Annual Report and
Form 20-F 2015
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bp.com/annualreport
Who we are
We aim to create long-term value for
shareholders by helping to meet growing
demand for energy in a safe and responsible
way. We strive to be a world-class operator,
a responsible corporate citizen and a
good employer.
Our proposition for value growth
For BP good business starts with a
relentless focus on safe and reliable
operations. Our portfolio enables us to
develop high-quality opportunities from
a broad set of options. We prioritize
value over volume and invest where
we can apply our distinctive strengths,
capabilities and technologies.
Our objective is to create shareholder
value by growing sustainable free
cash flow and distributions over the
long term through capital and cost
discipline.
BP is one of the world’s leading
integrated oil and gas companies –
based on market capitalization, proved
reserves and production. Through our
work we provide customers with fuel
for transportation, energy for heat and
light, lubricants to keep engines moving
and the petrochemicals products used
to make everyday items as diverse as
paints, clothes and packaging.
We believe a mix of fuels and
technologies is needed to meet
growing energy demand, improve
efficiency and support the transition to
a lower-carbon economy. These are the
reasons why our portfolio includes oil,
gas and renewables.
Our projects and operations help to
generate employment, investment
and tax revenues in countries and
communities across the world. We
have well-established operations in
Europe, North and South America,
Australasia, Asia and Africa and employ
around 80,000 people.
Front cover images
In Oman’s remote desert, we use our advanced
technology to unlock gas from hot sandstone
almost three miles below the earth’s surface.
Construction work has started on the Khazzan
field – one of the Middle East’s largest
unconventional gas resources – and we expect
first gas in late 2017.
Your feedback
We welcome your comments and feedback
on our reporting. You can provide this at
bp.com/annualreportfeedback or by emailing the
corporate reporting team – details are on the
back cover.
Your views are important to us and help shape
our reporting for future years.
BP Annual Report and Form 20-F 2015
BP in 2015
It is a challenging time for our
industry but we are making the
changes that are needed without
compromising our longer-term
goals.
Information about this report
1 Strategic report
BP at a glance
2
Chairman’s letter
6
Group chief executive’s letter
8
Our market outlook
10
Our business model and strategy
12
Lower oil and gas prices
18
Our key performance indicators
20
Strategy, performance and pay
22
Our markets in 2015
24
Group performance
26
55 Corporate governance
56
60
62
63
64
65
66
66
68
Board of directors
Executive team
Introduction from the chairman
The board in 2015
Board activity
Shareholder engagement
International advisory board
How the board works
Audit committee
28
34
38
40
41
43
51
53
71
73
74
74
75
76
93
Upstream
Downstream
Rosneft
Other businesses and corporate
Gulf of Mexico oil spill
Corporate responsibility
Our management of risk
Risk factors
Safety, ethics and environment
assurance committee
Gulf of Mexico committee
Geopolitical committee
Chairman’s committee
Nomination committee
Directors’ remuneration report
Directors’ statements
★ Glossary
Words with this symbol★ are defined
in the glossary on page 256.
95 Financial statements
96
Consolidated financial statements
of the BP group
107 Notes on financial statements
169
196
Supplementary information on oil and
natural gas (unaudited)
Parent company financial statements
of BP p.l.c.
215 Additional disclosures
216 Selected financial information
219 Liquidity and capital resources
221 Upstream analysis by region
225 Downstream plant capacity
227 Oil and gas disclosures for the group
233 Environmental expenditure
233 Regulation of the group’s business
237 Legal proceedings
242
243 Material contracts
International trade sanctions
243 Property, plant and equipment
243 Related-party transactions
244 Corporate governance practices
244 Code of ethics
244 Controls and procedures
245 Principal accountants’ fees and services
245 Directors’ report information
246
Disclosures required under Listing
Rule 9.8.4.R
246 Cautionary statement
247 Shareholder information
248 Share prices and listings
248 Dividends
249 UK foreign exchange controls on dividends
249 Shareholder taxation information
251 Major shareholders
251 Annual general meeting
251 Memorandum and Articles of Association
253
Purchases of equity securities by the
issuer and affiliated purchasers
259 Signatures
260 Cross reference to Form 20-F
254 Fees and charges payable by
254
ADSs holders
Fees and payments made by
the Depositary to the issuer
254 Documents on display
255 Shareholding administration
255 Exhibits
255 Abbreviations, glossary and trade marks
BP Annual Report and Form 20-F 2015
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Information about this report
Cautionary statement
This document should be read in
conjunction with the cautionary
statement on page 246.
Frequently used abbreviations, terms
and BP and third-party trade marks are
described on page 255.
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 2015. A cross reference to Form 20-F requirements
is included on page 260.
This document contains the Strategic report on pages 1-54 and the inside cover (Who we are) and
the Directors’ report on pages 55-75, 93-94, 169-195 and 215-258. 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 and Transparency Rules. The Directors’ remuneration report is on
pages 22-23 and 76-92. The consolidated financial statements of the group are on pages 95-168 and
the corresponding reports of the auditor are on pages 96-102. The parent company financial
statements of BP p.l.c. are on pages 196-213.
The Directors’ statements (comprising the Statement of directors’ responsibilities; Risk management
and internal control; Going concern; Longer-term viability; and Fair balanced and understandable), the
independent auditor’s report on the annual report and accounts to the members of BP p.l.c. and the
parent company financial statements of BP p.l.c. and corresponding auditor’s report 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 2015 and BP Strategic Report 2015 (comprising the Strategic report
and supplementary information) 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 2015 or BP Strategic
Report 2015 (comprising the Strategic report and supplementary information), forms any part of
those documents. 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. Unless otherwise stated, the text does not distinguish between the
activities and operations of the parent company and those of its subsidiaries★, and 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.
BP’s primary share listing is the London Stock Exchange. Ordinary shares are also traded on the
Frankfurt Stock Exchange in Germany and, in the US, the company’s securities are traded on the
New York Stock Exchange (NYSE) in the form of ADSs (see page 248 for more details).
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 BP 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.
★ Defined on page 256.
Registered office and our worldwide
headquarters:
Our agent in the US:
BP p.l.c.
1 St James’s Square
London SW1Y 4PD
UK
Tel +44 (0)20 7496 4000
BP America Inc.
501 Westlake Park Boulevard
Houston, Texas 77079
US
Tel +1 281 366 2000
Registered in England and Wales No. 102498.
London Stock Exchange symbol ‘BP.’
ii
BP Annual Report and Form 20-F 2015
Strategic
report
An overview of the key
activities, events and results
in 2015, together with
commentary on our
performance and priorities
as we move forward.
2 BP at a glance
6 Chairman’s letter
8 Group chief executive’s letter
10 Our market outlook
12 Our business model and strategy
18 Lower oil and gas prices
20 Our key performance indicators
22 Strategy, performance and pay
22 Annual statement by the remuneration committee chair
24 Our markets in 2015
26 Group performance
28 Upstream
34 Downstream
38 Rosneft
40 Other businesses and corporate
40 Renewable energy
41 Gulf of Mexico oil spill
43 Corporate responsibility
43 Safety
46 Environment and society
48 Business ethics and transparency
49 Employees
51 Our management of risk
53 Risk factors
1
BP Annual Report and Form 20-F 2015Strategic report
BP at a glance
BP delivers energy products
and services to people around
the world.
Through our two main operating segments,
Upstream and Downstream, we find, develop
and produce essential sources of energy,
turning them into products that people need.
We also buy and sell at each stage of the
hydrocarbon value chain. In renewable energy,
our activities are focused on biofuels and
onshore wind.
We also have a 19.75% shareholding in Rosneft,
that we report as a separate segment.
Business model
For more information on our business
model see page 12.
Our group key performance indicators (KPIs)
are shown on page 20. Some financial KPIs
are not recognized GAAP measures, but are
provided for investors because they are
closely tracked by management to evaluate
BP’s operating performance and to make
financial, strategic and operating decisions.
Group
BP p.l.c. is the parent company of
the BP group of companies. Our
worldwide headquarters is in London.
Finding
oil and gas
Developing and extracting
oil and gas
First, we acquire exploration rights,
then we search for hydrocarbons beneath
the earth’s surface.
Once we have found
hydrocarbons, we work to bring
them to the surface.
Upstream
Our Upstream segment manages exploration,
development and production activities.
See KPIs page 20.
See Upstream page 28.
$(6.5)bn
loss attributable to
BP shareholders
2014: $3.8bn profit
21.6%
gearing (net
debt ratio)★
2014: 16.7%
20
tier 1 process
safety events★
2014: 28
$5.9bn
underlying replacement
cost profit★
2014: $12.1bn
$19.1bn
operating cash
flow★
2014: $32.8bn
3.3
million barrels of oil
equivalent per daya
2014: 3.2mmboe/d
a See footnote a on page 15.
2
BP Annual Report and Form 20-F 2015
Upstream proved
reservesb (mmboe)
14
2
3
Liquids
1. Subsidiaries(cid:31)
2. Equity-accounted entities
Total
3,982
707
4,689
Natural gas
3. Subsidiaries
4. Equity-accounted entities
Total
5,269
425
5,694
$(0.9)bn
replacement cost loss
before interest and tax
2014: $8.9bn profit
2.3
million barrels of oil
equivalent per dayb
2014: 2.1mmboe/d
3
upstream major project★
start-ups
2014: 7 major projects
$1.2bn
underlying replacement cost profit
before interest and tax
2014: $15.2bn
8,000km2
new exploration access
2014: 47,000km2
b Excludes BP’s share of Rosneft.
See Rosneft on page 38.
Data provided on pages 2-5 is at or for the year
ended 31 December 2015, unless otherwise
indicated.
Transporting and trading
oil and gas
Manufacturing
fuels and products
Marketing
fuels and products
We move hydrocarbons using pipelines,
ships, trucks and trains and use our trading
capability to capture value across the
supply chain.
We refine, process and blend
hydrocarbons to make fuels, lubricants
and petrochemicals.
We supply our customers with fuel for
transportation, energy for heat and light,
lubricants to keep engines moving and the
petrochemicals required to make a variety
of everyday items.
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Fuels
Lubricants
Petrochemicals
International oil and
gas markets
Generating
renewable energy
We operate a biofuels business in Brazil and an
onshore wind business in the US.
Downstream Our Downstream segment operates
hydrocarbon value chains covering three
main businesses – fuels, lubricants and
petrochemicals.
Renewables
See Downstream page 34.
See Renewable energy page 40.
Operating capital
employed c
1
3
2
1. Fuels
2. Lubricants
3. Petrochemicals
$29.2bn
$1.3bn
$4.4bn
$7.5bn
795
underlying replacement cost
profit before interest and tax
2014: $4.4bn
million litres of ethanol equivalent
produced at our three mills in Brazil
2014: 542 million litres
4,424
gigawatt hours of electricity generated
at our 16 US wind farms
2014: 4,617GWh
$7.1bn
replacement cost profit
before interest and tax
2014: $3.7bn
1.7
14.8
million barrels of oil refined
per day
2014: 1.7mmb/d
million tonnes of petrochemicals
produced in the year
2014: 14.0mmte
42%
of our lubricants sales were
premium grades
2014: 41%
c See page 218.
★ Defined on page 256.
BP Annual Report and Form 20-F 2015
3
BP around the world
Gulf of Mexico
Fuels
Over the past decade, no oil and gas company
has invested more in its operations in the
deepwater Gulf than BP. We are a leading
acreage holder and producer of oil and natural
gas in the region. Our production comes
from more than 10 fields and includes four
BP-operated hubs.
Our fuels business is made up of regionally
based integrated fuels value chains, that
include refineries and fuels marketing
businesses, together with global oil supply
and trading activities. We supply fuel and
related convenience services to consumers
at around 17,200 retail sites under a BP brand
and market our products in more than 50
countries.
BP has operations in more
than 70 countries.
Countries where we have operations
or interests are shaded green.
Upstream
Primarily (>75%) liquids★.
Primarily (>75%) natural gas.
Liquids and natural gas.
Exploration site.
Locations are categorized as liquids or natural
gas based on 2015 production. Where
production is yet to commence, categorization is
based on proved reserves. Exploration sites have
no significant proved reserves or production as at
31 December 2015.
Upstream see page 28.
Downstream
Refinery.
Petrochemicals site(s).
Downstream see page 34.
Renewable energy
Operational assets.
Renewable energy see page 40.
BP group employees by region
16
5
4
3
1. Europe
2. US and Canada
3. Asia Pacific
4. South and Central
33,100
16,600
14,700
America
5. Middle East and
North Africa
6. Sub-Saharan
Africa
Total
7,200
5,900
2,300
79,800
2
Employee figures include 15,600 service station
staff and 4,800 agricultural, operational and
seasonal workers in Brazil.
Lower 48
Employees see page 49.
4
The US Lower 48 onshore business produces
natural gas, oil, condensate and NGLs from
conventional and unconventional sources
including gas, coalbed methane and shale gas
assets. It is one of the largest producers of
natural gas in the US, with a presence in seven
prolific gas basins in the country.
Renewable energy
BP has the largest operated renewables
business among our oil and gas peers. Our
participation in renewable energies is
focused on biofuels and onshore wind. Our
operations include three sugar cane mills in
Brazil and 16 wind farms in the US.
BP Annual Report and Form 20-F 2015
North Sea
Azerbaijan
Rosneft
BP has been operating in the North Sea for
many decades, where we remain a major player
thanks to our large asset base in the area. We
have two major projects under way in the UK:
Quad 204 and Clair Ridge. Our activities cover
the entire industry life cycle, from access and
exploration to production and decommissioning.
We are a significant investor in Azerbaijan, with
two major production-sharing agreements★★and
seven platforms in the country, as well as
interests in other exploration leases. The Caspian
Sea is one of the world’s major hydrocarbon
provinces, and development of the region’s
offshore oil and gas fields and onshore pipelines
has made Azerbaijan a focal point of the global
energy market.
Rosneft is Russia’s largest oil company
and the world’s largest publicly traded
oil company in terms of hydrocarbon
production. BP’s 19.75% share of Rosneft’s
proved reserves – on an SEC basis – is
5 billion barrels of oil and 11 trillion cubic
feet of gas. Rosneft’s downstream
operations include interests in 15 refineries.
Angola
Lubricants
Petrochemicals
We have interests in eight major deepwater
licences offshore, and operate four of these.
In 2015 19% of our total net oil production
worldwide (excluding Rosneft) came from
Angola.
We market lubricants and related products
and services in approximately 75 countries
through direct sales and/or locally approved
distributors. We leverage brand, technology
and relationships, focusing our resources on
core and growing markets. Our Castrol, BP
and Aral brands are recognized for innovation
and high performance.
We manufacture petrochemicals products
across 17 sites and sell them in more than 40
countries. Our proprietary technologies are
one of the business’s distinctive sources of
competitive advantage and support the
development of our licensing business.
★ Defined on page 256.
5
BP Annual Report and Form 20-F 2015Strategic report Chairman’s letter
We are prepared and well
positioned to respond to the
volatile environment as
we move through 2016.
Carl-Henric Svanberg
Dear fellow shareholder,
2015 has been another challenging year: oil prices have remained low, falling by more
than 50% and our industry finds itself in a position not seen for some 30 years. This
sustained low price is a result, not of lack of demand, but of oversupply. However, our
work in reconfiguring BP following the incident in the Gulf of Mexico has meant that we
were prepared and well positioned to respond to this volatile environment as we move
through 2016.
Shareholders and distributions
We have maintained our dividend during the year and remain committed to growing
sustainable free cash flow and shareholder distributions over the long term. I believe that
our current financial framework can support these commitments.
The board considers shareholder distributions in the context of how to achieve long-term
growth and value creation. In the current weaker price environment, our aim is to
rebalance our sources and uses of cash to ensure we cover capital expenditure and
shareholder distributions with operating cash flow.a This will enable BP to continue to
develop its business while maintaining safe and reliable operations. We anticipate that all
the actions we are taking will capture more deflation and drive the point of rebalance to
below $60 per barrel. The board will keep all of this under review and will make any
adjustments to our financial framework as circumstances require.
Strategy
The proposed consent decree with the United States federal government and settlements
with the US Gulf states are an important step. It has enabled us to look at the future with
greater confidence. However the current price environment continues to be a cause for
concern and so we have set a financial path for the next two years. This medium-term
strategy is based on optimizing our deployment and allocation of capital and the continuing
simplification of our business while maintaining our commitment to safety and reliability.
Our financial results over the year demonstrated the benefit from the integration of our
upstream and downstream activities. We have a strong, refocused and rebalanced portfolio
based on our distinctive capabilities which we believe will enable us to withstand lower
prices. In the future, we will continue to invest in a balanced range of resources and
geographies across the Upstream and Downstream to enable us to achieve long-term
growth.
We have recently published our BP Energy Outlook. I believe this makes an important
contribution to the discourse and debate in this area. As the world continues to develop
economically then oil, and increasingly gas, will be needed for the foreseeable future. This
is the core of our business. Overall we keep under review the broader strategic direction of
the group as the market for our products evolves and the energy landscape starts to
change.
2015 has seen increased focus on climate change. BP has consistently argued for a price
on carbon and recognized the part we all must play in being part of the solution. However
governments must take the lead in developing policies to reduce carbon emissions and we
continue to engage in this debate. The UN conference on climate change has produced
$7.3bn
dividends to BP shareholders
7.5%
ordinary shareholders annual dividend yield
7.7%
ADS shareholders annual dividend yield
6
BP Annual Report and Form 20-F 2015
Board performance
For information about the board and its
committees see page 55.
Remuneration
For information about our directors’
remuneration see page 76.
Top: The safety, ethics and environmental
assurance committee (SEEAC) examine safety
measures at our operations in the Khazzan field
in Oman.
Bottom: SEEAC members meeting crew on the
Cassia platform in Trinidad and Tobago where
they inspected the safety of operations.
some clear results and I am proud of the part that Bob has played in leading the initiative
within our industry. At our last AGM in April the board was pleased to support a resolution
brought by a group of our shareholders that encouraged greater disclosure of our work in
this area; our evolving response to this is set out in our Sustainability Report due for
publication this March.
Oversight
The world continues to be a troubled place and the risks faced by BP are ever evolving.
The board keeps under review its approach to the monitoring of risk – as demonstrated by
the board’s oversight of cybersecurity and the sharpened focus on geopolitical risk through
the formation of the geopolitical committee. This is complemented by the work of our
international advisory board. As we progress with our litigation in the US, we expect to
stand down the Gulf of Mexico committee during 2016 and I would like to thank my
colleagues for the important work and focus they have given to this committee over the
past five years. Oversight of the continuing litigation will fall to the full board.
Governance and succession
Membership of the board has continued to be refreshed and during the year Paula
Reynolds and Sir John Sawers joined us as non-executive directors. Paula brings deep
experience from the financial and energy worlds, while John brings long experience of
international politics and security that are so important to our business. Professor Dame
Ann Dowling has taken the chair of the remuneration committee in anticipation of Antony
Burgmans standing down from the board after twelve years. Antony has chaired the
remuneration committee and is also chairing the newly formed geopolitical committee
until April when Sir John Sawers will succeed him. Phuthuma Nhleko, who joined the
board in 2011, has decided not to offer himself for re-election at the forthcoming AGM due
to external business commitments. On behalf of the board I thank Antony and Phuthuma
for the substantial contribution that they have made to all of our work.
In 2015 Bob and his executive team have worked determinedly to steer the business
through some difficult times with some tough decisions. They have met every challenge
and as a result the business is in robust shape as we go into 2016. They deserve our
thanks as do all our employees. I would like to thank the board for all that they have done.
And I would like to thank our shareholders for your continued support. We are set to
continue supplying energy to help meet global demand while delivering value to you from
a great business.
Carl-Henric Svanberg
Chairman
4 March 2016
a See Our financial framework on page 19.
★ Defined on page 256.
7
BP Annual Report and Form 20-F 2015Strategic report
Group chief executive’s letter
By focusing on our distinctive
areas of strength, BP has
become an increasingly agile
business, able to respond
quickly to changing conditions.
Bob Dudley
Dear fellow shareholder,
In 2015 we continued to adapt to the tough environment created by the dramatic drop in oil
prices. We have seen prices crash before, but this fall has been particularly steep, from
over $100 a barrel in mid-2014 to below $30 by January 2016. The work we have done to
reshape and strengthen BP after 2010 stood us in good stead to withstand these
conditions and last year we took further action to make the business more resilient in the
short term. We also continue to invest for long-term growth. Our safety record improved,
along with operating reliability, while costs came down and capital discipline was
maintained. The current environment has however impacted our financial results, as well
as those of our competitors. So, while the oil price is beyond our control, we have
performed strongly on the factors that we can control.
A safer, more reliable, more resilient BP
In terms of safety, our top priority, we achieved improvements year-on-year in all of our key
safety measures – process safety events, leaks, spills and other releases, and recordable
injuries. This performance is at a much better level than five years ago and in line with the
best among our peers. Safety is also good business. When we operate safely, our
operations are more reliable. When the assets run reliably, they operate more continuously.
When our operations run efficiently, we have better financial results.
In the current business environment, competitiveness depends on minimizing our costs
and being disciplined in our use of limited capital – as demonstrated by our organic capital
expenditure in 2015 of $18.7 billion, down from nearly $23 billion in 2014. And we continue
to focus our portfolio on the highest quality projects and operations, divesting $10 billion
worth of assets in 2014 and 2015, in line with our target.
2015 was a challenging year for our Upstream business, with weaker oil and gas
realizations leading to a significantly lower underlying pre-tax replacement cost profit of
$1.2 billion. However, efficiency and reliability improved across the business in 2015.
Upstream unit production costs were down 20% on 2013, and BP-operated plant reliability
increased to 95% from 86% in 2011. We have made our base production more resilient by
improving our reservoir management and increasing efficiencies in our drilling and
operations – lowering the decline rate and reducing non-productive time in drilling to its
lowest level since 2011. And the decision to manage our US Lower 48 business separately
is starting to deliver improvements in performance and competitiveness.
Our Downstream business had a record year, delivering $7.5 billion of underlying pre-tax
replacement cost profit, demonstrating the benefit of being an integrated business. Our
refining business is ranked among the top performers based on net cash margin in the
most recent industry benchmark. We made improvements in safety, efficiency and
operational performance, and continued to develop a portfolio of highly competitive assets
and products. These include the launch in Spain of a new range of fuels with engine-
cleaning and fuel-economy benefits, the unveiling of Nexcel from Castrol – a technology
with the potential to revolutionize the oil changing process in vehicles, and the start-up of
Zhuhai 3 in China – one of the most efficient purified terephthalic acid production units in
the world.
94.7%
2015 refining availability
95%
Upstream BP-operated plant reliability
8
BP Annual Report and Form 20-F 2015 Strategy
For more information on our strategic
priorities and longer-term objectives
see pages 12-17.
Industry context
See how we are responding to
the lower price environment on
pages 18-19.
Top: Bob Dudley meets Russian deputy prime
minister for social affairs, Olga Golodets, at the
London Science Museum Cosmonauts exhibition.
Bottom: Bob Dudley speaks with Pemex CEO,
Emilio Lozoya Austin and Total CEO Patrick
Pouyanné at the OGCI event in Paris.
Our executive vice president for corporate business activities, Katrina Landis, decided to
step down after a very successful 24 years in BP. We have taken this opportunity to
simplify and better align responsibilities within the team, appointing Lamar McKay as
deputy chief executive, leading on key accountabilities such as strategy and safety, with
Bernard Looney succeeding Lamar as Upstream chief executive.
Building a platform for growth
The agreements we reached in July with US federal, state and the vast majority of local
government bodies will, subject to court approval, settle our largest remaining legal
exposures relating to the Deepwater Horizon accident and oil spill in 2010. This is a realistic
outcome that gives BP clarity to plan for the future.
To build that future, we are continuing to invest in a disciplined way in a portfolio that is
well balanced in several respects – geographically across regions, across our upstream and
downstream businesses and across resource types – conventional and unconventional oil
and gas, as well as the renewable energies of biofuels and wind. This gives us resilience
and flexibility now and in the future.
In the Upstream, in addition to a well-managed base of existing operations, we had three
major project start-ups in 2015 and we made final investment decisions on four projects,
including the West Nile Delta project in Egypt, where we are seeing some best-in-class
drilling performance. Looking ahead, we expect significant new production from projects
starting up between 2015 and 2020, including our mega projects at Shah Deniz 2 in
Azerbaijan and Khazzan in Oman, which will create value for decades. These projects are
on time and on budget.
In the Downstream, we continue to focus on resilient and improving performance and
growth from a quality portfolio of high-performing refineries, a competitive petrochemicals
business and growing fuels marketing and lubricants businesses.
In 2015 we furthered our relationship with Rosneft to that of a strategic partner, with
involvement in exploration, appraisal and production in some of the world’s most prolific oil
and gas provinces. In China, we have signed new agreements to supply liquefied natural
gas and to explore for shale gas. And we continue to build relationships in BP’s historic
heartlands of the Middle East, with growing opportunities in Oman, Kuwait, Egypt and Iraq.
Acting on climate change
We continue to support action to address the risk of climate change. Through the Oil and
Gas Climate Initiative – a business coalition that accounts for over a fifth of global oil and
gas production – we are sharing best practices and developing common approaches, such
as on the role of natural gas, the lowest-carbon fossil fuel and on energy efficiency. We
also joined with BG Group, Eni, Reliance, Repsol, Royal Dutch Shell, Statoil and Total to call
on the UN and governments to put a price on carbon so that businesses and consumers of
energy can better work within frameworks that are clear.
We welcome the direction provided by the historic agreement reached at the UN climate
conference in Paris. Governments, companies and consumers all have to make an
appropriate contribution and we will continue to play our part through means including
energy efficiency, renewable energy and increasing the share of natural gas in our portfolio.
Adapting for now and the future
Over the years BP has responded to changing circumstances many times. Each time we
have learned, adapted and evolved. This experience, gained over more than 100 years, is
one of our greatest assets. Today, we are well placed to weather the storm and navigate
through a testing environment to emerge in good shape for taking advantage of new
opportunities. I am confident that BP will be delivering energy for our customers and value
for our shareholders long into the future.
Bob Dudley
Group chief executive
4 March 2016
★ Defined on page 256.
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BP Annual Report and Form 20-F 2015Strategic report
Our market outlook
We believe that a diverse mix of fuels and technologies will
be essential to meet the growing demand for energy and
challenges facing our industry.
Near-term outlook
The global economy continues to experience
weaker growth in the main developing
economies and slower than expected recovery
in the developed world. World gross domestic
product (GDP) is expected to grow by 2.8% in
2016, led by the OECD, but with significant
downside risks from emerging economies,
particularly commodity exporters.
After around four years of averaging about $100
per barrel, oil prices fell by nearly 50% in 2015.
Even as US production growth stalled and global
oil demand rebounded, a large increase in OPEC
production continued to push inventories higher.
Price declines continued into early 2016, with
daily prices reaching levels not seen since 2004.
Prices are expected to remain low at least
through the near term. And while we anticipate
supply chain deflation in 2016 and beyond, as
industry costs follow oil prices with a lag, this
will be a tough period of intense change for the
industry as it adapts to this new reality.
Long-term outlook
The world economy is likely to more than double
from 2014 to 2035, largely driven by rising
incomes in the emerging economies and a
projected population increase of 1.5 billion.
We expect world demand for energy to increase
by as much as 34% between 2014 and 2035.
This is after taking into account improvements in
energy efficiency, a shift towards less energy-
intensive activities in fast-growing economies,
governmental policies that incentivize lower-
carbon activity, and national pledges made at the
2015 UN climate conference in Paris.
There are more than enough energy resources
to meet this growing demand, but there are a
number of challenges.
Affordability
Fossil fuels are currently cheaper than
renewables but their future costs are hard to
predict. Some fossil fuels may become more
costly as the difficulty to access and process
them increases; others may be more affordable
with technological progress, as seen with US
shale gas. While many renewables remain
expensive, innovation and wider deployment are
likely to bring down their costs.
Supply security
Energy resources are often distant from the
hubs of energy consumption and in places
facing political uncertainties. More than half of
the world’s known oil and natural gas reserves
are located in just eight countries.
Sustainability
Fossil fuels – though plentiful and currently more
affordable than other energy resources – emit
carbon dioxide (CO2) and other greenhouse
gases (GHG) through their production and use in
homes, industry and vehicles. Renewables are
lower carbon but can have other environmental
or social impacts, such as high water
consumption or visual intrusion.
Effective policy
BP believes that carbon pricing is the most
comprehensive and economically efficient policy
to limit GHG emissions. Putting a price on
carbon – one that treats all carbon equally,
whether it comes out of a smokestack or a car
exhaust – would make energy efficiency more
attractive and lower-carbon energy sources,
such as natural gas and renewables, more cost
competitive. A carbon price incentivizes both
energy producers and consumers to reduce their
GHG emissions. Governments can put a price
on carbon via a well-constructed carbon tax or
cap-and-trade system.
For further detail on our projections of future
energy trends contained in this section,
please refer to BP Energy Outlook.
Our markets in 2015
See page 24 for information on oil and gas
prices in 2015.
Global energy consumption by region
(billion tonnes of oil equivalent)
Other
Other Asia
China
OECD
18
16
14
12
10
8
6
4
2
1965
2000
2035
Source: BP Energy Outlook.
10
BP Annual Report and Form 20-F 2015
BP Technology Outlook
Technology choices for a secure, affordable
and sustainable energy future
November 2015
The BP Technology Outlook shows how
technology can play a major role in meeting the
energy challenge by widening energy resource
choices, transforming the power sector,
improving transport efficiency and helping to
address climate concerns out to 2050.
See bp.com/technologyoutlook
BP Energy Outlook provides our projections of
future energy trends and factors that could affect
them out to 2035, based on our views of likely
economic and population growth and
developments in policy and technology. Also
available in Excel and video format.
See bp.com/energyoutlook
Our strategy
Find out how BP can help meet energy
demand for years to come on page 12.
Climate change
Our sector has an important part to play
in addressing climate change. See page
46 to find out what BP is doing.
Energy consumption
(billion tonnes of oil equivalent)
Today around 32% of energy consumed
comes from oil, 30% from coal, and 24%
from gas – so 86% from fossil fuels in total.
Hydroelectricity accounts for 7%, nuclear for
4% and other renewables for just 3%.
Oil
Gas
Coal
Renewables
Hydro
Nuclear
Source: BP Energy Outlook.
S
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r
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p
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Energy efficiency
Greater efficiency helps with affordability –
because less energy is needed; with security –
because it reduces dependence on imports; and
with sustainability – because it reduces
emissions. Innovation can play a key role in
improving technology, bringing down cost and
increasing efficiency. In transport, for example,
we believe energy-efficient technologies and
biofuels could offer the most cost-effective
pathway to a secure, lower-carbon future.
All sorts of energy required
We believe a diverse mix of fuels and
technologies is needed to meet growing energy
demand, while supporting the transition to a
lower-carbon economy. These are reasons why
our portfolio includes oil, gas and renewables.
Oil and natural gas
Over the next few decades, we think oil and
natural gas are likely to continue to play a
significant part in meeting demand for energy.
They currently account for around 56% of total
energy consumption, and we believe they will
decrease to about 54% in 2035. For comparison,
under the International Energy Agency’s most
ambitious climate policy scenario (the 450
scenarioa), oil and gas would still make up 50%
of the energy mix in 2030 and 44% in 2040 –
assuming carbon capture and storage is widely
deployed.
Oil is a good source of energy for transportation
as it has a high energy density. That means
vehicles go further on less weight and volume
of fuel than alternatives. Also, oil’s liquid form
makes it easy to move around, globally and
locally. For these reasons, we expect oil to still
account for almost 90% of transportation fuels
in 2035 – compared with 94% today.
Natural gas is likely to play an increasing role in
meeting global energy demand, because it’s
available at scale, relatively low cost and lower
carbon than other fossil fuels. By 2035 gas is
expected to provide 26% of global energy,
placing it on a par with oil and coal.
a From World Energy Outlook 2015. © OECD/International
Energy Agency 2015, page 35. The IEA 450 scenario assumes
a set of policies that bring about a trajectory of greenhouse gas
emissions from the energy sector that is consistent with
limiting long-term average global temperature increase to 2°C.
We believe shale gas will contribute more than
half of the growth in natural gas globally
between 2014 and 2035. In the US, the growth
of shale gas has already had a significant impact
on gas demand as well as CO2 emissions, which
have fallen back to 1990s levels.
The increasing gas supply in the US and other
countries is encouraging the use of liquefied
natural gas worldwide, which is expected to
double between 2014 and 2035.
New sources of hydrocarbons may be more
difficult to reach, extract and process. BP and
others in our industry are working to improve
techniques for maximizing recovery from
existing and currently inaccessible or
undeveloped fields.
Renewables
Renewables are the fastest-growing energy
source. Over the past few years, there has been
rapid expansion of the use of solar power due to
cost reduction in manufacturing and public
subsidies. That said, renewables, excluding
large-scale hydroelectricity, currently account for
around 3% of energy consumption. While they
are starting from a low base, we estimate that
by 2035 they will contribute around 9% of total
global energy demand.
Temporary policy support is needed to help
commercialize lower-carbon options and
technologies, but they will ultimately need to
become commercially self-sustaining, supported
only by a carbon price.
Beyond 2035
We expect that growing population and per
capita incomes will continue to drive growing
demand for energy. These dynamics will be
shaped by future technology developments,
changes in tastes, and future policy choices –
all of which are inherently uncertain. Concerns
about energy security, affordability and
environmental impacts are all likely to be
important considerations. These factors may
accelerate the trend towards more diverse
sources of energy supply, a lower average
carbon footprint, increased efficiency and
demand management.
2035
2015
1995
0
3
6
9
12
15
18
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BP Annual Report and Form 20-F 2015Strategic report
Our business model and strategy
We aim to create value for our investors and benefits for
the communities and societies where we operate.
The new semi-submersible Deepsea Aberdeen
drilling vessel carries out ultra-deepwater drilling
in the UK North Sea.
An officer working in the under-deck pipe
passageway on board BP’s LNG tanker
British Trader.
Illustrated business model
For an at a glance overview of our
business model see page 2.
Our businesses
For more information on our
upstream and downstream business
models, see pages 28 and 34
respectively.
Our business model
We believe the best way to achieve
sustainable success as a group is to act in the
long-term interests of our shareholders, our
partners and society. By supplying energy, we
support economic development and help to
improve quality of life for millions of people.
Our activities also generate jobs, investment,
infrastructure and revenues for governments
and local communities.
Our business model spans everything from
exploration to marketing. We have a diverse
integrated portfolio that is balanced across
resource types, geographies and businesses,
and adaptable to prevailing conditions. Our
geographic diversity gives us access to
growing markets and new resources and
provides robustness to geopolitical events.
By having upstream and downstream
businesses and well established trading
capabilities, we have a cushion to oil price
volatility as downward pressures in one part of
the group can create opportunities in another.
Integration also allows us to share functional
excellence more efficiently across areas such
as safety and operational risk, environmental
and social practices, procurement, technology
and treasury management.
Every stage of the hydrocarbon value chain
offers opportunities for us to create value,
through both the successful execution of
activities that are core to our industry, and the
application of our own distinctive strengths
and capabilities in performing those activities.
What we do differently
Our partnerships in Russia
Global energy trading
We apply our capabilities of advanced
technology, strong relationships and
proven expertise across our operations
to help us deliver against our strategic
priorities in ways that we believe set us
apart from our peers. These examples
reflect our distinctive ways of working
across the business.
BP has been collaborating with leading
Russian oil and gas companies for 25 years,
creating a successful presence in a country
with some of the largest oil and gas reserves
and greatest potential worldwide. Through our
partnership with Rosneft, the world’s largest
listed oil company in terms of production
volume, we are able to build on the experience
and success we have achieved over the past
quarter century and continue to grow BP’s
business in Russia.
Using our knowledge and insights to help keep
the world’s energy moving, our energy trading
function is BP’s face to global energy markets
and an integral part of our upstream and
downstream operations. We offer a combination
of expertise in physical supply and trading,
innovative financial structures and advanced
analytics to deliver long-term value, from
wellhead to end customer. We trade a variety
of physical products such as crude oil, refined
products, natural gas, LNG and power, and aim
to maximize value from our assets by managing
the flow of these commodities.
See page 16 for details of
our distinctive capabilities.
12
BP Annual Report and Form 20-F 2015
Industry context
See how we are responding to the
lower price environment on pages
18-19.
Our key performance indicators
See how we measure our progress
on page 20.
Risks
Find out how we manage the risks to
our strategy on page 51.
A relentless focus on safety remains the
top priority for everyone at BP. Rigorous
management of risk helps to protect the
people at the front line, the places where we
operate and the value we create. We
understand that operating in politically
complex regions and technically demanding
geographies requires particular sensitivity to
local environments.
Our strategy
We prioritize value over volume by actively
managing a high-value upstream and
downstream portfolio and investing where
we can apply the distinctive strengths,
capabilities and technologies we have built
up over decades.
We aim to create shareholder value by
growing sustainable free cash flow and
distributions over the long term.
We are pursuing our strategy by setting clear
priorities, actively managing a quality portfolio
and employing our distinctive capabilities.
Clear priorities
First, we aim to run safe, reliable and
compliant operations – leading to better
operational efficiency and safety performance.
We target competitive project execution to
deliver projects as efficiently as possible.
Making disciplined financial choices focused
on capital and cost discipline allows us to
maximize free cash flow and increase the
resilience of our portfolio to changing price
environments.
Quality portfolio
We undertake active portfolio management
to concentrate on areas where we can play
to our strengths. We focus on high-value
upstream assets in deep water, giant
fields, selected gas value chains and
unconventionals★. And, in our downstream
businesses, we plan to leverage our upgraded
assets, customer relationships, brand and
technology to continue to grow free
cash flow.
Our portfolio of projects and operations is
focused where we believe we can generate
the most value, using our commercial agility
and technical capability. This allows us to
build a strong pipeline of future growth.
Distinctive capabilities
Our ability to deliver against our priorities
and build the right portfolio depends on our
distinctive capabilities. We apply advanced
technology across the hydrocarbon value
chain, from finding resources to developing
energy-efficient and high-performance
products for customers. We work to develop
and maintain strong relationships – with
governments, partners, civil society and others
– to enhance our operations in more than 70
countries across the globe. And the proven
expertise of our employees comes to the fore
in a wide range of disciplines.
Innovative customer offers
Collaborative partnerships
Pioneering commercial arrangements
We provide our customers with a broad range
of premium products, tailored to meet their
needs. Our Castrol brand has a long history
of product innovation and industry firsts, such
as our recently launched Nexcel oil-change
technology. In retail, our combination of quality
brands creates a highly differentiated offer. For
example, in the UK this includes our partnership
with Marks & Spencer, a market-leading loyalty
programme with Nectar, the Wild Bean Café
and Apple Pay®.
We have considerable experience of managing
the complexities of large projects with multiple
parties. For example, BP is leading the Shah
Deniz Stage 2 and Southern Corridor projects,
in partnership with 10 other national and
international oil companies, to construct one of
the world’s longest pipelines from Azerbaijan to
Italy. Our history of working with governments,
international agencies, communities and
partners has proved invaluable in establishing
the route between the landlocked Caspian Sea
and the Mediterranean.
We find innovative and mutually beneficial ways
of working. The Rumaila oil field in Iraq is one of
the world’s largest by production, although this
had fallen after years of conflict and under-
investment. In 2009 BP and China National
Petroleum Corporation committed to work
with Iraq’s South Oil Company to modernize
operations and increase production. BP
recovers costs, irrespective of oil price, and a
fee per barrel of incremental production above a
defined threshold.
★ Defined on page 256.
13
BP Annual Report and Form 20-F 2015Strategic report
Our strategy in action
Delivering energy
to the world
Safe, reliable and
compliant operations
Clear priorities
Competitive
project
execution
Disciplined
financial
choices
Source
future
growth
Focus on
high-value
upstream assets
Quality portfolio
Build high-quality
downstream businesses
Safe, reliable and
compliant operations
Disciplined financial
choices
Competitive project
execution
Source future
growth
Focus on high-value
upstream assets
Build high-quality
downstream
businesses
Advanced
technology
How we measure
For definitions of how we measure
our performance, see Our key
performance indicators on page 20.
Distinctive capabilities
Proven
expertise
Strong
relationships
Our ability to deliver
against our priorities and
build the right portfolio
depends on our distinctive
capabilities.
14
BP Annual Report and Form 20-F 2015
S
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p
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How we deliver
How we measure
Strategy in action in 2015
We prioritize the safety and reliability of our
operations to protect the welfare of our
workforce, local communities and the
environment, and to improve the efficiency of
our operations. This also helps preserve value
and secure our right to operate around the world.
Recordable injury
frequency, loss of primary
containment, greenhouse
gas emissions, tier 1
process safety events.
We rigorously screen our investments and we work
to keep our annual capital expenditure within a set
range. Ongoing management of our portfolio helps
ensure focus on more value-driven propositions.
We balance funds between shareholder
distributions and investment for the future.
Operating cash flow,
gearing, total shareholder
return, underlying
replacement cost profit
per ordinary share.
We seek efficient ways to deliver projects on
time and on budget, from planning through to
day-to-day operations. Our wide-ranging project
experience makes us a valued partner and
enhances our ability to compete.
Major project delivery.
We target opportunities with the greatest
potential to increase value, using our commercial
agility and technical capability. This allows us to
build a strong pipeline for future growth.
Proved reserves
replacement ratio.
We are strengthening our portfolio of high-return
and longer-life assets – across deep water, giant
fields, gas value chains and unconventionals – to
provide BP with momentum for years to come.
Production.
We benefit from our high-performing fuels,
lubricants, petrochemicals and biofuels
businesses. Through premium products,
powerful brands and supply and trading,
Downstream provides strong cash generation
for the group.
Refining availability.
Creating shareholder value by generating
sustainable free cash flow over the long term
Improving reliability
Improvement plans are
increasing UK North Sea
plant reliability.
See page 44.
20
tier 1 process
safety events
2014: 28
Capturing value
Improving the quality of
future investments.
See page 30.
$19.1bn
operating cash flow
2014: $32.8bn
Adapting rapidly
Using local knowledge to
increase our competitiveness.
See page 29.
3
major project start-ups
in Upstream
2014: 7
Unlocking energy potential
Investing in exploration and
development in Egypt.
See page 33.
61%
reserves
replacement ratioa
2014: 63%
Optimizing our assets
Using our technical expertise
to maintain a secure and
reliable supply.
See page 31.
3.3
million barrels of oil
equivalent per daya
2014: 3.2 million
Improving operations
Improvements at Castellón
refinery are helping to
increase profitability.
See page 36.
94.7%
refining availability
2014: 94.9%
Advanced technology
We develop and deploy technologies we
expect to make the greatest impact on our
businesses – from enhancing the safety and
reliability of our operations to creating
competitive advantage in energy discovery,
recovery, efficiency and products.
Strong relationships
We aim to form enduring partnerships in the
countries in which we operate, building strong
relationships with governments, customers,
partners, suppliers and communities to create
mutual advantage. Co-operation helps unlock
resources found in challenging locations and
transforms them into products for our
customers.
Proven expertise
Our talented people help to drive our business
forward. They apply their diverse skills and
expertise to deliver complex projects across
all areas of our business.
★ Defined on page 256.
15
a On a combined basis of subsidiaries and equity-accounted entities.
BP Annual Report and Form 20-F 2015Strategic report
Our distinctive capabilities
Advanced technology
We select and develop the technologies that can
best help us manage risk and grow value for our
businesses. Our first priority is to enhance the
safety and reliability of our operations. Beyond
that we aim to build and maintain leadership
positions in selected technologies.
Our upstream technology programmes include
advanced seismic imaging to help us find more
oil and gas, and enhanced oil recovery to get
more from existing fields. New techniques are
improving the efficiency of unconventional
oil and gas production. Our downstream
technology programmes are designed to
improve the performance of our refineries
and petrochemicals plants and create high-
quality, energy-efficient products.
High-speed graphics workstations in our Sunbury
office use state-of-the-art software and projection
equipment to create a 3D virtual world.
We employ scientists and technologists at
seven major technology centres in the US,
UK and Germany. BP and its subsidiaries hold
more than 4,500 granted patents and pending
patent applications throughout the world. In
2015 we invested $418 million in research
and development (2014: $663 million, 2013
$707 million).
We partner with universities for research,
recruitment, policy insights and education.
Our long-term research programmes around
the world are exploring areas from reservoir fluid
flow to novel lubricant additives and lower-
carbon energy sources. For example research
at the BP International Centre for Advanced
Materials has led to its first patent application on
a strong steel alloy that resists becoming brittle
and is less likely to crack. This has the potential
to enhance the reliability of our equipment.
See bp.com/technology
1
3
2
4
1 2 Seismic imaging
Our Independent Simultaneous Source (ISS)
technology makes large-scale 3D seismic
surveys faster and reduces cost by using
multiple surveying sources and receivers at
the same time. Our 2015 ISS survey at
Prudhoe Bay in Alaska delivered a 10-fold
increase in productivity, meaning we could
acquire higher-quality images in just one
winter season.
3 Production optimization
We began to deploy a new automated well
choke control system as part of our Field of the
Future technology suite in Azerbaijan in 2015.
Sand can cause wells to fail, but this system is
helping us manage well start-up and unsteady
flow during operations, contributing to improved
operational efficiency and production rates.
Proven expertise
We aim to maintain a skilled workforce to deliver
our strategy and meet our commitments to
investors, partners and the wider world. We
compete for the best people within the energy
sector and other industries.
Our people are talented in a wide range of disciplines
– from geoscience, mechanical engineering and
research technology to government affairs, trading,
marketing, legal and others.
We have a bias towards building capability and
promoting from within the organization and
complement this with selective external recruitment.
We invest in our employees’ development to build
enduring capability for the future.
Our approach to professional development and
training helps build individual capabilities. We
believe our shared values help everyone at BP to
contribute to their full potential.
16
BP Annual Report and Form 20-F 2015
Graduate intake
Our global graduate and
postgraduate programmes
recruited 298 people in 2015.
Internal promotion
We promoted 4,729
employees including
476 to senior level and
group leader roles.
Group leaders
Our group leaders have
an average of 21 years’
experience in BP.
External hires
We hired 5,303 people
including 53 to senior level
and group leader roles.
Developing the talent pipeline
Employees
For more information about our
people see page 49.
6
5
6
7
88
9
4 Enhanced oil recovery (EOR)
Bright Water technology, invented by BP, helps
to maximize oil production by recovering and
moving more oil to our wells. We use it in more
than 140 wells worldwide to date. It costs less
than $5 to recover each additional barrel of oil
released through Bright Water, and we deliver
more light oil EOR production than any other
international oil company.
6 Lubricants
Castrol’s new technology, the Nexcel oil cell,
is an easy-to-change unit containing both
engine oil and filter. We believe the technology
is a significant oil change innovation for the
automotive industry. It is designed to lower CO2
emissions, improve vehicle servicing and
increase the recycling of used oil for cars of
the future.
8 Petrochemicals
BP is one of the world’s largest producers of
purified terephthalic acid (PTA), a raw material
for many consumer products. In 2015 we
entered into licensing agreements in Oman and
China, for plants that will use our latest
generation PTA technology, with a combined
capacity to produce more than two million
tonnes of PTA each year.
5 Corrosion prevention
We use automated phased array ultrasonic
testing (PAUT) across our refineries to safely
inspect our tanks and pipelines. Our PAUT
technology uses ultrasonic pulses to examine
the integrity of these assets and detect cracks
in a non-destructive way. The technique reduces
facility downtime, decreases turnaround costs
and risks, and avoids production losses.
7 Fuels
BP began marketing a range of ‘dirt-busting’
fuels with a launch in Spain in 2015. The fuels
contain our new ACTIVE technology that cleans
and protects car engines with proprietary
additives. Our fuels are designed to remove
deposits and prevent their formation – helping
engines perform in the way they were designed
to do.
9 Biofuels
We are developing biobutanol in conjunction
with DuPont. This second-generation biofuel can
be blended into gasoline in greater proportions
and is more compatible than ethanol with the
infrastructure used for existing fuel supplies.
Internally we put together collaborative teams of
people with the skills and experience needed to
address complex issues, work effectively with
our partners, engage with our stakeholders
and help create shared value.
Strong relationships
We work closely with governments, national oil
companies, other resource holders and local
communities to build long-lasting relationships
that are crucial to the success of our business.
We place enormous importance on acting
responsibly and meeting our obligations as we
know from experience that trust can be lost. We
work on big and complex projects with partners
ranging from other oil companies to suppliers
and contractors. Our activity creates value that
benefits governments, shareholders, customers,
local communities and other partners.
We believe good communication and open
dialogue are vital if we are to meet their
expectations.
Universities
and research
institutions
National
and international
oil companies
Banks and
providers of
finance
Intern
l r e lation
s
a
h
i
p
s
Governments
and
regulators
BP
Industry
bodies
Customers
Communities
Suppliers,
partners and
contractors
BP Annual Report and Form 20-F 2015
17
Strategic report
Lower oil and gas prices
We are taking action to adapt to a lower oil and gas
price environment – while maintaining longer-term
growth prospects.
Since 2010, we have been working to create a
stronger, simpler and more focused business.
This has positioned us well to respond to the
lower oil and gas price environment. We are
reducing capital expenditure by paring back and
rephasing activities as necessary, as well as
capturing the benefits of deflation of industry
costs. We are driving down cash costs★ through
a reduction in third-party costs, and through
efficiency and simplification across the
organization. As always, safe and reliable
operations are our first priority.
Remodelling Mad Dog Phase 2 reduced our
project cost estimate by more than half.
Brent dated average crude oil prices
($/barrel)
2013
$108.66
2014
$98.95
2015
$52.39
For the year ended 31 December 2015.
Sources
Operating cash flow − rest of group
Disposal proceeds − investing activities
Uses
Capital investment − investing activities
Dividends paid
Operating cash flow − Gulf of Mexico oil spill
Industry context
Between 2010 to mid-2014 oil prices were relatively
stable, averaging around $100 per barrel. In 2014, strong
supply growth, largely as a result of growth in US shale,
caused oil prices to fall sharply. Prices fell further in 2015
as OPEC production increased and supply continued to
outstrip demand. There are, however, increasing signs
that the market is adjusting to the current low level of
prices, with strong demand growth and weakening
supply. The high level of inventories suggests that this
adjustment process is likely to take some time, but it
does appear to be underway. This underpins our belief
that prices will stay lower for longer, but not forever.
Gas prices also fell, albeit on a more regional and less
dramatic scale. In markets such as the US, gas prices
are at historically low levels, with increases in
production from shale being a key factor.
Low prices are having a significant effect on our
industry, including BP. With falling revenues,
companies need to re-base costs and activity – a
process that could take several years. We expect
2016 to be a period of intense change, with ongoing
restructuring and further deflation in the supply
chain. That said, periods of low prices are not
uncommon in our industry and BP has gone through
such cycles in the past.
For BP, the lower prices significantly impacted our
2015 financial results. The result for the year was
a loss of $6.5 billion. Underlying replacement
cost profit★ was $5.9 billion (2014 $12.1 billion)
and operating cash flow★ was $19.1 billion
(2014 $32.8 billion).
Sources and uses of cash
($ billion)
The cash flow from our Upstream operations
was significantly lower than in 2014 although
Downstream cash flows were strong. We
significantly reduced the capital expenditure of
the group as well as received proceeds from
divestments. The strength of our balance sheet
helped us meet the balance of outgoings.
30
25
20
15
10
5
How we are resilient
$
Sources
Uses
Integrated business
We benefit from having both upstream and
downstream businesses, as well as a well-
established oil and gas trading function that can
generate value for the group when prices are
volatile. A weak environment in one part of the
group can create opportunities in another. For
example, we delivered record profits in our
Downstream business in 2015.
Balanced portfolio
The geographical diversity and mix of resource
types in our portfolio can provide us with resilience
to a wide range of operating conditions and
opportunities for growth. In Upstream we operate
in countries with different commercial frameworks.
We have a significant part of our portfolio in
production-sharing agreements, where revenues
are typically less sensitive to oil price fluctuations.
Balance sheet flexibility
We maintain a strong balance sheet with
sufficient cash reserves, which helps to withstand
price falls and other events. We began 2015 with
significant cash reserves due to strong operating
cash flow in 2014 and the two divestment
programmes made since the Gulf of Mexico oil
spill. Most of these sales were made in the higher
oil price environment.
18
BP Annual Report and Form 20-F 2015
Our financial framework
Our financial framework is designed
to re-establish a balance where
operating cash flow (excluding
payments related to the Gulf of
Mexico oil spill) covers organic
capital expenditure★ and the current
level of dividend per share by 2017,
based on an average Brent★ price of
around $60 per barrel.
If prices remain lower for longer
than anticipated, we expect to
continue to recalibrate for the
weaker environment and to capture
more deflation. We would expect
this to drop the balance point below
$60 per barrel.
We will keep our financial framework
under review as we monitor oil
and gas prices and their impact on
industry costs as we move through
2016 and beyond.
Our financial framework – through 2017
Underpinning our commitment to sustain the dividend for our shareholders
Principle
2015 achievement
Looking ahead
Optimize capital
expenditure
2015 organic capital expenditure
was $18.7 billion.
This is 18% down from the
2011-2014 period average.
Reduce cash
costs
We made significant progress in
reducing cash costs compared with
2014.
Make selective
divestments
We completed the $10-billion
divestment programme
announced for 2014-2015.
Maintain flexibility
around gearing
Gearing★ at the end of 2015 was
21.6% against a 2011-2014
average of 18%.
We expect capital expenditure
of $17-19 billion per year in 2016
and 2017 as a result of reducing
costs and activity, with 2016
spend towards the lower end
of this range.
We anticipate the reduction in
our cash costs to be close to
$7 billion versus 2014 by the
end of 2017.
We expect divestments of
$3-5 billion in 2016 and $2-3 billion
per year from 2017 to help manage
oil price volatility and fund the
ongoing Gulf of Mexico
commitments.
Looking ahead, we aim to
manage gearing with some
flexibility at around 20%. While
oil prices remain weak, we
expect gearing to be above 20%.
How we are putting this into action
Upstream
Downstream
We are focusing on the timing of investments
to capture deflation in the supply chain, paring
back access and exploration spend and
prioritizing activity in our base operations.
Where we are not the operator, we are
influencing partners to focus on third-party
costs.
We reduced unit production costs by more
than 20% compared with 2013 and achieved
an average reduction of 15% in upstream
third-party costs in 2015. By the end of 2016,
we expect to re-bid 40% of our third-party
spend, including a significant proportion of our
well services contracts.
Our total upstream workforce – including
employees and contractors – is now 20%
smaller than it was in 2013, with a reduction of
around 4,000 expected in 2016. We are aiming
for an upstream workforce of approximately
20,000 by the end of 2016.
★ Defined on page 256.
In 2015 we reorganized our fuels business
from nine regions to three, streamlined the
lubricants business and started restructuring
petrochemicals. We are implementing
site-by-site improvement programmes to drive
manufacturing efficiency in refining and
petrochemicals. Our focus on third-party
spend has resulted in significant cost
reductions and we have reduced head office
related costs by around 40%.
These simplification and efficiency actions
have significantly contributed to the group’s
cash cost reductions in 2015.
We expect to reduce our downstream
workforce roles by more than 5,000 by the
end of 2017 compared with 2014, and by the
end of 2015 had already achieved a reduction
of more than 2,000.
Other businesses and corporate
We made significant progress in reducing
corporate and functional costs in 2015. We are
focusing on third-party spend and headcount
both in response to the lower oil price and also
to reflect the changes to our portfolio.
BP group employees (at 31 December)
70,000
65,000
60,000
55,000
65,500
64,800
59,400
2013
2014
2015
Figures exclude retail staff and agricultural, operational and
seasonal workers in Brazil.
19
BP Annual Report and Form 20-F 2015Strategic report Our key performance indicators
We assess our performance across
a wide range of measures and
indicators. Our key performance
indicators (KPIs) help the board and
executive management measure
performance against our strategic
priorities and business plans. We
periodically review our metrics and
test their relevance to our strategy.
We believe non-financial measures
– such as safety and an engaged
and diverse workforce – have a
useful role to play as leading
indicators of future performance.
Remuneration
To help align the focus of our board
and executive management with
the interests of our shareholders,
certain measures are reflected in
the variable elements of executive
remuneration.
Overall annual bonuses, deferred
bonuses and performance shares
are all based on performance
against measures and targets linked
directly to strategy and KPIs.
Directors’ remuneration
See how our performance
impacted 2015 pay on
page 76.
Underlying RC profit
per ordinary share (cents)
Operating cash flow ($ billion)
Gearing (net debt ratio)
(%)
89.70
70.92
66.00
125
111.97
100
75
50
25
50
40
30
20
10
32.22
32.8
22.2
20.5
21.1
19.1
25
20
15
10
5
20.4
18.7
16.2
16.7
21.6
2011
2012
2013
2014
2015
2011
2012
2013
2014
2015
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.
2015 performance Operating cash flow
was lower in 2015, largely reflecting the
impact of the lower oil price environment.
2015
2011
2013
2014
2012
Our gearing (net debt ratio) shows
investors how significant net debt is
relative to equity from shareholders in
funding BP’s operations.
We aim to keep our gearing around 20%
to give us the flexibility to deal with an
uncertain environment.
Gearing is calculated by dividing net
debt by total equity plus net debt. Net
debt is equal to gross finance debt,
plus associated derivative financial
instruments, less cash and cash
equivalents. For the nearest equivalent
measure on an IFRS basis and for further
information see Financial statements –
Note 26.
2015 performance Gearing at the end of
2015 was 21.6%, up 4.9% on 2014.
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 . The IFRS equivalent
can be found on page 216.
2015 performance The significant
reduction in underlying RC profit per
ordinary share for the year compared with
2014 was mainly due to lower profit in
Upstream.
Refining availability (%)
Reported recordable injury
frequencya
Loss of primary containmenta
Workforce
Employees
Contractors
98
96
94
92
90
94.8
94.8
95.3
94.9
94.7
1.00
0.80
0.60
0.40
0.20
3
4
.
0
1
4
.
0
5
3
.
0
6
3
.
0
1
3
.
0
6
2
.
0
1
3
.
0
6
3
.
5 0
2
.
0
4
3
.
0
1
3
.
0
7
2
.
0
8
2
.
0
4
2
.
0
0
2
.
0
2011
2012
2013
2014
2015
2011
2012
2013
2014
2015
Key
KPIs used to measure
progress against our strategy.
KPIs used to determine 2015
and 2016 remuneration.
Underlying RC profit and gearing
are non-GAAP measures, but
are provided for investors
because they are closely tracked
by management to evaluate
BP’s operating performance and
to make financial, strategic and
operating decisions.
20
Refining availability represents Solomon
Associates’ operational availability.
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.
2015 performance Refining availability
was similar to 2014.
Reported recordable injury frequency
(RIF) measures the number of reported
work-related employee and contractor
incidents that result in a fatality or injury
(apart from minor first aid cases) per
200,000 hours worked.
Loss of primary containment (LOPC)
is the number of unplanned or
uncontrolled releases of oil, gas or other
hazardous materials from a tank, vessel,
pipe, railcar or other equipment used for
containment or transfer.
The measure gives an indication of the
personal safety of our workforce.
2015 performance Our workforce
RIF, which includes employees and
contractors combined, was 0.24. This
improvement on 2014 was also reflected
in our other occupational safety metrics.
While this is encouraging, continued
vigilance is needed.
By tracking these losses we can
monitor the safety and efficiency of our
operations as well as our progress in
making improvements.
2015 performance We have seen a
decrease in our loss of primary
containment to 235. Figures for 2014
and 2015 include increased reporting
due to the introduction of enhanced
automated monitoring for remote sites
in our US Lower 48 business. Using a
like-for-like approach with prior years’
reporting, our 2015 loss of primary
containment figure is 208 (2014 246).
20112012201320142015500400300200100361261286235292BP Annual Report and Form 20-F 2015
Total shareholder return (%)
Reserves replacement ratio (%)
Major project delivery
Production (mboe/d)
ADS basis
Ordinary share basis
60
40
20
0
-20
5
.
2
0
.
3
5
.
4
6
.
2
7
.
4
1
0
.
4
1
)
5
.
6
1
(
)
6
.
1
1
(
)
8
.
2
1
(
)
3
.
8
(
129
103
77
140
120
100
80
60
10
8
6
4
2
2
63
61
7
5
4
4
3,331
3,500
3,454
3,400
3,300
3,200
3,100
3,230
3,277
3,151
2011
2012
2013
2014
2015
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.
We are committed to maintaining a
progressive and sustainable dividend
policy.
2015 performance Negative TSR in the
year reflects the fall in the BP share price
exceeding the dividend.
2011
2012
2014
2013
2015
Proved reserves replacement ratio is 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. The ratio
reflects both subsidiaries and equity-
accounted entities.
This measure helps to demonstrate our
success in accessing, exploring and
extracting resources.
2015 performance This year’s reserves
replacement ratio was similar to 2014. See
page 229 for more information.
2011
2012
2013
2014
2015
2011
2012
2013
2014
2015
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.
We monitor the progress of our major
projects to gauge whether we are
delivering our core pipeline of activity.
Projects take many years to complete,
requiring differing amounts of resource,
so a smooth or increasing trend should
not be anticipated.
2015 performance We delivered three
major projects in Upstream – two in
Angola and one in Asia Pacific, and
started up Zhuhai 3 in Downstream.
We report production of crude oil,
condensate, natural gas liquids (NGLs),
natural bitumen and natural gas on a
volume per day basis for our subsidiaries
and equity-accounted entities. Natural
gas is converted to barrels of oil
equivalent at 5,800 standard cubic feet of
natural gas = 1 boe.
2015 performance BP’s total reported
production including Upstream and
Rosneft segments was 4.0% higher
than in 2014. This was mainly due to
favourable entitlement impact in our
production-sharing agreements in the
Upstream segment.
Tier 1 process safety events a
Greenhouse gas emissionsb
(million tonnes of CO2 equivalent)
Group priorities indexd (%)
Diversity and inclusiond (%)
74
43
100
80
60
40
20
100
80
60
40
20
28
20
20
61.8
59.8
50.3
48.6
48.9
100
80
60
40
20
67
71
72
72
69
Women
Non UK/US
2
2
2
2
3
2
8
1
8
1
9
1
0
2
9
1
7
1
5
1
30
25
20
15
10
5
2011
2012
2013
2014
2015
2011
2012
2013
2014
2015
2011
2012
2013
2014
2015
2011
2012
2013
2014
2015
We report tier 1 process safety events,
which are the losses of primary
containment of greatest consequence
– causing harm to a member of the
workforce, costly damage to equipment
or exceeding defined quantities.
2015 performance The number of tier 1
process safety events has decreased
substantially since 2011. We believe
our systematic approach to safety
management and assurance is
contributing to improved performance
over the long term and will maintain our
focus in these areas.
We provide data on greenhouse gas
(GHG) emissions material to our business
on a carbon dioxide-equivalent basis. This
includes carbon dioxide (CO2) and
methane for direct emissions. Our GHG
KPI encompasses all BP’s consolidated
entities as well as our share of
equity-accounted entities other than BP’s
share of TNK-BP and Rosneft.c
2015 performance The increase in our
reported emissions is due to updating the
global warming potential for methane.
Without this update, our emissions
would have decreased primarily due to
divestments in Alaska.
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.
b The 2015 figure reflects our update of the
global warming potential for methane from
21 to 25, in line with IPIECA’s guidelines.
c For more information on our GHG emissions
see page 46.
We track how engaged our employees
are with our strategic priorities using our
group priorities index. This is derived
from survey questions about their
perceptions of BP as a company and
how it is managed in terms of leadership
and standards.
2015 performance Our group priorities
engagement measure fell slightly in 2015,
as expected in the current low oil price
environment.
Each year we report the percentage of
women and individuals from countries
other than the UK and the US among
BP’s group leaders. This helps us track
progress in building a diverse and
well-balanced leadership team.
2015 performance The percentage of
our group leaders who are women or
non-UK/US rose slightly. We remain
committed to our aim that women will
represent at least 25% of our group
leaders by 2020.
d Relates to BP employees.
★ Defined on page 256.
21
BP Annual Report and Form 20-F 2015Strategic report
Strategy, performance and pay
In a difficult environment, BP’s leadership delivered strong operating performance,
based on a sound strategy and consistently improved safety performance. They have
acted early and decisively in response to low oil prices to preserve future growth.
Highlights of the year
Strong safety and operational performance in a difficult environment
• Responded early and decisively to lower oil price environment.
• Excellent safety standards with continuous improvement over the past three years, leading to
improvements in reliability and operations.
• Strong operating cash flow★ and underlying replacement cost profit relative to plan.
• Net investment managed aggressively to reflect ‘lower for longer’ oil price environment.
• Executive directors’ pay outcomes reflect strong operating performance relative to plan.
• Alignment between executives and shareholders with the majority of executive director
remuneration paid in equity with lengthy retention requirements.
In an ever more challenging world BP executives
performed strongly in 2015 in managing the
things they could control and for which they
were accountable. BP was one of the first to
recognize the shift to a ’lower for longer’ price
environment and through early action delivered
distinctive competitive performance on costs.
Momentum built through the year in
simplification and efficiencies, such that
operating cash flow significantly exceeded plan.
Assets ran well and major projects★ were
commissioned on time. Good performance on
safety has led to sound and reliable operations.
There has been a high quality of execution.
Our pay structure is relatively simple and reflects
a number of key overriding principles. It is
long-term, performance-based and tied directly
to strategy and delivery. It is biased towards
equity with long retention periods. This is
reflected in the policy framework that was
approved by shareholders in 2014. Variable
remuneration is primarily based on true
underlying performance and not driven by
factors over which the executives have no
control. Consistent with past practice, we
Short-term: annual bonus
normalize for changes in oil and gas price and
refining margins. This avoids both windfall gains
and punitive losses in periods of extreme
volatility such as we are currently experiencing.
Against this background, I am pleased to give
an overview of key elements of executive
remuneration for 2015. All of the detail is set out
in the Directors’ remuneration report on page 76.
Short-term performance
The annual cash bonus is based on safety (30%)
and value (70%) measures directly linked to our
KPIs and strategy. In setting annual safety
targets, the committee reviews the three-year
performance and in each case aims for
improvement. We measure value by reference to
operating cash flow and underlying replacement
cost profit. In addition, two value measures,
reductions in corporate and functional costs and
net investment (organic)★, reflect progress in
simplification. Targets were based on the
board’s plan set in January 2015, with the
maxima tested for stretch. Results were strong
across all measures.
Measure
Result
Target
Outcome
Safety and operational risk
Loss of primary containment
Process safety tier 1 events
Recordable injury frequency
Value
Spills and leaks declined.
The most serious process
safety events were reduced.
Number of work-related
recordable injuries per 200k
hours fell.
≤ 253 events 208 eventsa
20 events
≤ 29 events
≤ 0.261/200k
hoursb
0.223/200k
hoursb
Significantly ahead of plan.
Significantly ahead of plan.
Operating cash flow
Underlying replacement
cost profit
Net investment (organic)
Significantly ahead of plan.
Corporate and functional costs Significantly ahead of plan.
Major project delivery
On target.
$17.2bn
$4.2bn
18%
5.9%
4
$19.1bn
$5.9bn
27%
17.6%
4
These pages constitute the remuneration
committee chair’s annual statement which
forms part of the Directors’ remuneration
report, the rest of which can be found on
page 76.
For more information on the group’s key
performance indicators see page 20.
22
BP Annual Report and Form 20-F 2015
a Adjusted in accordance with the treatment of the loss of primary containment key performance indicator on page 20.
b Excludes biofuels.
The safety and operational risk performance has
been excellent. This has led to increased
reliability and more efficient operations. There is
a proposed settlement of the federal and state
claims and settlement of most of the local
government claims relating to the Deepwater
Horizon incident. BP responded quickly and
decisively to the drop in oil price, continuing to
simplify its activities and significantly reducing
its cost base. Capital discipline has been
demonstrated in a strategic way that offers
flexibility and resilience now and options for
future growth. Our belief is that management
has delivered very well in a difficult year.
The overall group score achieved was 1.91 out of
a maximum of 2.00. As is our normal practice,
the committee reviewed this result and
considered whether it produced a fair outcome
in light of the underlying performance of the
company and the wider environment. As part of
this both the committee and the group chief
executive believed some recognition of the
dramatic fall in oil prices and its impact on
shareholders was warranted. As a result the
group score was lowered to 1.70 and this has
been used to determine annual bonuses for BP’s
wider management group. For executive
directors our approved policy limits annual bonus
to 1.50.
Long-term performance
The 2012 deferred bonus was contingent on
safety and environmental sustainability over a
three-year period. The committee saw good
evidence of a continued improvement on safety
that is both ingrained in the culture and has led
to more reliable and efficient operations. The
award vested in full.
The 2013-15 performance share plan was, as in
previous years, based on three sets of measures
equally weighted: relative total shareholder return
(TSR) over the three-year period, 2015 operating
cash flow and finally, strategic imperatives which
included safety and operational risk, relative
reserves replacement ratio (RRR) and major
project delivery over the three years.
For TSR, BP was in third place. The target set in
2013 for operating cash flow in 2015 was $35
billion based on the plan assumptions.. At the start
of the year, this was normalized for the change in
oil and gas price, and refining margins since 2013.
We also, as in previous years, adjusted for major
divestments and for contributions to the Gulf of
Mexico restoration. The resulting target was $17.7
billion. This compared to an outcome of $19.1
billion. Safety performance at the end of the
three-year period, against targets previously set at
the outset, was strong. The final results from the
comparator group for RRR are not yet available
but on the evidence, our preliminary assessment
is that the company is in first place. There will be
a final assessment later in the year. Major project
delivery exceeded target.
As a result 77.6% of the shares are expected to
vest. Reviewing the period 2013-15, the
committee believes that this represents a fair
outcome. In that time there has been the
delivery of the 10-point plan in 2014, consistent
improvements in safety performance and
effective budgetary and capital discipline in
difficult circumstances.
★ Defined on page 256.
S
t
r
a
t
e
g
i
c
r
e
p
o
r
t
Long-term: performance share plan
Measure
Result
Target
Outcome
Relative TSR
Operating cash flow
Strategic imperatives
Relative reserves replacement
ratio (RRR)
Safety and operational risk:
• Loss of primary containment
• Process safety tier 1 events
• Recordable injury frequency
BP’s TSR ranked third
versus other oil majors.
Strong operating cash
flow in 2015 relative to
plan.
BP’s RRR preliminary
ranked first versus other
oil majors.
Downward trend over
the last three years.
Major project delivery
15 major projects were
commissioned.
Outperform
peers
$17.7bn
Third
$19.1bn
Outperform
peers
First
≤ 212 events
≤ 30 events
≤ 0.240/200k
hoursb
208 eventsa
20 events
0.223/200k
hours
11
15
a Adjusted in accordance with the treatment of the loss of primary containment key performance indicator on page 20.
b Excluding biofuels.
Pay outcomes
The resulting remuneration for executive directors
is shown below. Consistent with the wider
population of BP employees, executive directors
received no increase in base salary in 2015. This
is being continued with no salary increase for the
senior leadership and executive directors in 2016.
three-year retention period before being released
to the individual.
In our assessment, the overall quantum of
remuneration is market competitive and
represents a balanced outcome. It is based
heavily on performance and mainly paid in equity
with long retention periods. Executive directors
are required to hold shares in excess of
five-times salary. While the value of their shares
has, as for all shareholders, dropped with the oil
price, they satisfy that requirement.
As described above, annual bonus was limited to
a group score of 1.50, the 2012 deferred bonus
vested fully and 77.6% of shares in the
2013-2015 performance share plan are expected
to vest. These will be finally determined later in
the year when results from all oil majors are
known. The shares that vest will have a further
For the single figure remuneration
table see page 77.
Total remuneration (excluding pensions)
Group chief executive
Chief financial officer
1
15%
$13.1m
4
54%
2
11%
3
20%
1
16%
£4.8m
4
46%
2
12%
3
26%
1. Salary and benefits
2. Annual cash bonus
3. 2012 deferred bonus
4. 2013-15 performance shares
Conclusion
In conclusion, BP has performed well and
surpassed the board’s expectations on almost all
of the measures. I am pleased that our current
policy has appropriately recognized this in the
2015 outcomes. There remain challenging times
with an evolving remuneration landscape. During
2016, the committee will be undertaking a full
review of our policy. I have already met with
some of our key shareholders and look forward
to continuing this engagement as we develop a
new proposed policy for approval at the 2017
Annual General Meeting.
BP is a strong company with strong leadership.
The company continues to evolve as will our
remuneration policy and practice to ensure we
remain performance driven and competitive.
Professor Dame Ann Dowling
Chair of the remuneration committee
BP Annual Report and Form 20-F 2015
23
Our markets in 2015
A snapshot of the challenging global energy market in 2015.
More than 200 of our UK BP stores have an M&S
Simply Food® outlet. This premium offer is helping
to drive overall service station sales growth.
Construction of Glen Lyon, our new 270 metre
long floating, production, storage and offloading
vessel, at a shipyard in South Korea.
BP Statistical Review of World Energy
See bp.com/statisticalreview for an
objective review of key global energy
trends.
Crude oil prices (quarterly average)
Brent dated
150
120
90
60
l
e
r
r
a
b
r
e
p
s
r
a
l
l
o
d
S
U
06
07
08
09
10
11
12
13
14
15
Natural gas prices (quarterly average)
Henry Hub
12
10
8
6
4
s
e
c
i
r
p
s
a
g
s
r
a
l
l
o
d
S
U
06
07
08
09
10
11
12
13
14
15
24
The global economy struggled to return to a more
normal pace of growth in 2015 – GDP growth
estimates were revised down over the course of
the year, with latest estimates indicating that the
world economy grew by 2.5% in 2015, compared
to trend growth of around 3%. Slowing growth in
China contributed to falling commodity prices,
weak global trade and weakening emerging
market growth. The developed world also failed
to take off as expected with the US, EU and
Japan all underperforming.
Oil
Crude oil prices averaged $52.39 per barrel in
2015, as demonstrated by the industry
benchmark of dated Brent
, nearly $47 per barrel
below the 2014 average of $98.95. This was the
largest oil price decline ever – in inflation-adjusted
terms – and it was the third-largest percentage
decline (behind 1873 and 1986). Prices recovered
in the second quarter, averaging nearly $62, but
fell later in the year as OPEC production increased
and inventories grew. Brent prices ended the year
near $35.
In response to the sharp decline in world oil
prices, global oil consumption increased by an
above-average 1.6 million barrels per day
(mmb/d) for the year (1.7%).a While emerging
economies accounted for the majority of
growth, the mature economies of the OECD
recorded a rare increase as well. The robust
growth in consumption was once again
exceeded by growth in global production.
Non-OPEC production growth slowed to
1.4mmb/d as US production peaked in the
second quarter in the face of a rapid contraction
in investment and drilling.a OPEC crude oil
production, however, accelerated, growing by
1.1mmb/d in 2015.a As a result, OECD
commercial oil inventories reached record levels
late in the year.
In 2014 global oil consumption grew by roughly
0.8 million barrels per day (0.8%), significantly
slower than the increase in global production
(2.3%).b Non-OPEC production once again
accounted for all the net global increase, driven
by record US growth.
Natural gas
Global price differentials in 2015 continued to
narrow. US gas prices and Asian transacted
LNG prices were more than 40% lower, while
European transacted LNG prices were 15%
lower. The Henry Hub First of the Month index
fell from $4.43 per million British thermal units
(mmBtu) in 2014 to $2.67 in 2015 as supply
growth continued to be resilient.
Transacted LNG prices in Europe and Asia fell
with rising global LNG supplies and weak
demand growth. New LNG projects in Papua
New Guinea and Australia and recovering
supplies in Africa added 1.4bcf/d of supply
capacity to the LNG market in 2015.
Moderating demand and ample supplies from
both Russia and LNG markets reduced the UK
National Balancing Point
average of 42.61 pence per therm in 2015 (2014
50.01). The Japanese spot price fell to an average
of $7.45/mmBtu in 2015 (2014 $13.86) with
weaker demand from North Asian consumers
coinciding with rising supplies in the region.
hub price to an
In 2014 growth in natural gas consumption was
at its slowest rate for the last 20 years – with the
exception of the financial crisis of 2008-09.
Broad differentials between regional gas prices
narrowed considerably, as US gas prices
continued their recovery from their 2012 lows.
Global LNG supply capacity expanded further in
2014, following a small increase in 2013, while
growth in LNG demand moderated.
a From IEA Oil Market Report, February 2016 ©, OECD/IEA
2016, Page 4.
b BP Statistical Review of World Energy 2015.
Prices and margins
See pages 29 and 35.
BP Annual Report and Form 20-F 2015
BP is embedding cost efficiency and simplification into everyday activities
as well as large-scale changes in response to market conditions.
As with other companies within our industry,
BP is taking measures to respond to the
impact of a lower-price environment by
limiting capital spend, looking to benefit from
cost deflation and reducing headcount. In
addition, for some time we have been
encouraging everyone in BP to find and
implement smarter ways of working, without
compromising safety. From large-scale
behaviour changes to small and simple ideas,
our employees are helping to make a positive
difference to the reliability and efficiency of
our operations.
Foundations for success
BP drilling and cementing teams in Azerbaijan
regularly review well design and construction
to ensure they are safe, efficient and reliable.
In efforts to improve cementing technology,
a key element of well construction, the teams
identified ways to simplify the process and
decrease drying times. By changing cement
and optimizing parameters, drying time has
been reduced and more than $1 million has
been saved. The process can be replicated
elsewhere.
Easing the bottleneck
The Cherry Point refinery rail facility receives
crudes directly from US and Canadian producers.
But with only two tracks available, the mile-long
trains often had to wait to offload their oil supply.
This prevented the refinery from maximizing its
rail offloading efficiency. Teams at the site, along
with the supply organization, worked to resolve
the problem by installing additional track to
reduce congestion and allow full utilization of
the rail facility. In 2015 we safely executed this
rail upgrade ahead of schedule and within
budget.
A helicopter-sharing first
When changing crews on board BP’s Skarv
platform in the Norwegian North Sea, a
helicopter flies the replacement team offshore
and brings the current team back to land. On
these journeys an average of six of the 19
seats were unused. We discovered that nearby
operator, Statoil, was in the same situation and
so looked for opportunities to maximize seat
usage on our journeys. Statoil offered BP a
50% share in its contracted helicopter capacity
and the companies entered into a cost-sharing
agreement for scheduled flights. With fewer
flights offshore we have reduced costs and
CO2 emissions.
Steam clean savings
Refinery tank cleaning, which is done by hand,
is not always efficient as it is based on
estimates of waste within the tank.
Downstream teams tested an existing steam
injection method that was new to BP that
separates the build up into sediment on the
bottom, then water, and a layer of recoverable
oil floating on the top. The oil and water are
pumped away, leaving the sediment to be easily
cleaned up in the final manual cleaning step.
Since the process was implemented at the
Rotterdam refinery in 2015, it has significantly
reduced cleaning times – from 9-12 months
down to three, reduced risks to cleaners and
saved more than $3 million. It is now being
adopted across BP with further savings expected.
Logistics planning
Driving supply boats to our offshore Egypt rigs
can consume a lot of fuel. Through detailed
logistics planning we calculated that a 25%
reduction in speed consumed about 40% less
fuel per trip. We also found that keeping a vessel
outside the 500 metre rig zone required less
engine power than the full dynamic positioning
mode needed within it, and this reduced fuel
consumption by around 80%. We have applied
these changes across the region’s fleet and are
expecting to save more than $400,000 a year. We
are sharing this cost-saving approach globally.
★ Defined on page 256.
Making storage simpler
Throughout more than 50 years of operations in
the North Sea, BP had built up large quantities of
equipment that were spread around 172 locations,
with significant storage fees and long lead times
to get these materials offshore. By updating and
improving our materials management process we
reduced the number of stored inventory items by
half and brought the number of storage locations
down by about 65%. We also generated around
$32 million by selling surplus materials and scrap.
25
BP Annual Report and Form 20-F 2015Strategic report Non-operating items in 2015 also included $1,088 million for
restructuring charges that largely relate to rationalization and
reorganization costs in response to the low oil and gas price
environment. A further $1.0 billion of restructuring charges are
expected to be incurred in 2016.
Profit for the year ended 31 December 2014 decreased by
$19.7 billion compared with 2013. Excluding inventory holding losses,
RC profit decreased by $15.6 billion compared with 2013. Both results
in 2013 included a $12.5-billion non-operating gain relating to the
disposal of our interest in TNK-BP.
After adjusting for a net charge for non-operating items, which mainly
related to impairments and further charges associated with the Gulf of
Mexico oil spill; and net favourable fair value accounting effects,
underlying RC profit for the year ended 31 December 2014 was down
by $1.3 billion compared with 2013. The reduction was mainly due to a
lower profit in Upstream, partially offset by improved earnings from
Downstream.
More information on non-operating items, and fair value accounting
effects, can be found on page 217. See Gulf of Mexico oil spill on page
41 and Financial statements – Note 2 for further information on the
impact of the Gulf of Mexico oil spill on BP’s financial results.
See Upstream on page 28, Downstream on page 34, Rosneft on
page 38 and Other businesses and corporate on page 40 for
further information on segment results. Also see page 41 for
further information on the Gulf of Mexico oil spill.
Segment RC profit (loss) before interest and tax ($ billion)
40
30
20
10
0
-10
-20
Taxation
Upstream
Downstream
TNK-BP
Rosneft
Other businesses
and corporate
Gulf of Mexico
oil spill
Unrealized profit
in inventory
Group RC profit (loss)
before interest and tax
2013
2014
2015
The ETR in 2015 compared with 2014 was impacted by various one-off
items. Adjusting for inventory holding impacts, non-operating items, fair
value accounting effects and the one-off deferred tax adjustment in 2015
as a result of the reduction in the UK North Sea supplementary charge, the
underlying ETR on RC profit was 31% in 2015 (2014 36%, 2013 35%). The
underlying ETR for 2015 is lower than 2014 mainly due to changes in the
geographical mix of profits.
The ETR in 2014 was similar to 2013 and was relatively low in both years.
The low ETR in 2014 reflected the impairment charges on which tax
credits arise in relatively high tax rate jurisdictions. The ETR in 2013
reflected the gain on disposal of TNK-BP in 2013 for which there was no
corresponding tax charge.
In the current environment, and with our existing portfolio of assets,
the underlying ETR in 2016 is expected to be lower than 2015 due to the
anticipated mix of profits moving away from relatively high tax Upstream
jurisdictions.
Group performance
A summary of our group financial and
operating performance.
A technician monitors the pressure gauges in the
enhanced oil recovery laboratory in Sunbury.
Financial and operating performance
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 ,
net of tax
Replacement cost profit (loss)
Net charge (credit) for non-operating
2015
2014
$ million
2013
(7,918)
6,412
31,769
(1,462)
(947)
(223)
3,780
(1,548)
(6,463)
(307)
23,451
(1,653)
3,171
(82)
(6,482)
1,320
(5,162)
items , net of tax
11,272
4,620
(10,533)
Net (favourable) unfavourable
impact of fair value accounting
effects , net of tax
Underlying replacement cost profit
Dividends paid per share – cents
– pence
Capital expenditure and acquisitions,
(205)
5,905
40.0
26.383
(557)
12,136
39.0
23.850
280
13,428
36.5
23.399
on an accruals basis
19,531
23,781
36,612
a Profit (loss) attributable to BP shareholders.
The result for the year ended 31 December 2015 was a loss of
$6.5 billion, compared with a profit of $3.8 billion in 2014. Excluding
inventory holding losses, replacement cost (RC) loss was $5.2 billion,
compared with a profit of $8.1 billion in 2014.
After adjusting for a net charge for non-operating items, which mainly
related to the agreements in principle to settle federal, state and the vast
majority of local government claims arising from the 2010 Deepwater
Horizon accident and impairment charges; and net favourable fair value
accounting effects, underlying RC profit for the year ended 31 December
2015 was $5.9 billion, a decrease of $6.2 billion compared with 2014.
The reduction was mainly due to a significantly lower profit in Upstream,
partially offset by improved earnings from Downstream.
26
4,293
8,073
230
23,681
The credit for corporate income taxes in 2015 reflects the deferred tax
impact of the increased provisions in respect of the Gulf of Mexico oil spill.
The effective tax rate (ETR) was 33% in 2015 (2014 19%, 2013 21%).
BP Annual Report and Form 20-F 2015 Cash flow and net debt information
Net cash provided by operating
activities
Net cash used in investing activities
Net cash used in financing activities
Cash and cash equivalents at end of year
Gross debt
Net debt
Gross debt to gross debt-plus-equity
Net debt to net debt-plus-equity
2015
2014
19,133
(17,300)
(4,535)
26,389
53,168
27,158
35.1%
21.6%
32,754
(19,574)
(5,266)
29,763
52,854
22,646
31.9%
16.7%
$ million
2013
21,100
(7,855)
(10,400)
22,520
48,192
25,195
27.0%
16.2%
KPIs used to measure progress against our strategy.
Net cash provided by operating activities
Net cash provided by operating activities for the year ended 31 December
2015 was $13.6 billion lower than 2014, of which $1.1 billion related to the
Gulf of Mexico oil spill. This was principally a result of the lower oil price
environment, although there were benefits of reduced working capital
requirements and lower tax paid.
There was an increase of $11.7 billion in 2014 compared with 2013. Profit
before taxation was lower but this was partially offset by movements in
the adjustments for non-cash items, including depreciation, depletion and
amortization, impairments and gains and losses on sale of businesses and
fixed assets. Furthermore, 2014 was impacted by a favourable movement
in working capital.
Net cash used in investing activities
Net cash used in investing activities for the year ended 31 December 2015
decreased by $2.3 billion compared with 2014. The decrease mainly
reflected a reduction in capital expenditure of $3.9 billion in response to the
lower oil price environment, partly offset by a reduction of $0.7 billion in
disposal proceeds.
The increase of $11.7 billion in 2014 compared with 2013 reflected a
decrease in disposal proceeds of $18.5 billion, partly offset by a $4.9-billion
decrease in our investments in equity-accounted entities, mainly relating to
the completion of the sale of our interest in TNK-BP and subsequent
investment in Rosneft in 2013. There was also a decrease in our other
capital expenditure excluding acquisitions of $2.0 billion.
There were no significant acquisitions in 2015, 2014 and 2013.
The group has had significant levels of capital investment for many years.
Cash flow in respect of capital investment, excluding acquisitions, was
$20.2 billion in 2015 (2014 $23.1 billion and 2013 $30 billion). 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 capital expenditure, excluding acquisitions and asset
exchanges, to be at the lower end of the range of $17-19 billion in 2016.
Total cash disposal proceeds received during 2015 were $2.8 billion (2014
$3.5 billion, 2013 $22.0 billion). In 2015 this included amounts received
from our Toledo refinery partner, Husky Energy, in place of capital
commitments relating to the original divestment transaction that have not
been subsequently sanctioned. In 2013 this included $16.7 billion for the
disposal of BP’s interest in TNK-BP. See Financial statements – Note 4 for
more information on disposals.
lower net proceeds from long-term debt offset by an increase of
$1.2 billion in short-term debt).
The decrease of $5.1 billion in 2014 compared with 2013 primarily reflected
higher net proceeds of $3.3 billion from long-term financing and a decrease
in the net repayment of short-term debt of $1.3 billion. The $8-billion share
repurchase programme was completed in July 2014.
Total dividends paid in 2015 were 40 cents per share, up 2.6% compared
with 2014 on a dollar basis and 10.6% in sterling terms. This equated to a
total cash distribution to shareholders of $6.7 billion during the year (2014
$5.9 billion, 2013 $5.4 billion).
Net debt
Net debt at the end of 2015 increased by $4.5 billion from the 2014 year-end
position. The net debt ratio★ at the end of 2015 increased by 4.9%.
The total cash and cash equivalents at the end of 2015 were $3.4 billion
lower than 2014.
We aim to maintain the net debt ratio, with some flexibility, at around 20%.
We expect the net debt ratio to be above 20% while oil prices remain weak.
Net debt and the net debt ratio are non-GAAP measures. See Financial
statements – Note 26 for gross debt, which is the nearest equivalent
measure on an IFRS basis, and for further information on net debt.
For information on financing the group’s activities, see Financial statements
– Note 28 and Liquidity and capital resources on page 219.
Group reserves and production
Estimated net proved reservesa
(net of royalties)
Liquids
(mmb)
Natural gas (bcf)
Total hydrocarbons★(mmboe)
Of which: Equity-accounted
2015
2014
2013
9,560
44,197
17,180
9,817
44,695
17,523
10,070
45,975
17,996
entitiesb
7,928
7,828
7,753
Productiona (net of royalties)
Liquids (mb/d)
Natural gas (mmcf/d)
Total hydrocarbons (mboe/d)
Of which: Subsidiaries★
Equity-accounted
entitiesc
2,045
7,146
3,277
2,007
1,927
7,100
3,151
1,898
2,013
7,060
3,230
1,882
1,270
1,253
1,348
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 Rosneft on page 38 and Supplementary information on oil
and natural gas on page 169 for further information.
c Includes BP’s share of Rosneft. 2013 also includes BP’s share of TNK-BP production. See Rosneft
on page 38 and Oil and gas disclosures for the group on page 227 for further information.
Total hydrocarbon proved reserves at 31 December 2015, on an oil
equivalent basis including equity-accounted entities, decreased by 2%
compared with 31 December 2014. The change includes a net increase
from acquisitions and disposals of 130mmboe (103mmboe within our
subsidiaries, 28mmboe within our equity-accounted entities). Acquisition
activity in our subsidiaries occurred in Egypt, Trinidad, the US and the UK,
and divestment activity in our subsidiaries occurred in Egypt, Trinidad, the
US and the UK. In our equity-accounted entities the most significant item
was a purchase in Russia.
We have now completed the $10-billion divestment programme which we
announced in 2013. We expect divestments to be around $3-5 billion in
2016 and ongoing divestments to be around $2-3 billion per annum
thereafter.
Our total hydrocarbon production for the group was 4% higher compared
with 2014. The increase comprised a 6% increase (13% increase for liquids
and 2% decrease for gas) for subsidiaries and a 1% increase (1% decrease
for liquids and 9% increase for gas) for equity-accounted entities.
Net cash used in financing activities
Net cash used in financing activities for the year ended 31 December 2015
decreased by $0.7 billion compared with 2014. There were no share
repurchases in 2015, compared with $4.6 billion in 2014. This was largely
offset by lower net proceeds from financing of $3.2 billion ($4.4 billion
See Oil and gas disclosures for the group on page 227.
★ Defined on page 256.
27
BP Annual Report and Form 20-F 2015Strategic report
Upstream
Our strategy is to have a balanced portfolio across
the world’s key basins, working safely and reliably
while maintaining a focus on capital discipline and
quality execution to deliver value.
Operators work on board the floating production, storage and offloading
vessel in the Plutão, Saturno, Vénus and Marte fields in Angola.
Our business model and strategy
The Upstream segment is responsible for our activities in oil and natural
gas exploration, field development and production, as well as midstream
transportation, storage and processing. We also market and trade
natural gas, including liquefied natural gas, power and natural gas
liquids. In 2015 our activities took place in 25 countries.
With the exception of our US Lower 48 onshore business, we deliver
our exploration, development and production activities through five
global technical and operating functions:
• The exploration function is responsible for renewing our resource
base through access, exploration and appraisal, while the reservoir
development function is responsible for the stewardship of our
resource portfolio over the life of each field.
• The global wells organization and the global projects
organization are responsible for the safe, reliable and compliant
execution of wells (drilling and completions) and major projects .
• The global operations organization is responsible for safe, reliable
and compliant operations, including upstream production assets and
midstream transportation and processing activities.
We optimize and integrate the delivery of these activities across 12
regions, with support provided by global functions in specialist areas of
expertise: technology, finance, procurement and supply chain, human
resources and information technology.
The US Lower 48 began operating as a separate onshore business
in 2015.
Technologies such as seismic imaging, enhanced oil recovery and big
data analytics support our upstream strategy by helping us gain new
access, increase recovery and reserves and improve production
efficiency. See Our distinctive capabilities on page 16.
We actively manage our portfolio and place increasing emphasis on
accessing, developing and producing from fields able to provide the
greatest value (including those with the potential to make the highest
contribution to our operating cash flow ). We sell assets that
we believe have more value to others. This allows us to focus our
leadership, technical resources and organizational capability on
28
developing the resources we believe are likely to add the most value
to our portfolio.
Our strategy is to have a balanced portfolio of material, enduring
positions in the world’s key hydrocarbon basins; to employ capital
and execute projects and other activitiesefficiently; and to operate
safely and reliably in every basin to deliver increasing value.
Our strategy is enabled by:
• A continued focus on safety, reliability and the systematic
management of risk.
• Prioritizing value over volume, and a continuous focus on executional
excellence, managing costs and business delivery.
• Maintaining disciplined investment in a balanced portfolio of
opportunities, in deep water, gas value chains, giant fields and
unconventionals .
• Delivering competitive operating cash growth through improvements
in efficiency and reliability – for both operations and capital
investment.
• Strong relationships built on trust, mutual advantage and deep
knowledge of the basins where we operate.
Our performance summary
• For upstream safety performance see page 44.
• We achieved an upstream BP-operated plant reliability of 95%.
• We started up three major upstream projects.
• Our exploration function gained access to new potential resources
covering almost 8,000km2 in four countries.
• Our divestments generated $0.8 billion in proceeds in 2015.
Upstream profitability ($ billion)
RC profit before interest and tax
Underlying RC profit before interest and tax
40
30
20
10
0
-10
26.4 25.2
22.5
19.4
16.7
18.3
15.2
8.9
-0.9
1.2
2011
2012
2013
2014
2015
See Financial performance on page 29 for an explanation of the main
factors influencing upstream profit.
Outlook for 2016
• We expect underlying production to be broadly flat with 2015. The
actual reported outcome will depend on the exact timing of project
start-ups, divestments, OPEC quotas and entitlement impacts in our
production-sharing agreements.
• Capital investment is expected to decrease, largely reflecting our
commitment to continued capital discipline and the rephasing and
refocusing of our activities and major projects where appropriate in
response to the current business environment. We will continue to
manage our costs down using all levers available to us. These include
continuing and expanding the simplification and efficiency efforts
started in 2014, continuing to drive deflation into our third-party spend,
influencing spend in our non-operated assets, and bringing headcount
down to a level that reflects the size of our operations and the current
environment.
• Oil prices continue to be challenging in the near term.
BP Annual Report and Form 20-F 2015 Adapting rapidly
To enable us to respond rapidly to the unique and highly competitive operating environment of the
US onshore exploration and production industry, the Lower 48 began operating as a separate
BP-operated onshore business in the US in 2015.
With its own governance, processes and systems, Lower 48 is better equipped to operate
competitively across several basins from the onshore Gulf Coast north to the Rocky Mountains,
and develop the vast resource within these large acreage positions.
In the San Juan basin of Colorado and New Mexico, we are drawing on our deep understanding of
the area’s reservoirs and utilizing innovative well designs to significantly improve capital efficiency
and increase the number of economic development opportunities.
In 2015 we successfully completed three multi-lateral wells in the San Juan basin, our first-ever
wells of this type there. With multiple horizontal laterals from the main wellbore, instead of only
one, we can access more of the reservoir and produce significantly more resource. Our multi-
lateral wells are already among the most productive we have ever drilled in the basin, with an
average development cost that is about 60% lower than wells we drilled in the basin just a few
years ago.
We now plan for the majority of our new wells in the San Juan basin to be multi-laterals, and are
pursuing well design improvements like these across our extensive resource base.
In addition to enhancing returns on new capital investments, Lower 48 is working to improve
operating efficiency through various initiatives to reduce production deferments and lower costs.
These efforts have begun to reduce production costs, which were down by about 7% year-over-
year in 2015 and are expected to decline even further in 2016.
Using experience to enhance our competitiveness.
2015
43,235
(937)
2014
65,424
8,934
$ million
2013
70,374
16,657
2,130
6,267
1,608
1,193
17,082
15,201
19,772
18,265
19,115
Brent ($/bbl)
2015
2014
2013
Five-year range
150
120
90
60
30
47.78
20.75
45.63
3.80
2.10
34.78
52.39
48.71
93.65
36.15
87.96
$ per barrel
105.38
38.38
99.24
$ per thousand cubic feet
5.35
3.07
$ per barrel of oil equivalent
63.58
5.70
3.80
60.85
98.95
93.28
$ per barrel
108.66
97.99
$ per million British thermal units
2.67
4.43
3.65
pence per therm
42.61
50.01
67.99
Jan
Feb
Mar
Apr May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Henry Hub ($/mmBtu)
2015
2014
2013
Five-year range
9
6
3
Jan
Feb
Mar
Apr May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
The dated Brent price in 2015 averaged $52.39 per barrel. Prices averaged
about $58 during the first half of 2015, but fell sharply during the second
half in the face of strong OPEC production growth and rising inventories.
Brent prices ended the year near $35.
The Henry Hub First of Month Index price was down by 40%, year-on-
year, in 2015 (2014, up by 21%).
The UK National Balancing Point gas price in 2015 fell by 15% compared
with 2014 (2014 a decrease of 26% on 2013). This reflected ample
supplies in Europe with robust Russian flows, higher LNG cargoes and
rising indigenous production. Lower LNG prices in Asia led to a reduction in
the price of transacted LNG available for Europe, which contributed to the
weakness of European spot prices. For more information on the global
energy market in 2015, see page 24.
a Includes sales to other segments.
b Realizations are based on sales by consolidated subsidiaries only, which excludes
equity-accounted entities.
c Includes condensate and bitumen.
d All traded days average.
e Henry Hub First of Month Index.
Market prices
Brent remains an integral marker to the production portfolio, from which a
significant proportion of production is priced directly or indirectly. Certain
regions use other local markers that are derived using differentials or a
lagged impact from the Brent crude oil price.
★ Defined on page 256.
29
Financial performance
Sales and other operating revenuesa
RC profit before interest and tax
Net (favourable) unfavourable impact
of non-operating items★ and fair
value accounting effects★
Underlying RC profit before interest
and tax
Capital expenditure and acquisitions
BP average realizations★b
Crude oilc
Natural gas liquids
Liquids★
Natural gas
US natural gas
Total hydrocarbons★
Average oil marker pricesd
Brent★
West Texas Intermediate
Average natural gas marker prices
Henry Hub gas price★e
UK National Balancing Point gas
price★d
BP Annual Report and Form 20-F 2015Strategic report
Capturing value
Continued declines in oil prices have put upstream earnings under
pressure across the industry. In this challenging environment we are
focused on maximizing the value of our assets, improving the quality of
investment and maintaining capital discipline.
As part of this, we are reviewing our projects to find opportunities to
improve their value. Our Thunder Horse South Expansion project in the
Gulf of Mexico is designed to sustain and grow quality deepwater oil
production from our existing field. We have been able to simplify our
plans and reduce drilling costs by examining the project’s scope and
costs and working with BP suppliers to use more of their standard
offerings that take advantage of current deflation in price. Adopting newer
and proven subsea metering technology has allowed the team to reduce
complexity and simplify execution.
At the same time we’ve further optimized the drilling sequence to
increase the production forecast for this project by 10% without changing
the planned start-up date. As a result the expected development cost per
barrel is now more than 25% lower than before.
Focusing on value-driven propositions.
Financial results
Sales and other operating revenues for 2015 decreased compared with
2014, primarily reflecting significantly lower liquids and gas realizations and
lower gas marketing and trading revenues partly offset by higher production.
The decrease in 2014 compared with 2013 primarily reflected lower liquids
realizations partially offset by higher production in higher-margin areas, higher
gas realizations and higher gas marketing and trading revenues.
Replacement cost (RC) loss before interest and tax for the segment
included a net non-operating charge of $2,235 million. This is primarily
related to a net impairment charge associated with a number of assets,
following a further fall in oil and gas prices and changes to other
assumptions. See Financial statements – Note 4 for further information.
Fair value accounting effects had a favourable impact of $105 million
relative to management’s view of performance.
The 2014 result included a net non-operating charge of $6,298 million,
primarily related to impairments associated with several assets, mainly in
the North Sea and Angola reflecting the impact of the lower near-term
price environment, revisions to reserves and increases in expected
decommissioning cost estimates. Fair value accounting effects had a
favourable impact of $31 million relative to management’s view of
performance. The 2013 result included a net non-operating charge of
$1,364 million, which included an $845-million write-off attributable to
block BM-CAL-13 offshore Brazil, as a result of the Pitanga exploration well
not encountering commercial quantities of oil or gas, and an unfavourable
impact of $244 million from fair value accounting effects.
After adjusting for non-operating items and fair value accounting effects,
the decrease in the underlying RC profit before interest and tax compared
with 2014 reflected significantly lower liquids and gas realizations, rig
cancellation charges and lower gas marketing and trading results partly
offset by lower costs including benefits from simplification and efficiency
activities and lower exploration write-offs, and higher production.
Compared with 2013 the 2014 result reflected lower liquids realizations,
higher costs, mainly depreciation, depletion and amortization and
exploration write-offs and the absence of one-off benefits which occurred
in 2013. This was partly offset by higher production in higher-margin areas,
higher gas realizations and a benefit from stronger gas marketing and
trading activities.
Total capital expenditure including acquisitions and asset exchanges in
2015 was lower compared with 2014. This included $100 million capital
expenditure before closing adjustments in 2015 relating to the purchase of
additional equity in the West Nile Delta concessions in Egypt and $81
million capital expenditure before closing adjustments relating to the
purchase of additional equity in the Northeast Blanco and 32-9
concessions in the San Juan basin onshore US.
In total, disposal transactions generated $0.8 billion in proceeds in 2015,
with a corresponding reduction in net proved reserves of 20mmboe within
our subsidiaries.
The major disposal transaction during 2015 was the sale of our 36%
interest in the Central Area Transmission System (CATS) business in the
UK North Sea to Antin Infrastructure Partners. More information on
disposals is provided in Upstream analysis by region on page 221 and
Financial statements – Note 4.
Exploration
The group explores for oil and natural gas under a wide range of licensing,
joint arrangement
alone or, more frequently, with partners.
and other contractual agreements. We may do this
In exploration we have reduced capital spending by 50% since 2014 with a
focus on prioritizing near-term activity while creating options for longer-
term renewal.
New access in 2015
We gained access to new potential resources covering almost 8,000km2 in
four countries (UK (North Sea), Egypt, the US, and Azerbaijan). We acquired a
20% participatory interest in Taas-Yuryakh Neftegazodobycha, a Rosneft
subsidiary that will further develop the Srednebotuobinskoye oil and gas
condensate field in East Siberia, in November 2015. Related to this, Rosneft
and BP will jointly undertake exploration in an adjacent area of mutual interest.
Rosneft and BP have also agreed to jointly explore two additional areas of
mutual interest in the prolific West Siberian and Yenisey-Khatanga basins
where they will jointly appraise the Baikalovskoye discovery subject to receipt
of all relevant consents. This is in addition to the exploration agreement
announced in 2014 for an area of mutual interest in the Volga-Urals region of
Russia, where Rosneft and BP have commenced joint study work to assess
potential non-shale, unconventional tight-oil
exploration prospects.
Exploration success
We participated in two potentially commercial discoveries in Egypt – Atoll and
Nooros in 2015.
Exploration and appraisal costs
Excluding lease acquisitions, the costs for exploration and appraisal
were $1,794 million (2014 $2,911 million, 2013 $4,811 million). These
costs included exploration and appraisal drilling expenditures, which
were capitalized within intangible fixed assets, and geological and
geophysical exploration costs, which were charged to income as
incurred.
Approximately 26% of exploration and appraisal costs were directed
towards appraisal activity. We participated in 29 gross (16.76 net)
exploration and appraisal wells in six countries.
30
BP Annual Report and Form 20-F 2015 Upstream reserves
Estimated net proved reservesa (net of royalties)
2015
Liquids
Crude oilb
Subsidiaries
Equity-accounted entitiesc
Natural gas liquids
Subsidiaries
Equity-accounted entitiesc
Total liquids
Subsidiariesd
Equity-accounted entitiesc
Natural gas
Subsidiariese
Equity-accounted entitiesc
Total hydrocarbons
Subsidiaries
Equity-accounted entitiesc
3,560
694
4,254
422
13
435
3,982
707
4,689
30,563
2,465
33,027
9,252
1,132
10,384
2014
2013
million barrels
3,582
702
4,283
510
16
526
4,092
717
4,809
3,798
729
4,527
551
16
567
4,349
745
5,094
billion cubic feet
34,187
2,517
36,704
32,496
2,373
34,869
million barrels of oil equivalent
10,243
1,179
11,422
9,694
1,126
10,821
a Because of rounding, some totals may not agree exactly with the sum of their component parts.
b Includes condensate and bitumen which are not material.
c BP’s share of reserves of equity-accounted entities in the Upstream segment. During 2015,
upstream operations in Abu Dhabi, Argentina and Bolivia, as well as some of our operations in
Angola and Indonesia, were conducted through equity-accounted entities.
d Includes 19 million barrels (21 million barrels at 31 December 2014 and 2013) in respect of the
30% non-controlling interest in BP Trinidad & Tobago LLC.
e Includes 2,359 billion cubic feet of natural gas (2,519 billion cubic feet at 31 December 2014 and
2,685 billion cubic feet at 31 December 2013) in respect of the 30% non-controlling interest in
BP Trinidad & Tobago LLC.
Exploration expense
Total exploration expense of $2,353 million (2014 $3,632 million,
2013 $3,441 million) included the write-off of expenses related to
unsuccessful drilling activities, lease expiration or uncertainties around
development in Libya ($432 million), Angola ($471 million), the Gulf of
Mexico ($581 million) and others ($345 million).
Reserves booking
Reserves booking from new discoveries will depend on the results of
ongoing technical and commercial evaluations, including appraisal
drilling. The segment’s total hydrocarbon reserves on an oil equivalent
basis, including equity-accounted entities at 31 December 2015
decreased by 4% (a decrease of 5% for subsidiaries and an increase of
less than 1% for equity-accounted entities) compared with reserves at
31 December 2014.
Proved reserves replacement ratio★
The proved reserves replacement ratio for the Upstream segment in
2015, excluding acquisitions and disposals, was 33% for subsidiaries
and equity-accounted entities (2014 31%), 28% for subsidiaries alone
(2014 29%) and 76% for equity-accounted entities alone (2014 43%).
For more information on proved reserves replacement for the group see
page 227.
Optimizing our assets
The Caspian Sea is one of the world’s leading hydrocarbon
provinces and we have been the major presence in development
of Azerbaijan’s offshore oil and gas fields since our office in Baku
opened in 1992.
The country’s gas production is dominated by one of the world’s
largest fields, Shah Deniz – BP’s biggest discovery since Prudhoe
Bay in Alaska in 1968.
Developing Shah Deniz Stage 1 involved drilling some of BP’s
most difficult wells – at depths of around 6,000 metres below
sea level and under high pressures. And in only seven years, we also
drilled the deepest exploration well in the Caspian to date, built
the platform and onshore terminal and laid the 700km South
Caucasus pipeline through Azerbaijan and Georgia to the
Turkish border.
Our technical expertise and ongoing maintenance of the facilities
has helped Shah Deniz provide a consistently secure and reliable
supply of gas to the region and in 2015 we achieved almost
100% plant reliability . This has helped to increase production from
the existing facilities.
Shah Deniz Stage 1 has reliably delivered plateau production
throughout 2015, with 9.9 billion standard cubic metres of gas
and about 18.3 million barrels of condensate produced.
Strengthening our assets to provide momentum for
years to come.
★ Defined on page 256.
31
BP Annual Report and Form 20-F 2015Strategic report
Developments
We achieved three major project start-ups in 2015: two in Angola and
one in Australia. The In Salah Southern Fields project started up in
February 2016. In addition to starting up major projects, we made good
progress in projects in AGT (Azerbaijan, Georgia, Turkey), the North
Sea, Oman and Egypt.
With BP-operated plant reliability increasing from around 86% in 2011
to 95% in 2015, efficient delivery of turnarounds and strong infill drilling
performance, we expect to keep the average managed base decline
through 2016 at around 2% versus our 2014 baseline. Our long-term
expectation for managed base decline remains at the 3-5% per annum
level we have described in the past.
• Azerbaijan, Georgia, Turkey – we signed agreements to become a
shareholder in the Trans Anatolian Natural Gas Pipeline (TANAP), to
transport gas from Shah Deniz to markets in Turkey, Greece, Bulgaria
and Italy.
• North Sea – we continued to see high levels of activity, including
further progress in the major redevelopment of Quad 204 and
approval of the development plans for the Culzean field. We also
completed the Magnus life extension project and installed the
platform topsides at Clair Ridge.
• Oman – development of the Khazzan project continued, with
10 rigs in operation by the end of 2015. We also signed a heads of
agreement with the government of the Sultanate of Oman to extend
the licence area in February 2016.
• Egypt – we signed final agreements on the West Nile Delta project.
We also increased our working interest in both West Nile Delta
concessions.
Subsidiaries development expenditure incurred, excluding midstream
activities, was $13.5 billion (2014 $15.1 billion, 2013 $13.6 billion).
Production
Our oil and natural gas production assets are located onshore and
offshore and include wells, gathering centres, in-field flow lines,
processing facilities, storage facilities, offshore platforms, export
systems (e.g. transit lines), pipelines and LNG plant facilities. These
include production from conventional and unconventional (coalbed
methane and shale) assets. The principal areas of production are
Angola, Argentina, Australia, Azerbaijan, Egypt, Iraq, Trinidad, the UAE,
the UK and the US.
Production (net of royalties)a
Liquids
Crude oilb
Subsidiaries
Equity-accounted entitiesc
Natural gas liquids
Subsidiaries
Equity-accounted entitiesc
Total liquids
Subsidiaries
Equity-accounted entitiesc
Natural gas
Subsidiaries
Equity-accounted entitiesc
Total hydrocarbons
Subsidiaries
Equity-accounted entitiesc
2015
2014
2013
thousand barrels per day
971
165
1,137
88
7
95
1,060
172
1,232
5,495
456
5,951
844
163
1,007
91
7
99
936
170
1,106
789
294
1,083
86
8
94
874
302
1,176
million cubic feet per day
5,845
415
6,259
5,585
431
6,016
thousand barrels of oil equivalent per day
1,882
1,898
245
374
2,256
2,143
2,007
251
2,258
a Because of rounding, some totals may not agree exactly with the sum of their component parts.
b Includes condensate and bitumen which are not material.
c Includes BP’s share of production of equity-accounted entities in the Upstream segment.
Our Upstream project pipeline
Key:
Oil
Gas
*BP operated
Project
Location
Type
Project
Location
Type
2015 start-ups
Kizomba Satellites Phase 2
Greater Plutonio Phase 3*
Western Flank Phase A
Angola
Angola
Australia
Deepwater
Deepwater
LNG
LNG
Conventional
Conventional
Conventional
Conventional
Expected start-ups 2016-2020
Projects currently under construction
Angola
Angola LNG
North Africa
In Amenas compression
In Salah Southern Fieldsa
North Africa
Alaska
Point Thomson
North Sea
Quad 204*
Thunder Horse water injection* Gulf of Mexico Deepwater
Clair Ridge*
Juniper
Oman Khazzan*
Persephone
Thunder Horse South expansion* Gulf of Mexico Deepwater
West Nile Delta Taurus/Libra*
Culzean
Shah Deniz Stage 2*
Taas-Yuryakh expansion
North Sea
Trinidad
Middle East
Asia Pacific
Conventional
LNG
Tight
LNG
Conventional
High pressure
Conventional
Conventional
Conventional
Egypt
North Sea
Azerbaijan
Russia
Egypt
West Nile Delta Giza/
Fayoum/Raven*
Expected start-ups 2017-2020
Design and appraisal phase
Angelin
Atoll
B18 Platina*
Mad Dog Phase 2*
Snadd*
Tangguh expansion*
Trinidad onshore compression
Trinidad offshore compression
Vorlich*
Beyond 2020
LNG
Trinidad
Conventional
Egypt
Angola
Deepwater
Gulf of Mexico Deepwater
North Sea
Asia Pacific
Trinidad
Trinidad
North Sea
Conventional
LNG
LNG
LNG
Conventional
We have an additional 35-40 projects in the pipeline for post-2020
start-up.
• Mix of resource types across conventional oil, deepwater oil,
conventional gas and unconventionals.
• Broad geographic reach.
• Range of development types, from new to producing fields where
we can use existing infrastructure.
Western Flank Phase B
Australia
Conventional
a Started up in February 2016.
32
BP Annual Report and Form 20-F 2015
Our total hydrocarbon production for the segment in 2015 was 5.4% higher
compared with 2014. The increase comprised a 5.7% increase (13.2%
increase for liquids and 1.6% decrease for gas) for subsidiaries and a 2.4%
increase (1.2% increase for liquids and 5.8% increase for gas) for
equity-accounted entities compared with 2014. For more information on
production see Oil and gas disclosures for the group on page 227.
In aggregate, underlying production was flat versus 2014.
The group and its equity-accounted entities have numerous long-term
sales commitments in their various business activities, all of which are
expected to be sourced from supplies available to the group that are not
subject to priorities, curtailments or other restrictions. No single contract or
group of related contracts is material to the group.
Gas marketing and trading activities
Our integrated supply and trading function markets and trades our own and
third-party natural gas (including LNG), power and NGLs. This provides us
with routes into liquid markets for the gas we produce and generates
margins and fees from selling physical products and derivatives to third
parties, together with income from asset optimization and trading. This
means we have a single interface with gas trading markets and one
consistent set of trading compliance and risk management processes,
systems and controls.
Our upstream marketing and trading activity primarily takes place in the
US, Canada and Europe and supports group LNG activities, managing
market price risk and creating incremental trading opportunities through
the use of commodity derivative contracts. It also enhances margins and
generates fee income from sources such as the management of price risk
on behalf of third-party customers.
Our trading financial risk governance framework is described in Financial
statements – Note 28 and the range of contracts used is described in
Glossary – commodity trading contracts on page 256.
Unlocking energy potential
BP has invested in Egypt for half a century. And in recent years, it has
been a key location for BP discoveries. Our ongoing investment and
exploration activities are helping to unlock energy potential in the area.
In March we made a gas discovery 6,400 metres below sea level in the
North Damietta offshore area. We are working with the Egyptian
government to accelerate the development of the Atoll discovery.
The discovery is in line to become our next major project in Egypt after
completion of our West Nile Delta project.
For an analysis of our upstream business by geographic region
and key events in 2015, see page 221.
Building a pipeline of future growth opportunities.
★ Defined on page 256.
33
BP Annual Report and Form 20-F 2015Strategic report • Fuels and lubricants marketing – we invest in higher-returning
businesses with reliable cash flows and growth potential.
• Portfolio quality – we maintain our focus on quality by high-grading of
assets combined with capital discipline.
• Simplification and efficiency – we are embedding a culture of
simplification and efficiency to support performance improvement
and make our businesses even more competitive.
Disciplined execution of our strategy is helping improve our underlying
performance and create a more resilient business that is better able to
withstand external environmental impacts. This is with the aim of
ensuring Downstream remains a reliable source of cash flow for BP.
Our performance summary
• For Downstream safety performance see page 45.
• We have delivered record replacement cost profit before interest and
tax and pre-tax returns this year, demonstrating that we are
creating a more resilient Downstream business.
• We delivered strong availability and operational performance across
our refining portfolio and year-on-year improvement in utilization.
• We commenced the European launch of our BP fuels with ACTIVE
technology in Spain, which are designed to remove dirt and protect
car engines.
• We announced the agreement to restructure our German refining
joint operation with Rosneft.
• We halted operations at Bulwer refinery in Australia.
• In Air BP we completed the integration of Statoil Fuel and Retail’s
aviation business which added more than 70 airports to our global
network.
• In our lubricants business we launched Castrol’s Nexcel, an
innovative automotive oil-change technology.
• We completed start-up of the Zhuhai 3 plant in China – the world’s
largest single train purified terephthalic acid (PTA) unit.
• Our simplification and efficiency programmes contributed to material
progress in lowering cash costs . These programmes include
right-sizing the Downstream organization, implementing site-by-site
improvement plans to deliver manufacturing efficiency in refining and
petrochemicals, and focusing on third-party costs.
Downstream profitability ($ billion)
RC profit before interest and tax
Underlying RC profit before interest and tax
6.0
5.5
6.5
7.1
2.9
3.6
2.9
4.4
3.7
8
6
4
2
7.5
2011
2012
2013
2014
2015
See Financial performance on page 35 for the main factors influencing
downstream profit.
Outlook for 2016
• We anticipate a weaker refining environment.
• We expect the financial impact of refinery turnarounds to be higher
than 2015 as a result of increased turnaround activity.
Downstream
We continued to improve our personal and process
safety and delivered strong operations and
marketing performance, contributing to record
replacement cost profit before interest and tax.
The Cherry Point refinery processes crude oil sourced from Alaska,
mid-continent US and Canada and has a capacity of 234,000 barrels per day.
Our business model and strategy
The Downstream segment has global manufacturing and marketing
operations. It is the product and service-led arm of BP, made up of
three businesses:
• Fuels – includes refineries, fuels marketing and convenience retail
businesses, together with global oil supply and trading activities that
make up our fuels value chains (FVCs). We sell refined petroleum
products including gasoline, diesel and aviation fuel.
• Lubricants – manufactures and markets lubricants and related
products and services globally, adding value through brand,
technology and relationships, such as collaboration with original
equipment manufacturing partners.
• Petrochemicals – manufactures, sells and distributes products, that
are produced mainly using proprietary BP technology, and are then
used by others to make essential consumer products such as paint,
plastic bottles and textiles. We also license our technologies to third
parties.
We aim to run safe and reliable operations across all our businesses,
supported by leading brands and technologies, to deliver high-quality
products and services that meet our customers’ needs.
Our strategy focuses on a quality portfolio that aims to lead the
industry, as measured by net income per barrel
returns and growing operating cash flow . Our five strategic priorities
are:
, with improving
• Safe and reliable operations – this remains our first priority and
we continue to drive improvement in personal and process
safety performance.
• Advantaged manufacturing – we continue to build a top-quartile
refining business by having a competitively advantaged portfolio
underpinned by operational excellence that helps to reduce exposure
to margin volatility. In petrochemicals we seek to sustainably improve
earnings potential and make the business more resilient to a bottom
of cycle environment through portfolio repositioning, improved
operational performance and efficiency benefits.
34
BP Annual Report and Form 20-F 2015
Financial performance
Sale of crude oil through spot
and term contracts
Marketing, spot and term sales
of refined products
Other sales and operating revenues
Sales and other operating revenuesa
RC profit (loss) before interest and taxb
Fuels
Lubricants
Petrochemicals
Net (favourable) unfavourable impact
of non-operating items and fair
value accounting effects
Fuels
Lubricants
Petrochemicals
Underlying RC profit (loss) before
interest and taxb
Fuels
Lubricants
Petrochemicals
Capital expenditure and acquisitions
2015
2014
$ million
2013
38,386
80,003
79,394
148,925
13,258
200,569
227,082
16,401
323,486
258,015
13,786
351,195
5,858
1,241
12
7,111
137
143
154
434
5,995
1,384
166
7,545
2,109
2,830
1,407
(499)
3,738
389
(136)
450
703
3,219
1,271
(49)
4,441
3,106
1,518
1,274
127
2,919
712
(2)
3
713
2,230
1,272
130
3,632
4,506
We continue to grow our fuels marketing businesses, including retail,
through differentiated marketing offers and key partnerships. We partner
with leading retailers, creating distinctive offers that aim to deliver good
returns and reliable profit and cash generation (see page 13).
Underlying RC profit before interest and tax was higher compared with
2014 reflecting a strong refining environment, improved refining margin
optimization and operations, and lower costs from simplification and
efficiency programmes. Compared with 2013, the 2014 result was higher,
mainly due to improved fuels marketing performance, increased heavy
crude processing and higher production, mainly as a result of the ramp-up
of operations at our Whiting refinery following the modernization project.
This was partially offset by a weaker refining environment.
Refining marker margin
We track the margin environment by a global refining marker margin
(RMM). Refining margins are a measure of the difference between the
price a refinery pays for its inputs (crude oil) and the market price of its
products. Although refineries produce a variety of petroleum products, we
track the margin environment using a simplified indicator that reflects the
margins achieved on gasoline and diesel only. 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.
Region
US North West
US Midwest
Crude marker
Alaska North
Slope
West Texas
Intermediate
Northwest Europe
Brent
Mediterranean
Azeri Light
2015
2014
$ per barrel
2013
24.0
19.0
14.5
12.7
15.4
17.0
16.6
17.4
12.5
10.6
13.5
14.4
15.2
21.7
12.9
10.5
13.4
15.4
a Includes sales to other segments.
b Income from petrochemicals produced at our Gelsenkirchen and Mülheim sites is reported within
the fuels business. Segment-level overhead expenses are included within the fuels business.
Australia
BP RMM
Brent
BP refining marker margin ($/bbl)
2014
2013
2015
Five-year range
32
24
16
8
Jan
Feb
Mar
Apr May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
The average global RMM in 2015 was $17.0/bbl, $2.6/bbl higher than in
2014, and the second highest on record (after 2012). The increase was
driven by higher margins on gasoline as a result of increased demand in a
low oil price environment and persistent refinery outages in the US.
Financial results
Sales and other operating revenues in 2015 were lower compared with
2014 due to lower crude prices. Similarly, the decrease in 2014, compared
with 2013 primarily was due to falling crude prices.
Replacement cost (RC) profit before interest and tax for the year ended
31 December 2015 included a net operating charge of $590 million, mainly
relating to restructuring charges. The 2014 result included a net non-
operating charge of $1,570 million, primarily relating to impairment charges
in our petrochemicals and fuels businesses, while the 2013 result included
impairment charges in our fuels business, which were mainly associated
with our disposal programme. In addition, fair value accounting effects had
a favourable impact of $156 million, compared with a favourable impact of
$867 million in 2014 and an unfavourable impact of $178 million in 2013.
After adjusting for non-operating items and fair value accounting effects,
underlying RC profit before interest and tax of $7,545 million in 2015 was a
record for Downstream.
Our fuels business
The fuels strategy focuses primarily on fuels value chains (FVCs). This
includes building a top-quartile and focused refining business through
operating reliability, feedstock and location advantage and efficiency
improvements to our already competitively advantaged portfolio.
We believe that having a quality refining portfolio connected to strong
marketing positions is core to our integrated FVC businesses as this
provides optimization opportunities in highly competitive markets.
In January 2016 we announced that we signed definitive agreements to
dissolve our German refining joint operation with our partner Rosneft. The
restructuring will refocus our refining business in the heart of Europe and is
in line with our drive for greater simplification and efficiency.
Defined on page 256.
35
BP Annual Report and Form 20-F 2015Strategic report
Refining
At 31 December 2015 we owned or had a share in 13 refineries producing
refined petroleum products that we supply to retail and commercial
customers. For a summary of our interests in refineries and average daily
crude distillation capacities see page 225.
In 2015, refinery operations were strong, with Solomon refining availability
sustained at around 95% and utilization rates of 91% for the year. Overall
refinery throughputs in 2015 were flat compared to 2014, with reduced
throughput from ceasing refining operations at Bulwer refinery, offset by
increased throughput at the Whiting and Kwinana refineries.
Refinery throughputsa
USb
Europe
Rest of worldb
Total
Refining availability
Sales volumes
Marketing salesc
Trading/supply salesd
Total refined product sales
Crude oile
Total
2015
657
794
254
1,705
94.7
2,835
2,770
5,605
2,098
7,703
2014
2013
thousand barrels per day
726
766
299
1,791
%
642
782
297
1,721
94.9
95.3
thousand barrels per day
3,084
2,485
5,569
2,142
7,711
2,872
2,448
5,320
2,360
7,680
a Refinery throughputs reflect crude oil and other feedstock volumes.
b Bulwer refinery in Australia ceased refining operations in 2015. The Texas City and Carson
refineries in the US were both divested in 2013.
c Marketing sales include sales to service stations, end-consumers, bulk buyers and jobbers (i.e.
third parties who own networks of a number of service stations) and small resellers.
d Trading/supply sales are sales to large unbranded resellers and other oil companies.
e 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. 87,000 barrels per
day relate to revenues reported by the Upstream segment.
36
Logistics and marketing
Downstream of our refineries, we operate an advantaged infrastructure and
logistics network that includes pipelines, storage terminals and tankers for
road and rail. We seek to drive excellence in operational and transactional
processes and deliver compelling customer offers in the various markets
where we operate. In early 2016 we agreed the disposal of our Amsterdam
oil terminal. We also announced our intention to enter into joint ventures
on certain midstream assets in North America and Australia to increase our
competitiveness and enable growth in these regions.
We supply fuel and related retail services to consumers through company-
owned and franchised retail sites, as well as other channels, including
dealers and jobbers. We also supply commercial customers within the
transport and industrial sectors.
Retail sitesf
US
Europe
Rest of world
Total
Number of retail sites operated under a BP brand
2015
7,000
8,100
2,100
17,200
2014
7,100
8,000
2,100
17,200
2013
7,700
8,000
2,100
17,800
f Reported to the nearest 100. Includes sites not operated by BP but instead operated by dealers,
jobbers, franchisees or brand licensees under a BP brand. These may move to or from the BP
brand as their fuel supply or brand licence agreements expire and are renegotiated in the normal
course of business. Retail sites are primarily branded BP, ARCO and Aral. Excludes our interests
in equity-accounted entities that are dual-branded.
Retail is the most material element of our fuels marketing operations and
has good exposure to growth markets. In addition we have distinctive
partnerships with leading retailers in six countries and plan to expand
elsewhere. Retail is a significant source of growth today and is expected to
be so in the future. This year we began rolling out our new BP fuels with
ACTIVE technology in Spain and we plan to continue this roll-out in
additional markets in 2016.
Supply and trading
Our integrated supply and trading function is responsible for delivering
value across the overall crude and oil products supply chain. This structure
enables our downstream businesses to maintain a single interface with oil
trading markets and operate with one set of trading compliance and risk
management processes, systems and controls. It has a two-fold purpose:
Improving operations
Our Castellón refinery in Spain has been ranked among the best
refineries for availability in the world by Solomon international standards.
Since 2009 the refinery has had an ongoing programme in place that is
focused on unlocking local employee knowledge to find efficiencies and
improvements to safety and operations.
Using BP’s continuous improvement methodology, the programme has
captured more than 2,500 ideas, with contributions from around 80% of
the refinery’s employees. Ideas have covered everything from reducing
risks, improving efficiency, increasing margins, reducing costs and
increasing plant availability to improving staff engagement. All of these
have been analysed to draw out underlying issues and develop actions
that address these.
By April 2015 around 1,000 ideas had been implemented and the benefits
of the programme are being realized with reduced break-even margins,
improved safety ratios and increased plant availability and utilization.
The programme has contributed to the improvement in Castellón’s
break-even margin by more than $2 per barrel between 2009 and 2015.
The refinery has also seen that steps to improve safety go hand-in-hand
with improving operational reliability. Since the programme began, there
has been a steady reduction in tier 1 and 2 process safety events –
those with the potential to cause the most harm to people and property.
Over the same time, the refinery’s utilization – a measure of how much
crude is being processed – improved, up from 78% in 2009 to 93% in
2015.
Downstream provides strong cash generation for the group.
BP Annual Report and Form 20-F 2015 First, it seeks to identify the best markets and prices for our crude oil,
source optimal raw materials for our refineries and provide competitive
supply for our marketing businesses. We will often sell our own crude and
purchase alternative crudes from third parties for our refineries where this
will provide incremental margin.
Second, it aims to create and capture incremental trading opportunities by
entering into a full range of exchange-traded commodity derivatives,
over-the-counter contracts and spot and term contracts. In combination
with rights to access storage and transportation capacity, this allows it to
access advantageous price differences between locations and time
periods, and to arbitrage between markets.
The function has trading offices in Europe, North America and Asia. Our
presence in the more actively traded regions of the global oil markets
supports overall understanding of the supply and demand forces across
these markets.
Our trading financial risk governance framework is described in Financial
statements – Note 28 and the range of contracts used is described in
Glossary – commodity trading contracts on page 256.
Aviation
Air BP’s strategic aim is to continue to hold strong positions in our core
locations of Europe and the US, while expanding our portfolio in airports
that offer long-term competitive advantage in material growing markets
such as Asia and South America. We are one of the world’s largest global
aviation fuels suppliers. Air BP serves many major commercial airlines as
well as the general aviation sectors. We have marketing sales of more than
430,000 barrels per day and we added more than 70 airports to our global
network with the acquisition of Statoil Fuel & Retail’s aviation business.
Our lubricants business
Our lubricants strategy is to focus on our premium brands and growth
markets while leveraging technology and customer relationships. With
more than 50% of profit generated from growth markets and continued
growth in premium lubricants, we have an excellent base for further
expansion and sustained profit growth.
Our lubricants business manufactures and markets lubricants and related
products and services to the automotive, industrial, marine and energy
markets across the world. Our key brands are Castrol, BP and Aral. Castrol
is a recognized brand worldwide that we believe provides us with
significant competitive advantage. In technology, we apply our expertise to
create differentiated, premium lubricants and high-performance fluids for
customers in on-road, off-road, sea and industrial applications globally.
We are one of the largest purchasers of base oil in the market, but have
chosen not to produce it or manufacture additives at scale. Our
participation choices in the value chain are focused on areas where we can
leverage competitive differentiation and strength, such as:
• Applying cutting-edge technologies in the development and formulation
of advanced products.
• Creating and developing product brands and clearly communicating their
benefits to customers.
• Building and extending our relationships with customers to better
understand and meet their needs.
The lubricants business delivered an underlying RC profit before interest
and tax which was higher than 2014 and 2013. The 2015 result reflected
strong performance in growth markets and premium brands and lower
costs from simplification and efficiency programmes. These factors
contributed to around a 20% year-on-year improvement in results, which
was partially offset by adverse foreign exchange impacts. The 2014 result
benefited from improved margins across the portfolio, offset by adverse
foreign exchange impacts.
Our petrochemicals business
Our petrochemicals strategy is to improve our earnings potential and make
the business more resilient to a bottom-of-cycle environment. We develop
proprietary technology to deliver leading cost positions compared with our
competition. We manufacture and market four main product lines:
• Purified terephthalic acid (PTA).
• Paraxylene (PX).
• Acetic acid.
• Olefins and derivatives.
We also produce a number of other specialty petrochemicals products.
We aim to reposition our portfolio, improve operating performance and
create efficiency benefits. We are taking steps to significantly improve the
resilience of the business to a bottom-of-cycle environment by:
• Restructuring a significant portion of our portfolio, primarily in our
aromatics business, to shut down older capacity in the US and Asia and
assess disposal options for less advantaged assets.
• Retrofitting our best technology in our advantaged sites to reduce overall
operating costs.
• Growing third-party licensing income to create additional value.
• Delivering operational improvements focused on turnaround efficiency
and improved reliability.
• Delivering value through simplification and efficiency programmes.
In addition to the assets we own and operate, we have also invested in a
number of joint arrangements in Asia, where our partners are leading
companies in their domestic market. We are licensing our distinctive
technologies, including recently announced licensing agreements for our
latest generation PTA technology in Oman and China.
In 2015 the petrochemicals business delivered a higher underlying RC
profit before interest and tax compared with 2014 and 2013. The result
reflected improved operational performance and benefits from our
simplification and efficiency programmes leading to lower costs.
Compared with 2013, the 2014 result was lower, reflecting a continuation
of the weak margin environment, particularly in the Asian aromatics sector,
and unplanned operational events.
Our petrochemicals production of 14.8 million tonnes in 2015 was
higher than 2014 and 2013 (2014 14.0mmte, 2013 13.9mmte), with the low
margin environment in 2014 and 2013 driving reduced output.
In 2015, our Zhuhai 3 PTA plant in China was fully commissioned adding
1.25 million tonnes of production capacity to our petrochemicals portfolio.
During the year we also shut down older capacity of certain units in the US
and Asia.
We are upgrading our PTA plants at Cooper River in South Carolina, US and
Geel in Belgium using our latest proprietary technology. We expect these
investments to significantly increase manufacturing efficiency at these
facilities. We plan to continue deploying our technology in new asset
platforms to access Asian demand and advantaged feedstock sources.
We announced in January 2016 that we had reached an agreement to
sell our Decatur petrochemicals complex in Alabama, US, as part of
our strategy to refocus our global petrochemicals business for
long-term growth.
Defined on page 256.
37
BP Annual Report and Form 20-F 2015Strategic report Rosneft
Rosneft is the largest oil company in Russia, with a
strong portfolio of existing and future opportunities.
Taas-Yuryakh central processing facility at the Srednebotuobinskoye oil and
gas field during the Siberian winter.
BP and Rosneft
• BP’s 19.75% shareholding in Rosneft allows us to benefit from a
diversified set of existing and potential projects in the Russian oil
and gas sector.
• Russia has significant hydrocarbon resources and will continue to
play an important role in long-term energy supply to the global
economy.
• BP is positioned to contribute to Rosneft’s strategy implementation
through collaboration on technology and best practice.
• We have the potential to undertake standalone projects with
Rosneft, both in Russia and internationally.
• We remain committed to our strategic investment in Rosneft, while
complying with all relevant sanctions.
2015 summary
• In the current environment Rosneft continues to deliver solid
operational and financial performance, demonstrating the resilience
of its business model.
• BP received $271 million, net of withholding taxes, in July –
representing our share of Rosneft’s dividend of 8.21 Russian
roubles per share for 2014.
• In 2015 Rosneft met all its debt service obligations and increased
total hydrocarbon production by 1%.
• Bob Dudley serves on the Rosneft Board of Directors, and its
Strategic Planning Committee.
• A second BP nominee, Guillermo Quintero, was elected to
Rosneft’s Board of Directors at Rosneft’s annual general meeting in
June 2015 and was subsequently elected to its HR and
Remuneration Committee.
• US and EU sanctions remain in place on certain Russian activities,
individuals and entities, including Rosneft.
38
Upstream
Rosneft is the largest oil company in Russia and the largest publicly traded
oil company in the world, based on hydrocarbon production volume.
Rosneft has a major resource base of hydrocarbons onshore and offshore,
with assets in all key hydrocarbon regions of Russia: West Siberia, East
Siberia, Timan-Pechora, Volga-Urals, North Caucasus, the continental shelf
of the Arctic Sea, and the Far East.
BP purchased a 20% participatory interest in Taas-Yuryakh
Neftegazodobycha, a Rosneft subsidiary that will further develop the
Srednebotuobinskoye oil and gas condensate field in East Siberia. Related
to this, Rosneft and BP will jointly undertake exploration in an adjacent area
of mutual interest. BP’s interest in Taas-Yuryakh Neftegazodobycha is
reported in the Upstream segment.
Rosneft and BP have also agreed to jointly explore two additional areas of
mutual interest in the prolific West Siberian and Yenisey-Khatanga basins,
where they will jointly appraise the Baikalovskoye discovery subject to
receipt of all relevant consents. This is in addition to the exploration
agreement announced in 2014 for an area of mutual interest in the
Volga-Urals region of Russia, where Rosneft and BP have commenced
joint study work to assess potential non-shale, unconventional tight-oil
exploration prospects.
Rosneft participates in international exploration projects or has operations
in countries including the US, Canada, Vietnam, Venezuela, Brazil, Algeria,
United Arab Emirates, Turkmenistan and Norway.
Rosneft continued to optimize its budget and to focus on new upstream
projects, including the development of the Labaganskoye, Suzun and East
Messoyakha fields. It also signed preliminary contracts for the Russkoye,
Kuyumba, Yurubcheno-Tokhomskoye and East Messoyakha fields to
deliver oil to the Transneft pipeline system.
Rosneft’s estimated hydrocarbon production reached an annual record in
2015. This was due to a ramp-up in drilling, optimization of well
performance and the application of modern technologies such as
multistage fracturing, dual completion and bottomhole treatment. In 2015
estimated gas production increased by around 10% compared with 2014,
primarily driven by greenfield start-ups and commissioning of new wells.
Downstream
Rosneft is the leading Russian refining company based on throughputs.
It owns and operates 10 refineries in Russia. Rosneft continued to
implement the modernization programme for its Russian refineries in
2015 to significantly upgrade and expand refining capacity.
As at 31 December 2015, Rosneft owned and operated more than 2,500
retail service stations in Russia and abroad. This includes BP-branded sites
acquired as part of the TNK-BP acquisition in 2013 that, under a licence
agreement with BP, continue to operate under the BP brand. Downstream
operations also include jet fuel, bunkering, bitumen and lubricants.
On 15 January 2016 BP and Rosneft announced that they had signed
definitive agreements to dissolve the German refining joint operation
Ruhr Oel GmbH (ROG). The restructuring, which is expected to be
completed in 2016, will result in Rosneft taking ownership of ROG’s
interests in the Bayernoil, MiRO Karlsruhe and PCK Schwedt refineries. In
exchange, BP will take sole ownership of the Gelsenkirchen refinery and
the solvent production facility DHC Solvent Chemie.
Rosneft refinery throughputs in 2015 amounted to 1,966mb/d (2014
2,027mb/d, 2013 1,818mb/d).
BP Annual Report and Form 20-F 2015
Balance sheet
Investments in associates e
(as at 31 December)
Production and reserves
2015
2014
$ million
2013
5,797
7,312
13,681
2015a
2014
2013f
Production (net of royalties) (BP share)c
Liquids (mb/d)
Crude oilg
Natural gas liquids
Total liquids
Natural gas (mmcf/d)
Total hydrocarbons (mboe/d)
Estimated net proved reservesh (net of royalties)
809
4
813
1,195
1,019
(BP share)
Liquids (million barrels)
Crude oilg
Natural gas liquids
Total liquidsi
Natural gasj (billion cubic feet)
Total hydrocarbons (mmboe)
4,823
47
4,871
11,169
6,796
816
5
821
1,084
1,008
4,961
47
5,007
9,827
6,702
643
7
650
617
756
4,860
115
4,975
9,271
6,574
e See Financial statements – Note 16 for further information.
f 2013 reflects production for the period 21 March to 31 December, averaged over the full year.
Information on BP’s share of TNK-BP’s production for comparative periods is provided on pages
230 and 231.
g Includes condensate.
h Because of rounding, some totals may not agree exactly with the sum of their component parts.
i Includes 70 million barrels of crude oil in respect of the 1.27% non-controlling interest in Rosneft
held assets in Russia including 28 million barrels held through BP’s equity-accounted interest in
Taas-Yuryakh Neftegazodobycha.
j Includes 129 billion cubic feet of natural gas in respect of the 0.23% non-controlling interest in
Rosneft held assets in Russia including 5 billion cubic feet held through BP’s equity-accounted
interest in Taas-Yuryakh Neftegazodobycha.
Rosneft segment performance
BP’s investment in Rosneft is managed and reported as a separate
segment under IFRS. The segment result includes equity-accounted
earnings, representing BP’s 19.75% share of the profit or loss of Rosneft,
as adjusted 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. See Financial
statements – Note 16 for further information.
Profit before interest and taxc d
Inventory holding (gains) losses
RC profit before interest and tax
Net charge (credit) for non-operating
items
Underlying RC profit before interest
and tax
Average oil marker prices
Urals (Northwest Europe – CIF)
2015a
1,314
(4)
1,310
2014
2,076
24
2,100
$ million
2013b
2,053
100
2,153
–
(225)
45
1,310
1,875
2,198
50.97
97.23
$ per barrel
107.38
a The operational and financial information of the Rosneft segment for 2015 is based on preliminary
operational and financial results of Rosneft for the three months ended 31 December 2015.
Actual results may differ from these amounts.
b From 21 March 2013.
c BP’s share of Rosneft’s earnings after finance costs, taxation and non-controlling interests is
included in the BP group income statement within profit before interest and taxation.
d Includes $16 million (2014 $25 million, 2013 $5 million) of foreign exchange losses arising on the
dividend received.
Market price
The price of Urals delivered in North West European (Rotterdam) averaged
$50.97/bbl in 2015, $1.42/bbl below dated Brent
. The differential to Brent
narrowed marginally from -$1.72/bbl in 2014 as stronger demand from
European refineries offset the impact of increased supplies of competing
medium sour crude from the Middle East.
Financial results
Replacement cost (RC) profit before interest and tax for the segment for
the year ended 31 December 2015 did not include any non-operating
items, whereas the 2014 result included a non-operating gain of $225
million, relating to Rosneft’s sale of its interest in the Yugragazpererabotka
joint venture .
After adjusting for non-operating items, the decrease in the underlying RC
profit before interest and tax compared with 2014 reflected lower oil
prices, foreign exchange, and comparatively favourable duty lag effects.
The rouble weakened against the US dollar during 2015. This impacts both
Rosneft’s earnings in roubles and BP’s share of the Rosneft result when it
is translated to US dollars. Compared with 2013, the 2014 result was
affected by an unfavourable duty lag effect, lower oil prices and other
items, partially offset by certain foreign exchange effects which had a
favourable impact on the result. See also Financial statements – Notes 16
and 31 for other foreign exchange effects.
Rosneft’s operations in West Siberia.
Defined on page 256.
39
BP Annual Report and Form 20-F 2015Strategic report
Other businesses
and corporate
Comprises our renewables business, shipping,
treasury and corporate activities including centralized
functions.
At our Tropical BioEnergia plant in Brazil we process sugar cane to
produce biofuels.
Financial performance
Sales and other operating revenuesa
RC profit (loss) before interest
2015
2,048
2014
1,989
$ million
2013
1,805
and tax
(1,768)
(2,010)
(2,319)
Net (favourable) unfavourable impact
of non-operating items
547
670
421
Underlying RC profit (loss) before
interest and tax
Capital expenditure and acquisitions
a Includes sales to other segments.
(1,221)
340
(1,340)
903
(1,898)
1,050
The replacement cost (RC) loss before interest and tax for the year ended
31 December 2015 was $1.8 billion (2014 $2.0 billion, 2013 $2.3 billion).
The 2015 result included a net charge for non-operating items of $547
million (2014 $670 million, 2013 $421 million).
After adjusting for these non-operating items, the underlying RC loss
before interest and tax for the year ended 31 December 2015 was
$1.2 billion, similar to prior year (2014 $1.3 billion, 2013 $1.9 billion).
Renewable energy
BP has the largest operated renewables business among our oil and
gas peers. Our activities are focused on biofuels and onshore wind.
Biofuels business model and strategy
Biofuels can be blended into traditional transport fuels without
significant engine modifications to existing fuel-delivery systems. BP is
working to produce biofuels that are low cost, low carbon, scalable and
competitive without subsidies.
Our main activity is in Brazil, where we operate three sugar cane mills
producing bioethanol and sugar, and exporting power made from sugar
cane waste to the local grid. We use our expertise and technology
capabilities to drive continuing improvements in operational efficiency.
Our strategy is enabled by:
• Safe and reliable operations – continuing to drive improvements in
personal, process and transport safety.
• Competitive sourcing – concentrating our efforts in Brazil, which
has one of the most cost-competitive biofuel feedstocks currently
available in the world.
• Low carbon – producing bioethanol supported by low-carbon power
generated from burning sugar cane waste. These processes reduce
life-cycle GHG emissions by around 70% compared with gasoline.
• Domestic and international markets – selling bioethanol
domestically in Brazil and also to international markets such as the
US and Europe through our integrated supply and trading function.
We are also investing in the development and commercialization of
biobutanol, in conjunction with our partner DuPont. Compared with
other biofuels, biobutanol has the potential to be blended with fuels in
higher proportions, and be easier to transport, store and manage. We
are also investigating a number of chemical applications for this
advanced biofuel.
Our performance summary
• We have reduced our recordable injury frequency by more than 60%
since the acquisition of Companhia Nacional de Açúcar e Álcool in
2011. For more information, see Safety on page 45.
• We increased our production of ethanol equivalent by 47% compared
with 2014 and generated 677GWh of power for Brazil’s national grid.
• We divested our interest in Vivergo Fuels – a UK-based joint
venture★ producing bioethanol from wheat – in May 2015.
• We are improving our agricultural operational performance with a
36% increase in cane harvester efficiency relative to 2014, and in
2015, we farmed a total planted area of 127,000 hectares.
BP Brazil biofuels production
(million litres of ethanol equivalent)
1,000
795
800
600
400
200
313
403
492
542
2011
2012
2013
2014
2015
Wind
We are among the top wind energy producers in the US. Our focus is
on safe operations and optimizing performance.
BP holds interests in 16 onshore wind farms in the US, and BP is the
operator of 14 of these. Our net generating capacity★ from this
portfolio, based on our financial stake, was 1,556 megawatts (MW) of
electricity at 31 December 2015.
40
BP Annual Report and Form 20-F 2015
BP also runs two wind farms in our refinery sites in the Netherlands,
operating on a much smaller scale and managed by our Downstream
segment, with 32MW of generating capacity.
Our net share of wind generation for 2015 was 4,424GWh, compared
with 4,617GWh a year ago. Lower power generation was primarily a
result of less windy weather across the US in 2015.
See our Sustainability Report or bp.com/renewables for additional
information on our renewable energy activities.
Shipping
The primary purpose of BP’s shipping and chartering activities is the safe
transportation of the group’s hydrocarbon products using a combination of
BP-operated, time-chartered and spot-chartered vessels. Surplus capacity may
also be used to transport third-party products. All vessels conducting BP
shipping activities are subject to our health, safety, security and environmental
requirements. At 31 December 2015, our fleet included four vessels
supporting operations in Alaska, 44 BP-operated and 40 time-chartered
vessels for our deep-sea, international oil and gas shipping operations. In
addition 28 deep-sea oil tankers and six LNG tankers are on order and planned
for delivery into the BP-operated fleet between 2016 and 2019. The first of
these new vessels, the British Respect oil tanker, was formally named at a
ceremony in November.
Treasury
Treasury manages the financing of the group centrally, with responsibility
for managing the group’s debt profile, share buyback programmes and
dividend payments, while ensuring liquidity is sufficient to meet group
requirements. It also manages key financial risks including interest rate,
foreign exchange, pension and financial institution credit risk. From
locations in the UK, US and Singapore, treasury provides the interface
between BP and the international financial markets and supports the
financing of BP’s projects around the world. Treasury trades foreign
exchange and interest-rate products in the financial markets, hedging
group exposures and generating incremental value through optimizing and
managing cash flows and the short-term investment of operational cash
balances. Trading activities are underpinned by the compliance, control
and risk management infrastructure common to all BP trading activities.
For further information, see Financial statements – Note 28.
Insurance
The group generally restricts its purchase of insurance to situations where
this is required for legal or contractual reasons. Some risks are insured with
third parties and reinsured by group insurance companies. This approach is
reviewed on a regular basis and if specific circumstances require such a
review.
Outlook
Other businesses and corporate annual charges, excluding non-operating
items, are expected to be around $1.2 billion in 2016.
Gulf of Mexico oil spill
BP reached agreements resolving the largest
remaining liabilities.
Shrimpers off the coast of Grand Isle in Louisiana.
Key events
• BP reached agreements in principle with the United States federal
government and five Gulf states in July to settle all federal and state
claims arising from the Deepwater Horizon accident and oil spill (the
incident). In addition, BP also settled the vast majority of claims made
by local government entities.
– The United States lodged a proposed Consent Decree with the
district court in October to resolve all United States and Gulf states
natural resource damage claims and all Clean Water Act penalty
claims. At the same time, BP entered a Settlement Agreement
with the Gulf states for economic, property and other losses.
– The proposed Consent Decree and the Settlement Agreement are
conditional on each other and neither will become effective unless
the court provides final approval of the Consent Decree.
• The final submission deadline for claims under the 2012 Plaintiffs’
Steering Committee settlements was 8 June 2015.
• By the end of 2015, the cumulative pre-tax income statement charge
as a result of the incident amounted to $55.5 billion. This excludes
amounts that BP does not consider possible to measure reliably at
this time.
Federal and state settlements
On 2 July 2015 BP announced that BP Exploration & Production Inc. (BPXP)
had reached agreements in principle to settle all federal and state claims
arising from the incident. The United States is expected to file a motion
with the court to enter the Consent Decree as a final settlement around the
end of March, which the court will then consider. Subject to final court
approval, payments under the terms of the agreements will be made
at a rate of around $1.1 billion a year for the majority of the 18-year
payment period.
See Legal proceedings on page 237 for further details including a summary
of what is not covered by the proposed Consent Decree and the
Settlement Agreement. For additional details on the financial impacts
see Financial statements – Note 2.
BP shipping reached a centenary of maritime achievement in April 2015.
★ Defined on page 256.
41
BP Annual Report and Form 20-F 2015Strategic report
Plaintiffs’ Steering Committee settlements
The Plaintiffs’ Steering Committee (PSC) was established to act on
behalf of individual and business plaintiffs in the multi-district litigation
proceedings in federal court in New Orleans (MDL 2179). In 2012 BP
reached settlements to resolve the substantial majority of legitimate
individual and business claims and medical claims stemming from the
incident. Approximately $2.3 billion was paid out under the PSC
settlements during 2015. Claims continue to be assessed and paid.
The medical benefits class action settlement provides for claims to be paid
to qualifying class members. The deadline for submitting claims under the
settlement was 12 February 2015.
Securities litigation and other legal proceedings
The multi-district litigation proceedings pending in federal court in
Houston (MDL 2185), including a purported class action on behalf of
purchasers of American depositary shares under US federal securities
law, are continuing. A jury trial is scheduled to begin in July 2016.
In MDL 2179, claims by individuals and businesses that opted out of the
PSC settlements or whose claims were excluded from them, including
claims for recovery of losses allegedly resulting from the 2010 federal
deepwater drilling moratoria and the related permitting processes, are
continuing.
BP is subject to additional legal proceedings in connection with the
incident. For more information see Legal proceedings on page 237.
Environmental restoration
In April 2011 BP committed to provide $1 billion in early restoration
funding to expedite recovery of natural resources injured as a result
of the incident. By the end of 2015 BP had provided approximately $762
million to support restoration projects, with the remaining $238 million
expected to be funded in 2016. The federal and state settlements referred
to above include more than $7 billion to resolve all natural resource damage
claims, which is in addition to this $1 billion.
Financial update
Analysis of cumulative $55.5 billiona charge to the
income statement ($ billion)
16
5
4
2
3
1. Spill response
2. Environmental
(cid:31)
(cid:31)
(cid:31) 3. Litigation and claimsb
(cid:31) 4. Clean Water Act penalties
(cid:31) 5. Other fines
(cid:31) 6. Functional costs
Total
14.3
8.6
22.6
4.1
4.5
1.4
55.5
a The cumulative income statement charge does not include
amounts that BP considers are not possible to measure
reliably at this time.
b The litigation and claims cost is net of recoveries of $5.7 billion.
The group income statement for 2015 includes a pre-tax charge of
$12.0 billion in relation to the incident. The charge for the year reflects the
amounts provided for the proposed Consent Decree; the Settlement
Agreement with the five Gulf states and local government claims as
described above; additional provisions made for business economic loss
claims under the PSC settlement and other items. As at 31 December
2015, the total cumulative charges recognized to date amounted to $55.5
billion. The total amounts that will ultimately be paid by BP in relation to all
the obligations relating to the incident are subject to uncertainty, and the
ultimate exposure and cost to BP and the timing of such costs will be
dependent on many factors, including in relation to any new information or
future developments. These could have a material impact on our
consolidated financial position, results and cash flows.
BP has provided for spill response costs, environmental expenditure,
litigation and claims and Clean Water Act penalties that can be measured
reliably. There continues to be uncertainty regarding the extent and timing
of the remaining costs and liabilities not covered by the proposed Consent
Decree and Settlement Agreement, including:
In May 2010 BP committed $500 million over 10 years to fund independent
scientific research through the Gulf of Mexico Research Initiative. BP had
contributed $278 million to the programme by the end of 2015.
• Claims asserted in civil litigation, including any further litigation by parties
excluded from, or parties who opted out of, the PSC settlement, and the
private securities litigation pending in MDL 2185.
See bp.com/gulfofmexico for further information on environmental and
economic restoration.
Process safety and ethics monitors
Two independent monitors – an ethics monitor and a process safety
monitor – were appointed under the terms of the criminal plea agreement
BP reached with the US government in 2012. Under the terms of the
agreement, BP is taking additional actions to further enhance ethics and
compliance and the safety of its drilling operations in the Gulf of Mexico.
The ethics monitor delivered an initial report early in 2015. He delivered a
second report later in the year under a separate administrative agreement
with the US Environmental Protection Agency. Recommendations from
the two reports largely relate to BP’s ethics and compliance programme
and code of conduct, including its implementation and enforcement. The
recommendations have been agreed and BP is now in the process of
implementing them. The ethics monitor is meanwhile conducting a
follow-up review as the next phase of his engagement.
The process safety monitor reviews and provides recommendations
concerning BPXP’s process safety and risk management procedures for
deepwater drilling in the Gulf of Mexico. BPXP is the BP group company
that conducts exploration and production operations in the Gulf of Mexico.
The process safety monitor also submitted a report in 2015. Following
discussions between BPXP, the process safety monitor and the US
Department of Justice, the recommendations have now been finalized and
implementation by BPXP is underway.
• The cost of business economic loss claims under the PSC settlement
not yet processed or processed but not yet paid (except where an
eligibility notice has been issued before the end of the month following
the balance sheet date and is not subject to appeal by BP within the
claims facility).
• Any obligation that may arise from securities-related litigation.
Payments made out of the $20-billion Deepwater Horizon Oil Spill Trust
(the Trust) during 2015 totalled $3.2 billion. As at 31 December 2015, the
aggregate cash balances in the Trust and the associated qualified
settlement funds amounted to $1.4 billion, nearly all of which was
committed to specific purposes including the seafood compensation fund
and natural resource damage early restoration projects. As of January
2016, payments in respect of claims and other costs previously funded
from the Trust are now being made by BP.
More details regarding the impacts and uncertainties relating to the
Gulf of Mexico oil spill can be found in Risk factors on page 53, Legal
proceedings on page 237 and Financial statements – Note 2.
42
BP Annual Report and Form 20-F 2015
Corporate responsibility
We believe we have a positive role to play in shaping
the long-term future of energy.
At our US Whiting refinery we have invested in new equipment to reduce
air emissions and implemented a monitoring system to provide air quality
information to the local community.
Safety
We continue to promote deep capability and a safe operating
culture across BP.
• Our operating management system (OMS) sets out BP’s principles
for good operating practice.
• By the end of 2015 we had completed all 26 recommendations from
BP’s internal investigation regarding the Deepwater Horizon accident,
the Bly Report.
• 52% of the 353 million hours worked by BP in 2015 were carried out
by contractors.
Process safety events
(number of incidents)
Tier 1
Tier 2
Loss of primary containment
400
300
200
100
2011
2012
2013
2014
2015
Recordable injury frequency
(workforce incidents per 200,000 hours worked)
American Petroleum Institute US benchmarka
International Association of Oil & Gas Producers benchmarka
0.8
0.6
0.4
0.2
Employees
Contractors
2011
0.31
0.41
2012
0.26
0.43
2013
0.25
0.36
2014
0.27
0.34
2015
0.20
0.28
a API and OGP 2015 data reports are not available until May 2016.
Additional information on our safety, environmental and social
performance is available in our sustainability report. Case
studies, country reports and an interactive tool for health, safety
and environmental data can be found at bp.com/sustainability
Group safety performance
In 2015 BP reported one workforce fatality in Turkey that occurred when a
ceiling collapsed during renovations at a recently acquired retail site. We
deeply regret the loss of this life and continue to focus efforts on
eliminating injuries and fatalities in our workplaces.
Personal safety performance
Recordable injury frequency (group)b
Day away from work case frequencyc
(group)b
Severe vehicle accident rated
2015
0.24
0.061
0.112
2014
0.31
0.081
0.132
2013
0.31
0.070
0.122
b Incidents per 200,000 hours worked.
c Incidents that resulted in an injury where a person is unable to work for a day (shift) or more.
d Number of vehicle incidents that result in death, injury, a spill, a vehicle rollover, or serious
disabling vehicle damage per one million kilometres travelled.
Process safety performance
Tier 1 process safety events★
Tier 2 process safety events
Loss of primary containment –
number of all incidentse
Loss of primary containment –
number of oil spillsf
Number of oil spills to land and water
Volume of oil spilled (thousand litres)
Volume of oil unrecovered
(thousand litres)
2015
20
83
235
146
55
432
142
2014
28
95
286
156
63
400
155
2013
20
110
261
185
74
724
261
e Does not include either small or non-hazardous releases.
f Number of spills greater than or equal to one barrel (159 litres, 42 US gallons).
We report our safety performance using industry metrics, including the
American Petroleum Institute (API) recommended practice 754. These
include tier 1 process safety events, defined as a loss of primary
containment causing harm to a member of the workforce, costly damage
to equipment or exceeding defined quantities. Tier 2 events are those of
lesser consequence than tier 1.
We seek to record all losses of primary containment regardless of the
volume of the release, and to report externally on losses over a severity
threshold. These include unplanned or uncontrolled releases from pipes,
containers or vehicles within our operational boundary, excluding releases
of non-hazardous substances such as water.
We have seen improvements in our process safety performance over the
past five years. This has been true across our upstream and downstream
businesses, with fewer tier 1 process safety events, fewer leaks and spills
and fewer recordable injuries. At the same time, the reliability of our rigs
and refineries has improved. We believe this shows that the rigour
needed to produce safe operations tends also to produce reliable
operations. We will maintain our focus on systematic safety management,
including self-verification and testing the effectiveness of our risk
mitigation measures.
Our figures for loss of primary containment in 2014 and 2015 include
increased reporting due to the introduction of enhanced automated
monitoring for remote sites in our US Lower 48 business. Using a
like-for-like approach with prior years’ reporting, our 2015 loss of primary
containment figure is 208 (2014 246).
Managing safety
We are working to continuously improve personal and process safety and
operational risk management across BP. Process safety is the application
of good design and engineering principles, as well as robust operating and
Defined on page 256.
43
BP Annual Report and Form 20-F 2015Strategic report
time to reflect BP’s priorities and experience or changing external
regulations. Any variations in the application of OMS – in order to meet
local regulations or circumstances – are subject to a governance process.
OMS also helps us improve the quality of our activities. All businesses
covered by OMS undertake an annual performance improvement cycle and
assess alignment with the applicable requirements of the OMS
framework. Recently acquired operations need to transition to OMS. See
page 45 for information about contractors and joint arrangements.
Security and crisis management
The scale and spread of BP’s operations means we must prepare for a
range of potential business disruptions and emergency events. We monitor
for, and aim to guard against, hostile actions that could cause harm to our
people or disrupt our operations, including physical and digital threats and
vulnerabilities.
Cyber attacks present a risk to the security of our information, IT systems
and operations. We maintain a range of defences to help prevent and
respond to this threat, including a 24-hour monitoring centre in the US and
employee cyber awareness programmes.
Improving reliability
Periodic breaks in production for planned maintenance are essential to
keep our operations running safely and reliably, but BP’s production in
the UK North Sea had suffered from unplanned shutdowns from
equipment failure on ageing infrastructure.
We also maintain disaster recovery, crisis and business continuity
management plans and work to build day-to-day response capabilities to
support local management of incidents. See page 47 for information on
BP’s approach to oil spill preparedness and response.
In 2013 we took action to address these unplanned shut-downs
through the development and implementation of reliability improvement
plans. These focused on three key areas: having spare equipment
available for parts that are particularly vulnerable; investing in getting
our basic maintenance activities right to prevent failures in the first
place; and learning from the equipment failures, by identifying the root
cause and sharing those learnings across the organization.
We are rolling these plans out across all five UK offshore assets and as
a result, our plant reliability has improved from 70% in 2014 to more
than 84% in 2015. We expect that this will not only improve production
and revenue, but also extend the life of our fields.
Prioritizing the safety and reliability of our operations.
Upstream safety
Key safety metrics 2011-2015
Recordable injury frequency
Loss of primary containment
Tier 1 process safety events
120
100
80
60
40
20
maintenance practices, to avoid accidents. Our approach builds on our
experience, including learning from incidents, operations audits, annual
risk reviews and sharing lessons learned with our industry peers.
BP-operated businesses are responsible for identifying and managing
operating risks and bringing together people with the right skills and
competencies to address them. They are required to carry out self-
verification and are also subject to independent scrutiny and assurance.
Our safety and operational risk team works alongside BP-operated
businesses to provide oversight and technical guidance, while our group
audit team visits sites on a risk-prioritized basis, including third-party
drilling rigs, to check how they are managing risks.
Each business segment has a safety and operational risk committee,
chaired by the business head, to oversee the management of safety and
operational risk in their respective areas of the business. In addition the
group operations risk committee facilitates the group chief executive’s
oversight of safety and operational risk management across BP.
The board’s safety, ethics and environment assurance committee
(SEEAC) receives updates from the group chief executive and the head
of safety and operational risk on the management of the highest priority
risks. SEEAC also receives updates on BP’s process and personal safety
performance, and the monitoring of major incidents and near misses
across the group. See Our management of risk on page 51 and SEEAC’s
report on page 71.
Operating management system
BP’s OMS is a group-wide framework designed to help us manage risks
and drive performance improvements in BP-operated businesses. 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.
We review and amend our group requirements within OMS from time to
2011
2012
2013
2014
2015
Indexed (2011=100)
Safety performance
Recordable injury frequency
Day away from work case frequency
Loss of primary containment
2015
0.21
0.034
2014
0.23
0.051
2013
0.32
0.068
incidents – number
153
187
143
Safer drilling
Our global wells organization is responsible for planning and executing our
wells operations across the world. It is also responsible for establishing
standards on compliance, risk management, contractor management,
performance indicators, technology and capability for our well operations.
Completing the Bly Report recommendations
We have completed all 26 recommendations made by BP’s investigation
into the Deepwater Horizon accident, the Bly Report, aimed at further
reducing risk across our global drilling activities.
Our group audit team has verified closure of the recommendations.
See bp.com/26recommendations for the Bly Report recommendations.
The BP board appointed Carl Sandlin as independent expert in 2012 to
provide an objective assessment of BP’s global progress in implementing
the recommendations from the Bly Report. He also provided process
safety observations and his views on the organizational effectiveness and
culture of the global wells organization.
Over the period of his appointment Mr Sandlin met regularly with wells
organization leadership and reviewed the standards and practices
developed to complete the recommendations. He made three visits to
each of the regional wells teams with active drilling operations, meeting
key personnel and drilling contractors on site.
44
BP Annual Report and Form 20-F 2015
Mr Sandlin’s engagement came to a close in February 2016 after he
reported to SEEAC that all 26 Bly Report recommendations had been
closed out to his satisfaction. He stated that the idea of safety as a top
priority is firmly ingrained throughout the global wells organization and
noted an increase in the degree of rigour and engagement at all levels.
Mr Sandlin recommended the organization build on the foundations
established by the recommendations and maintain its focus on continuous
improvement in the areas of safety culture, self-verification and training.
Safety performance
Recordable injury frequency
Day away from work case frequency
Severe vehicle accident rate
Loss of primary containment
incidents – number
2015
0.29
0.077
0.35
2014
0.44
0.067
0.48
2013
0.47
0.092
0.41
16
17
17
Downstream safety
Key safety metrics 2011-2015
Recordable injury frequency
Loss of primary containment
Tier 1 process safety events
120
100
80
60
40
20
2011
2012
2013
2014
2015
Indexed (2011=100)
Safety performance
Recordable injury frequency
Day away from work case frequency
Severe vehicle accident rate
Loss of primary containment
incidents – number
2015
0.26
0.092
0.09
2014
0.34
0.121
0.09
2013
0.25
0.063
0.10
66
82
101
We take measures to prevent leaks and spills at our refineries and other
downstream facilities throughout the design, maintenance and operation of
our equipment. We focus on managing the highest priority risks associated
with our storage, handling and processing of hydrocarbons. We also seek
to provide safe locations, emergency procedures and other mitigation
measures in the event of a release, fire or explosion.
Process safety expert
Duane Wilson’s three-year term as a board appointed process safety
expert for our downstream activities came to a close during 2015.
Mr Wilson provided an independent perspective on the progress that
BP’s fuels, lubricants and petrochemicals businesses have made toward
becoming industry leaders in process safety performance. Before leaving,
he shared his thoughts on possible areas for ongoing emphasis, such as
risk management, progress measurement and leadership.
Other businesses and corporate safety
We report on the combined safety performance of our biofuels, wind and
shipping businesses, as well as treasury and corporate activities, including
centralized functions.
Key safety metrics 2011-2015a
Recordable injury frequency
Loss of primary containment
Safety in our biofuels business
We have been working to deliver safe and reliable operations in our
Brazilian biofuels business since our acquisition of Companhia Nacional de
Açúcar e Álcool in 2011. We have done this by introducing a more
systematic approach to personal, process and transportation safety. For
example, we have segregated pedestrian access from several areas where
we operate machinery in our agricultural operations, reducing the likelihood
of injury to our workforce.
Working with contractors and partners
BP, like our industry peers, rarely works in isolation – we need to work with
contractors, suppliers and partners to carry out our operations. In 2015 52%
of the 353 million hours worked by BP were carried out by contractors.
Our ability to be a safe and responsible operator depends in part on the
capability and performance of those who help us carry out our operations.
We therefore work with our supply chain on areas such as safety,
operational performance, anti-bribery and corruption, money laundering and
human rights, and aim to have suitable provisions in our contracts with
contractors, suppliers and partners.
We seek to work with companies that share our commitment to ethical,
safe and sustainable working practices. We expect and encourage our
contractors and their employees to act in a way that is consistent with our
code of conduct. Our OMS includes requirements and practices for
working with contractors.
Contractors
We seek to set clear and consistent expectations of our contractors.
Our standard model contracts include health, safety, security and
environmental requirements, and most now include human rights
requirements. Bridging documents are necessary in some cases to define
how our safety management system and those of our contractors co-exist
to manage risk on a site.
Our partners in joint arrangements
We have a group framework for identifying and managing BP’s exposure
related to safety, operational, and bribery and corruption risk from our
participation in non-operated joint arrangements .
Typically, our level of influence or control over a joint arrangement is linked
to the size of our financial stake compared with other participants. In
some joint arrangements we act as the operator. Our OMS applies to the
operations of joint arrangements only where we are the operator.
In other cases, one of our partners may be the designated operator or the
operator may be an incorporated joint arrangement company owned by
BP and other companies. In those cases, our OMS does not apply as the
management system to be used by the operator, but is generally available
as a reference point when engaging with operators and co-venturers.
180
150
120
90
60
30
2011
2012
2013
2014
2015
Indexed (2011=100)
aThis does not include API tier 1 process safety events for our other businesses and
corporate as the current definition is not applicable in many cases.
Defined on page 256.
45
The Ocean Victory drilling rig in the Juniper field, Trinidad.
BP Annual Report and Form 20-F 2015Strategic report
Environment and society
Throughout the life cycle of our projects and operations, we
aim to manage the environmental and social impacts of our
presence.
• BP is helping to meet the demands of a lower-carbon future and
collaborating with others on climate change issues.
• BP-operated businesses with the potential to spill oil are on track to
complete updates to spill planning scenarios and response strategies
by the end of 2016.
• We are progressing towards alignment with the United Nations
Guiding Principles on Business and Human Rights.
Greenhouse gas emissionsabc
(MteCO
2 equivalent)
54.0
50.0
46.0
48.6
+0.6
+0.3
-1.0
+0.4
-0.1
48.9
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5
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a This is based on BP’s equity share basis (excluding BP’s share of Rosneft).
b The 2015 figure reflects our update of the global warming potential for methane from 21 to 25,
in line with IPIECA’s guidelines.
c Because of rounding, some totals may not agree exactly with the sum of their counterparts.
Managing our impacts
We review our management of material issues such as climate change,
water, how we work with communities and human rights. This includes
examining emerging risks and actions taken to mitigate them. We identify
areas for improvement and work to address these where appropriate.
Our operating sites can have a lifespan of several decades and our
operations are expected to work to reduce their impacts and risks. This
starts in early project planning and continues through operations and
decommissioning.
Our operating management system (OMS) includes practices that
set out requirements and guidance for how we identify and manage
environmental and social impacts. The practices apply to our major
projects , projects that involve new access and those that could affect an
international protected area.
In the planning stages of these projects we complete a screening process to
identify the most significant potential environmental and social impacts. We
completed this process for five projects in 2015. Following screening, projects
are required to carry out impact assessments, identify mitigation measures
and implement these in project design, construction and operations.
BP’s environmental expenditure in 2015 totalled $8,017 million (2014
$4,024 million, 2013 $4,288 million), including charges related to the Gulf
of Mexico oil spill. For a breakdown of environmental expenditure see
page 233.
Climate change
Meeting the climate challenge requires efforts by all – governments,
companies and consumers. We believe governments must lead by
providing a clear, stable and effective climate policy framework, including
putting a price on carbon – one that treats all carbon equally.
We expect that greenhouse gas (GHG) policy will have an increasing
impact on our businesses, operating costs and strategic planning, but may
also offer opportunities for the development of lower-carbon technologies
and businesses. There is a growing number of emission pricing schemes
46
globally, including in Europe, California and China, additional monitoring
regulations in the US, and more focus on reducing flaring and methane
emissions in many jurisdictions.
We are focusing on ways to reduce GHG emissions, including working to
improve the energy efficiency of our operations and our products. Around
half of our current upstream portfolio is natural gas, which produces about
half as much carbon dioxide (CO2) as coal per unit of power generated,
and we operate renewable businesses in biofuels and onshore wind.
We currently require larger projects, and those for which emissions costs
would be a material part of the project, to apply a standard carbon cost to
the projected GHG emissions over the life of the project. In industrialized
countries, our standard cost assumption is currently $40 per tonne of CO2
equivalent. We use this cost as part of the economic evaluation of the
investment.
We seek to address potential climate change impacts on our new projects
in the design phase. We have guidance for existing operations and
projects on how to assess potential climate risks and impacts – to enable
mitigation steps to be incorporated into project planning, design and
operations.
We are also working with our peers. For example, we are an active
participant in the Oil and Gas Climate Initiative, a voluntary, CEO-led
industry initiative that aims to catalyse meaningful action on climate
change through best practice sharing and collaboration. We also joined
with seven other oil and gas companies calling on the UN and
governments to put a price on carbon.
See bp.com/climatechange for more information about our activities.
Greenhouse gas emissions
We report on direct and indirect GHG emissions on a carbon dioxide-
equivalent (CO2e) basis. Direct emissions include CO2 and methane from
the combustion of fuel and the operation of facilities, and indirect
emissions include those resulting from the purchase of electricity, heat,
steam or cooling.
Our approach to reporting GHG emissions broadly follows the IPIECA/
API/IOGP Petroleum Industry Guidelines for Reporting GHG Emissions.
We calculate emissions based on the fuel consumption and fuel
properties for major sources rather than the use of generic emission
factors. We do not include nitrous oxide, hydrofluorocarbons,
perfluorocarbons and sulphur hexafluoride as they are not material and it
is not practical to collect this data.
Greenhouse gas emissions (MteCO2e)
Operational controla
Direct emissions
Indirect emissions
BP equity shareb
Direct emissions
Indirect emissions
2015
2014
2013
51.4c
7.0
48.9c
6.9
54.1
7.5d
48.6
6.8e
–
–
50.3
6.7f
a Operational control data comprises 100% of emissions from activities that are operated by BP,
going beyond the IPIECA guidelines by including emissions from certain other activities such as
contracted drilling activities. Data for emissions on an operational control basis was not available
prior to 2014. In 2014 we changed our GHG reporting boundary from a BP equity-share basis to
an operational control basis.
b BP equity share comprises our share of BP’s consolidated entities and equity accounted entities,
other than BP’s share of TNK-BP and Rosneft.
c The 2015 figure reflects our update of the global warming potential for methane from 21 to 25, in
line with IPIECA’s guidelines.
d The reported 2014 figure of 7.2Mte has been amended to 7.5Mte.
e The reported 2014 figure of 6.6Mte has been amended to 6.8Mte.
f The reported 2013 figure of 6.6Mte has been amended to 6.7Mte.
In 2015 we updated the global warming potential for methane from 21 to
25. Without this update, our reported direct emissions would have been
lower, primarily due to divestments in Alaska.
The ratio of our total GHG emissions reported on an operational control
basis to gross production was 0.24teCO2e/te production in 2015 (2014
0.25teCO2e/te). Gross production comprises upstream production,
refining throughput and petrochemicals produced.
See bp.com/greenhousegas for more information about our GHG
management and performance.
BP Annual Report and Form 20-F 2015
Water
BP recognizes the importance of managing fresh water use and water
discharges in our operations and we review our water risks annually. We
use industry-standard risk assessment tools, such as the IPIECA Global
Water Tool and the World Resources Institute Aqueduct Global Water
Atlas, to identify potential quantity, quality and regulatory risks across all
our operated assets. We are assessing different technology approaches
for optimizing water consumption and wastewater treatment
performance. For example, we have evaluated different approaches for
reducing fresh water use in our purified terephthalic acid operations, such
as wastewater recycling and sea water cooling.
We monitor the increasing number of regulations pertaining to freshwater
withdrawals and water discharge quality where we operate. This has led
to investments in our wastewater treatment plants at our refineries in
Europe and the US.
See bp.com/water for information about our approach to water.
Unconventional gas and hydraulic fracturing
Natural gas resources, including unconventional gas, have an increasingly
important role in supplying lower-carbon fuel to meet the world’s growing
energy needs. BP is working to responsibly develop and produce natural
gas from unconventional resources including shale gas, tight gas
coalbed methane. We have unconventional gas operations in Oman and
the US and we are evaluating unconventional gas opportunities in other
countries.
and
Some stakeholders have raised concerns about the potential
environmental and community impacts of hydraulic fracturing during
unconventional gas development. BP seeks to apply responsible well
design and construction, surface operation and fluid handling practices to
mitigate these risks.
Water and sand constitute on average 99.5% of the injection material
used in hydraulic fracturing. Some of the chemicals that are added to this,
when used in certain concentrations, are classified as hazardous by the
relevant regulatory authorities. BP works with service providers to
minimize their use where possible. We list the chemicals we use in the
fracturing process in material safety data sheets at each site. We also
submit data on chemicals used at our hydraulically fractured wells in the
US, to the extent allowed by our suppliers who own the chemical
formulas at fracfocus.org or other state-designated websites.
We are working to minimize air pollutant and GHG emissions, such as
methane, at our operating sites. For example, in the US we use a process
called green completions at our gas operations. This process captures
natural gas that would otherwise be flared or vented during the
completion and commissioning of wells.
Our US Lower 48 onshore business’s approach is to operate in line with
industry standards developed within the context of the highly regulated
US environment.
See bp.com/unconventionalgas for information about our approach to
unconventional gas and hydraulic fracturing.
Special resolution – strategic resilience for
2035 and beyond
A coalition of shareholders filed a special resolution in 2015 regarding
BP’s preparation for a lower-carbon future. The resolution, which was
supported by the BP board, requested that our reporting include
information in five areas:
Resolution element
Where reported
Ongoing operational
emissions management
Asset portfolio resilience
to post-2035 scenarios
Low-carbon energy R&D
and investment strategies
Strategic KPIs and
executive incentives
Public policy activities
BP Sustainability Report 2015, pages 17
and 42
How we are working to improve the
energy efficiency of our operations and
product use.
BP Sustainability Report 2015, page 18
BP Energy Outlook
BP Technology Outlook, page 8
How we adapt our investment strategy
to changes in policy, market or
technology conditions.
BP Sustainability Report 2015, page 16
Information on our gas, biofuels and
wind businesses, as well as our
research activities.
BP Annual Report 2015, pages 20 and 22
Information on how our executives are
currently rewarded.
BP Sustainability Report 2015, page 15
Our activities supporting our advocacy
for carbon pricing, along with working
with governments and peers on
methane and flaring reduction.
Find more online
bp.com/sustainabilityreport
bp.com/technologyoutlook
bp.com/energyoutlook
Oil spill preparedness and response
We are working to continuously improve how we control, contain and
clean up oil spills should they occur. Our requirements for oil spill
preparedness and response planning, and crisis management incorporate
what we have learned over many years of operation.
We updated our oil spill response plan requirements in 2012 to incorporate
learnings from the Deepwater Horizon accident. Revised response plans
include elements such as specialized modelling techniques to help predict
the impact of potential spills, provision of stockpiles of dispersant, and
the use of technologies like aerial and underwater robotic vehicles for
environmental monitoring. This is a substantial piece of work and
BP-operated businesses with the potential to spill oil are on track to
complete updates by the end of 2016.
We continue to investigate and test whether emerging technologies can
enhance our oil spill response capability. For example, in the Middle East,
we have trialled the use of satellite imagery as a way to identify oil spills
on land and track clean-up response time.
We seek to work collaboratively with government regulators in planning
for oil spill response, with the aim of improving any potential future
response. For example, in 2015 we participated in response exercises
with government regulators in regions such as Angola, the UK and US.
See page 43 for information on volume of oil spilled by our operations in
2015, including volume of oil unrecovered.
Defined on page 256.
47
Teams from BP Angola taking part in a shoreline oil spill response exercise
– the first international oil company event of its type in the country.
BP Annual Report and Form 20-F 2015Strategic report
Canada’s oil sands
BP is involved in three oil sands lease areas in Canada. Sunrise, operated
by Husky Energy, began producing oil in early 2015 and is currently
producing approximately 20,000 barrels per day. Pike, operated by Devon
Energy, is at the design stage. Terre de Grace, which is BP-operated, is
currently under appraisal for development.
Our decision to invest in Canadian oil sands activities takes into
consideration GHG emissions, impacts on the land, water use, local
communities and commercial viability.
See bp.com/oilsands for information on BP’s investments in Canada’s oil
sands.
Human rights
We are committed to conducting our business in a manner that respects
the rights and dignity of all people. 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. We set out our commitments in our human rights
policy. Our code of conduct references the policy, requiring employees to
report any human rights abuse in our operations or in those of our business
partners.
We are delivering our human rights policy by implementing the relevant
sections of the United Nations Guiding Principles on Business and Human
Rights (the Guiding Principles) and incorporating them into the processes
and policies that govern our business activities.
We are progressing towards alignment with the Guiding Principles using a
risk-based approach. This includes working across functions and
businesses in areas such as identifying and addressing human rights risks
and impacts, community and workforce grievance mechanisms, and
contracted workforce, working and living conditions and recruitment
processes.
In 2015 our actions included:
• Development and delivery of guidance, tools and training courses to
increase human rights awareness across the business.
• Inclusion of human rights clauses in an increasing number of our supplier
contracts.
• Evaluation of our community grievance mechanisms against the Guiding
Principles began at key sites to identify areas for improvement.
• Continued implementation of the Voluntary Principles on Security and
Human Rights, with periodic internal assessments to identify areas for
improvement.
See bp.com/humanrights for more information about our approach to
human rights.
Enterprise and community development
We run programmes to help build the skills of businesses and to develop
the local supply chain in a number of locations. In Indonesia, for example,
we have supported the foundation of local businesses, providing
community members with technical and hands-on training. In the UK we
support an apprenticeship programme in the North Sea run by one of our
contractors. The programme provides training on the skills required for the
safe and reliable operation of our offshore assets.
BP’s community investments support development that meets local
needs and are relevant to our business activities. We contributed
$67 million in social investment in 2015.
See bp.com/society for more information about our social contribution.
Business ethics and transparency
Our code of conduct defines our commitment to high
ethical standards.
• Our values and code of conduct set out the expected qualities and
actions of all our people.
• Our businesses dismissed 132 employees for non-conformance
with our code of conduct or unethical behaviour in 2015.
• We will begin to disclose information on payments made to
governments in 2016 as required by new UK regulations.
Our values
Safety
Respect
Excellence
Courage
One Team
Our values
Our values represent the qualities and actions we wish to see in BP, they
guide the way we do business and the decisions we make. We use these
values as part of our recruitment, promotion and individual performance
assessment processes.
See bp.com/values for more information.
The BP code of conduct
Our code of conduct is based on our values and clarifies the principles and
expectations for everyone who works at BP. It applies to all BP
employees, officers and members of the board.
Employees, contractors or other third parties who have a question about
our code of conduct or see something they feel to be unsafe, unethical or
potentially harmful can get help through OpenTalk, a confidential helpline
operated by an independent company.
A total of 1,158 people contacted OpenTalk with concerns or enquiries in
2015 (2014 1,114, 2013 1,121). The most common concerns related to the
people section of the code. This includes treating people fairly, with
dignity and giving everyone equal opportunity; creating a respectful,
harassment-free workplace; and protecting privacy and confidentiality.
48
Staff taking part in BP’s code of conduct training in Brazil.
BP Annual Report and Form 20-F 2015 We take steps to identify and correct areas of non-conformance and take
disciplinary action where appropriate. In 2015 our businesses dismissed
132 employees for non-conformance with our code of conduct or
unethical behaviour (2014 157, 2013 113). This excludes dismissals of staff
employed at our retail service stations.
See bp.com/codeofconduct for more information.
In addition to our code of conduct, we have policies on a variety of related
issues, including anti-bribery and corruption, political donations and
human rights.
Anti-bribery and corruption
Bribery and corruption are significant risks in the oil and gas industry. 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 dealings. Our code of conduct explicitly prohibits engaging in bribery
and corruption in any form.
Our group-wide anti-bribery and corruption policy applies to all BP-
operated businesses. The policy governs areas such as the inclusion of
appropriate clauses in contracts, risk assessments and training. We
provide training to those employees for whom we believe it is most
relevant, for example, depending on the nature or location of their role or
in response to specific incidents.
Lobbying and political donations
We do not use BP funds or resources to support any political candidate or
party. Employees’ rights to participate in political activity are governed by
the applicable laws in the countries in which we operate. For example, in
the US, BP provides administrative support to the BP employee political
action committee (PAC) to facilitate employee involvement and to assess
whether contributions comply with the law and satisfy all necessary
reporting requirements.
Tax and financial transparency
BP is committed to complying with tax laws in a responsible manner and
to having open and constructive relationships with tax authorities. BP
supports efforts to increase public trust in tax systems. We engage in
initiatives to simplify and improve tax regimes to encourage investment
and economic growth.
BP will start to disclose information on payments to governments on a
country-by-country and project basis in 2016. The disclosure is required
under the revenue transparency provisions contained in the EU
Accounting Directive, which was recently brought into effect in UK law.
We are awaiting the finalization and adoption of SEC rules under the US
Dodd-Frank Act.
As a founding member of the Extractive Industries Transparency Initiative
(EITI), BP works with governments, non-governmental organizations and
international agencies to improve transparency and disclosure of
payments to governments. We support governments’ efforts towards
EITI certification in countries where we operate and have worked with
many countries on implementation of their EITI commitments, including
Australia, Azerbaijan, Indonesia, Iraq, Norway, Trinidad & Tobago, the UK
and US.
See bp.com/tax for BP’s approach to tax.
Employees
BP’s performance depends on having a highly skilled,
motivated and talented workforce that reflects the diversity of
the societies in which we operate.
• Our goal is to create an environment of inclusion where our people are
treated with respect, dignity and without discrimination.
• We aim to develop the capabilities of our workforce with a focus on
the skills required to maintain safe and reliable operations.
• We are reducing activity in response to the current low-oil price
environment and some of this has resulted in job losses.
An employee at our service station in Twyford, UK. We are increasing the
footprint of our retail presence in many European countries and actively
recruiting in these markets.
BP employees
Number of employees at 31 Decembera
Upstream
Downstream
Other businesses and corporate
Total
Service station staff
Agricultural, operational and
seasonal workers in Brazil
Total excluding
service station staff
and workers in Brazil
2015
21,700
44,800
13,300
79,800
15,600
2014
24,400
48,000
12,100
84,500
14,400
2013
24,700
48,000
11,200
83,900
14,100
4,800
5,300
4,300
59,400
64,800
65,500
a Reported to the nearest 100. For more information see Financial statements – Note 34.
We aim to develop the capabilities of our workforce with a focus on the
skills required to maintain safe and reliable operations. As we adapt to the
current low oil price environment, we are reducing activity and simplifying
the way we work. Some of this has resulted in job losses. Our employee
headcount at the end of 2015 was 4,700 lower than the previous year.
Our total upstream workforce – including employees and contractors – is
now 20% smaller than it was in 2013, with a reduction of around 4,000
expected in 2016. We are aiming for an upstream workforce of approximately
20,000 by the end of 2016. We expect to reduce our downstream workforce
roles by more than 5,000 by the end of 2017 compared with 2014, excluding
service station staff and the reallocation of around 2,000 global business
services staff from Downstream to Other businesses and corporate in 2015.
By the end of 2015, we had already achieved a reduction of more than 2,000.
The group people committee, chaired by the group chief executive, has
overall responsibility for key policy decisions relating to employees and
governance of BP’s people management processes. In 2015 the
committee discussed longer-term people priorities, reward, progress in
our diversity and inclusion programme, employee engagement, and
improvements to our training and development programmes.
49
BP Annual Report and Form 20-F 2015Strategic report Employee engagement
Managers hold regular team and one-to-one meetings with their staff,
complemented by formal processes through works councils in parts of
Europe. We seek to maintain constructive relationships with labour
unions.
Each year, we conduct a survey to gather employees’ views on a wide
range of business topics and identify areas where we can improve.
We track how engaged employees are with our strategic priorities using
our group priorities index, based on questions about their perception of BP
as a business and how it is managed in terms of leadership and standards.
This measure fell to 69% in 2015 (2014 72%, 2013 72%).
Our survey results show a strong increase in understanding and use of the
code of conduct to guide behaviour and that employees remain clear
about compliance with safety procedures, standards and requirements.
However, as expected in the current low oil price environment, the
proportion of employees responding that they feel more confident about
BP’s future than they did the previous year has declined. We also saw a
decline in scores related to development and career opportunities.
We understand that employees have concerns about the consequences
of the lower oil price. We have established additional communications
channels to help address these concerns and support employees through
our restructuring processes. For example, our executive team has been
holding additional face-to-face town hall meetings. In our upstream
business we have introduced a dedicated inbox for queries and regular
listening sessions between frontline staff and management, with a
commitment to follow up on any issues raised.
Share ownership
We encourage employee share ownership and have a number of
employee share plans in place. For example, under our ShareMatch plan,
which operates in more than 50 countries, we match BP shares
purchased by our employees. We also operate a group-wide discretionary
share plan, which allows employee participation at different levels globally
and is linked to the company’s performance.
Attracting and retaining the right people
The complex projects we work on require a wide range of specialist skills
– from the capability to explore for new sources of energy through to those
required for transporting and distributing hydrocarbons safely around the
world. We have a bias towards building capability and promoting from
within the organization and complement this with selective external
recruitment. In 2015 90% of senior leadership roles were recruited from
within BP.
We decided to maintain graduate recruitment in 2015, albeit at a reduced
level, with a total of 298 graduates joining BP during the year (2014 670,
2013 814). We have worked to maintain our visibility in the graduate job
market to help us attract the best recruits, and provide them with high
quality early development opportunities. For the second consecutive year
BP was the highest ranked energy-sector company in the UK in The Times
Top 100 Graduate Employers.
In 2015 46% of our graduate intake were women and 41% were from
outside the UK and US.
Building in-house capability
We provide a broad range of development opportunities for our people
– from on-the-job learning and mentoring through to online and classroom-
based courses.
Through our internal academies, we provide leading technical, functional,
compliance and leadership learning opportunities. We have six academies,
focusing on our operating management system, petrotechnical skills,
downstream, midstream, leadership, and functional skills, including finance
and legal.
Diversity
As a global business, we aim for a workforce representative of the
societies in which we operate. We set out our ambitions for diversity and
our group people committee reviews performance on a quarterly basis.
Our aim is for women to represent at least 25% of group leaders – our
most senior managers – by 2020 and we are actively seeking qualified
female candidates for our board.
For more information on the composition of our board, see page 56.
Workforce by gender
Numbers as at 31 December
Board directors
Group leaders
Subsidiary directors
All employees
Male
12
350
1,099
54,581
Female
3
81
179
25,234
Female %
20%
19%
14%
32%
A total of 23% of our group leaders came from countries other than the
UK and US at the end of 2015 (2014 22%, 2013 22%). We have continued
to increase the number of local leaders and employees in our operations
so that they reflect the communities in which we operate. This is
monitored at a local, business and national level.
Inclusion
Our goal is to create an environment of inclusion and acceptance. For our
employees to be motivated and perform to their full potential, and for the
business to excel, our people need to be treated with respect and dignity
and without discrimination.
We aim to ensure equal opportunity in recruitment, career development,
promotion, training and reward for all employees – regardless of ethnicity,
national origin, religion, gender and gender identity, age, sexual
orientation, marital status, disability, or any other characteristic protected
by applicable laws. Where existing employees become disabled, our
policy is to provide continued employment and training wherever possible.
50
BP Annual Report and Form 20-F 2015 Our management of risk
BP manages, monitors and reports on the principal risks and uncertainties
that can impact our ability to deliver our strategy of meeting the world’s
energy needs responsibly while creating long-term shareholder value;
these risks are described in the Risk factors on page 53.
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 the board. The system seeks to avoid incidents and maximize
business outcomes by allowing us to:
BP’s group risk team analyses the group’s risk profile and maintains
the group risk management system. Our group audit team provides
independent assurance to the group 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.
Risk governance and oversight
Key risk governance and oversight committees include the following:
Executive committees
Executive team meeting – for strategic and commercial risks.
Group operations risk committee – for health, safety, security,
environment and operations integrity risks.
Group financial risk committee – for finance, treasury, trading and
cyber risks.
Group disclosure committee – for financial reporting risks.
• Understand the risk environment, and assess the specific risks and
Group people committee – for employee risks.
potential exposure for BP.
Group ethics and compliance committee – for legal and regulatory
• Determine how best to deal with these risks to manage overall
compliance and ethics risks.
potential exposure.
• Manage the identified risks in appropriate ways.
Resource commitment meeting – for investment decision risks.
• Monitor and seek assurance of the effectiveness of the management of
Board and its committees
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.
Our risk management activities
Day-to-day risk
management
Identify, manage
and report risks
Business and
strategic risk
management
Plan, manage
performance
and assure
Oversight and
governance
Set policy
and monitor
principal risks
Facilities,
assets and
operations
Business
segments
and functions
Executive
and corporate
functions
Board
Day-to-day risk management – management and staff at our facilities,
assets and functions 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 strong, sustainable performance. For example,
our operating management system (OMS)★ integrates BP requirements
on health, safety, security, environment, social responsibility, operational
reliability and related issues.
Business and strategic risk management – our businesses and
functions integrate risk 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 planning new activities.
Oversight and governance – functional leadership, the executive
team, the board and relevant committees provide oversight to identify,
understand and endorse management of significant risks to BP. They also
put in place systems of risk management, compliance and control to
mitigate these risks. Executive committees set policy and oversee the
management of significant risks, and dedicated board committees review
and monitor certain risks throughout the year.
BP board.
Audit committee.
Safety, ethics and environment assurance committee.
Geopolitical committee.
Gulf of Mexico committee.
Risk governance
For further information on risk management and internal control,
see page 93, and board and committee reports on page 64.
Risk management processes
As part of BP’s annual planning process, we review the group’s principal
risks and uncertainties. These may be updated throughout the year in
response to changes in internal and external circumstances.
We aim for a consistent basis of measuring risk to allow comparison on a
like-for-like basis, taking into account potential likelihood and impact, and to
inform how we prioritize specific risk management activities and invest
resources to manage them.
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.
We identify those risks as having a high priority for particular oversight by
the board and its various committees in the coming year. Those identified
for 2016 are listed on page 52. 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 throughout the business and in executive and board
committees.
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 53.
★ Defined on page 256.
51
BP Annual Report and Form 20-F 2015Strategic report 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 advisers who advise and conduct
assurance with respect to the management of security risks affecting our
people and operations. We also maintain disaster recovery, crisis and business
continuity management plans. We continue to monitor threats globally and, in
particular, the situation in the Middle East and North Africa.
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, adversely affect operational 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. Under the terms
of the 2012 criminal settlement with the US Department of Justice and the
2014 settlement with the US Environmental Protection Agency, an ethics
monitor is reviewing and providing recommendations concerning BP’s ethics
and compliance programme.
Find out more about our code of conduct and our business ethics on
page 48, and the ethics monitor on page 42.
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 employees.
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.
For further information see Upstream gas marketing and trading
activities on page 33, Downstream supply and trading on page 36
and Financial statements – Note 28.
Risks for particular oversight by the board and its
committees in 2016
The risks for particular oversight by the board and its committees in 2016
have been reviewed and updated. These risks remain the same as in 2015
other than the Gulf of Mexico oil spill and major project★ delivery risks,
which are no longer considered to require this additional oversight in 2016.
Financial resilience has been added to the high priority risks for particular
oversight in 2016. This update reflects the proposed settlements between
BP, the United States government and the five Gulf Coast states with
respect to federal and state claims arising from the oil spill, as well as
current market conditions. Both the Gulf of Mexico oil spill and major
project delivery risks will continue to be monitored as appropriate by the
board and its committees in the normal course of risk oversight and
management.
Strategic and commercial risks
Financial resilience
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, technological change, global
economic conditions and the influence of OPEC.
We actively manage this risk through BP’s diversified portfolio, our financial
framework, liquidity stress testing, regular reviews of market conditions and
our planning and investment processes.
For more information on our financial framework see page 18, Our
strategy on page 13, Our markets in 2015 on page 24 and Liquidity
and capital resources on page 219. See our Longer-term viability
statement on page 94.
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 actively manage this risk through development and maintenance
of relationships with governments and stakeholders and becoming trusted
partners in each country and region. In addition, we closely monitor events and
implement risk mitigation plans where appropriate. We established a new
board committee focusing on geopolitical risk in 2015.
Cybersecurity
The threats to the security of our digital infrastructure continue to evolve
rapidly and, like many other global organizations, our reliance on computers
and network technology is increasing. A cybersecurity breach could have a
significant impact on business operations.
We seek to manage this risk through a range of measures, which include
cybersecurity standards, ongoing monitoring of threats and testing of cyber
response procedures and equipment. We collaborate closely with
governments, law enforcement agencies and industry peers to understand
and respond to new and emerging cyber threats. Campaigns and
presentations on topics such as email phishing and protecting our information
and equipment have helped to raise employee awareness of these issues.
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 OMS helps us manage these risks and drive performance improvements.
It sets out the rules and principles 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 global wells organization in order to
promote a consistent approach for designing, constructing and managing
wells.
For more information on safety and our OMS see page 43.
52
BP Annual Report and Form 20-F 2015 access to financing or engagement in our trading activities on acceptable terms,
which could put pressure on the group’s liquidity. Credit rating downgrades
could 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 219 and Financial statements – Note 28.
Joint arrangements and contractors – we may have limited control
over the standards, operations and compliance of our partners, contractors
and sub-contractors.
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 risks 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 cybersecurity – breach of our digital security
or failure of our digital infrastructure could damage our operations and our
reputation.
A breach or failure of our digital infrastructure due to intentional actions such as
attacks on our cybersecurity, negligence or other reasons, could seriously
disrupt our operations and 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 potentially legal
liability. These could result in significant costs or reputational consequences.
Climate change and carbon pricing – public policies could increase
costs and reduce future revenue and strategic growth opportunities.
Changes in laws, regulations and obligations relating to climate change could
result in substantial capital expenditure, taxes and reduced profitability. In the
future, these could potentially impact our assets, revenue generation and
strategic growth opportunities.
Competition – inability to remain efficient, 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, or to sustain,
develop and operate a high-quality portfolio of assets efficiently. We could be
adversely affected if competitors offer superior terms for access rights or
licences, or if our innovation in areas such as exploration, production, refining or
manufacturing lags the industry. Our performance could also be negatively
impacted if we fail to protect our intellectual property.
Our industry faces increasing challenge to recruit and retain skilled and
experienced people in the fields of science, technology, engineering and
mathematics. Successful recruitment, development and retention of specialist
staff is essential to our plans.
Crisis management and business continuity – potential disruption to
our business and operations could occur if we do not address an incident
effectively.
Our business and operating 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. We typically bear losses as they arise rather than
spreading them over time through insurance premiums. This means 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.
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 subject to fluctuating
prices of oil, gas, 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 sources, technological change, global economic conditions 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 and ability to
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 and petrochemicals 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 – our inability to
access, renew and progress upstream resources in a timely manner
could adversely affect our long-term replacement of reserves.
Delivering our group strategy depends on our ability to continually replenish a
strong exploration pipeline of future opportunities to access and produce oil and
natural gas. Competition for access to investment opportunities, heightened
political and economic risks in certain countries where significant hydrocarbon
basins are located and increasing technical challenges and capital commitments
may adversely affect our strategic progress. This, and our ability to progress
upstream resources and sustain long-term reserves replacement, could impact
our future production and financial performance.
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. Operational challenges and poor investment
choice, efficiency or delivery at any major project that underpins production or
production growth could adversely affect our financial performance.
Geopolitical – we are exposed to a range of political developments and
consequent changes to the operating and regulatory environment.
We operate and may seek new opportunities in countries and regions where
political, economic and social transition may take place. Political instability,
changes to the regulatory environment or taxation, international sanctions,
expropriation or nationalization of property, civil strife, strikes, insurrections,
acts of terrorism and acts of war 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 further trade restrictions and other
sanctions, could adversely impact our income and investment in Russia. Our
ability to pursue business objectives and to recognize production and reserves
relating to Russia 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, manage or maintain sufficient liquidity and credit
could impact our ability to operate and result in financial loss. Trade and other
receivables, including overdue receivables, may not be recovered and a
substantial and unexpected cash call or funding request could disrupt our
financial framework or overwhelm our ability to meet our obligations.
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 credit ratings. This could potentially increase financing costs and limit
★ Defined on page 256.
53
BP Annual Report and Form 20-F 2015Strategic report Safety and operational risks
Process safety, personal safety, and environmental risks – we are
exposed to a wide range of health, safety, security and environmental risks
that could result in regulatory action, legal liability, increased costs, damage
to our reputation and potentially denial of our licence to operate.
Technical integrity failure, natural disasters, human error and other adverse
events or conditions could lead to loss of containment of hydrocarbons or other
hazardous materials, 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 system or other
policies and procedures will adequately identify all process safety, personal
safety and environmental risks or that all our operating activities will be
conducted in conformance with these systems. See Safety on page 43.
Such events, 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. We could as a result 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 could be greater than in other locations.
Drilling and production – challenging operational environments and other
uncertainties can impact drilling and production activities.
Our activities require high levels of investment and are often conducted in
extremely challenging environments which heighten the risks of technical
integrity failure and the impact of natural disasters. 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 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 business and 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 potentially impact our financial performance.
Failure to meet product quality standards could cause harm to people and the
environment, damage our reputation, result in regulatory action and legal
liability, and impact financial performance.
Compliance and control risks
US government settlements – our settlements with legal and regulatory
bodies in the US announced in November 2012 in respect of certain
charges related to the Gulf of Mexico oil spill may expose us to further
penalties, liabilities and private litigation or could result in suspension or
debarment of certain BP entities.
Settlements with the US Department of Justice (DoJ) and the US Securities
and Exchange Commission (SEC) impose significant compliance and remedial
obligations on BP and its directors, officers and employees, including the
appointment of an ethics monitor, a process safety monitor and an independent
third-party auditor. Failure to comply with the terms of these settlements could
result in further enforcement action by the DoJ and the SEC, expose us to
severe penalties, financial or otherwise, and subject BP to further private
litigation, each of which could impact our operations and have a material
adverse effect on the group’s reputation and financial performance. Failure to
satisfy the requirements or comply with the terms of the administrative
agreement with the US Environmental Protection Agency (EPA), under which
BP agreed to a set of safety and operations, ethics and compliance and
corporate governance requirements, could result in suspension or debarment of
certain BP entities.
Regulation – changes in the regulatory and legislative environment could
increase the cost of compliance, affect our provisions and limit our access
to new exploration opportunities.
Governments that award exploration and production interests may impose specific
drilling obligations, environmental, health and safety controls, controls over the
development and decommissioning of a field and possibly, nationalization,
expropriation, cancellation or non-renewal of contract rights. Royalties and taxes
tend to be high compared with those of other commercial activities, and in certain
jurisdictions there is a degree of uncertainty relating to tax law interpretation and
changes. Governments may change their fiscal and regulatory frameworks in
54
response to public pressure on finances, resulting in increased amounts payable to
them or their agencies.
Such factors could increase the cost of compliance, reduce our profitability in
certain jurisdictions, limit our opportunities for new access, 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. Potential changes to pension or financial market regulation
could also impact funding requirements of the group.
Following the Gulf of Mexico oil spill, there have been cases of additional
oversight and more stringent regulation of BP and other companies’ oil and gas
activities in the US and elsewhere, particularly relating to environmental, health
and safety controls and oversight of drilling operations, which could result in
increased compliance costs. In addition, we may be subjected to a higher
number of citations and level of fines imposed in relation to any alleged
breaches of safety or environmental regulations, which could result in increased
costs.
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, or non-compliance with the recommendations
of the ethics monitor appointed under the terms of the DoJ and EPA
settlements, could damage our reputation, result in litigation, regulatory action
and penalties.
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 and potentially damaging
our reputation. See Financial statements – Note 28.
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 systems and people. Failure to report data
accurately and in compliance with applicable standards could result in
regulatory action, legal liability and damage to our reputation.
Gulf of Mexico oil spill
There continues to be uncertainty regarding the extent and timing of the
remaining costs and liabilities relating to the Gulf of Mexico oil spill not
covered by the proposed Consent Decree and the Settlement Agreement.
The proposed Consent Decree between the United States, the five Gulf Coast
states and BP and the Settlement Agreement between BP and the Gulf Coast
states will, subject to these becoming effective, settle all federal and state
claims arising from the 2010 Gulf of Mexico oil spill. The proposed Consent
Decree and the Settlement Agreement are conditional upon each other and
neither will become effective until there is final approval of the Consent Decree.
There continues to be uncertainty regarding the extent and timing of the
remaining costs and liabilities relating to the Gulf of Mexico oil spill not covered
by the proposed Consent Decree and the Settlement Agreement. For items not
covered by the proposed Consent Decree and the Settlement Agreement and
for further information, see Financial statements – Note 2 and Legal
proceedings (page 237).
The Strategic report was approved by the board and signed on its behalf by
David J Jackson, company secretary on 4 March 2016.
BP Annual Report and Form 20-F 2015 Corporate
governance
56 Board of directors
60 Executive team
62
Introduction from the chairman
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63 The board in 2015
63 Board membership
63 Succession
63 Board meetings
63 Board evaluation
64 Board activity
64 Board focus in 2015
64 Strategy
64 Risk
64 Performance
64 Monitoring
65 Training and induction
65 Shareholder engagement
Institutional investors
66
66 Private investors
66 AGM
66 UK Corporate Governance Code compliance
66
International advisory board
66 How the board works
66 Role of the board
66 Key roles and responsibilities
66 Appointment and time commitment
67 Board diversity
68 Committee reports
68 Audit committee
71 Safety, ethics and environment assurance committee
73 Gulf of Mexico committee
74 Geopolitical committee
74 Chairman’s committee
75 Nomination committee
76 Directors’ remuneration report
76 Remuneration committee report
90 Non-executive directors
93 Directors’ statements
93 Statement of directors’ responsibilities
93 Risk management and internal control
94
94 Going concern
94
Fair, balanced and understandable
Longer-term viability
BP Annual Report and Form 20-F 2015
55
Board of directors
As at 4 March 2016
See BP’s board governance principles relating to director independence on page 244.
Board biographies
See bp.com/governance
Carl-Henric Svanberg
Chairman
Chair of the nomination and
chairman’s committees; attends
geopolitical, Gulf of Mexico, SEEAa
and remuneration committees
Bob Dudley
Group chief executive
Dr Brian Gilvary
Chief financial officer
Paul Anderson
Non-executive director
Chair of the SEEA committee;
member of the geopolitical, Gulf of
Mexico, nomination and chairman’s
committees
Alan Boeckmann
Non-executive director
Member of the SEEA, Gulf of
Mexico, remuneration and
chairman’s committees
Admiral Frank Bowman
Non-executive director
Member of the SEEA, geopolitical,
Gulf of Mexico and chairman’s
committees
Antony Burgmans
Non-executive director
Chair of the geopolitical committee;
member of the SEEA, remuneration,
chairman’s and nomination
committees
Cynthia Carroll
Non-executive director
Member of the SEEA, geopolitical,
nomination and chairman’s
committees
Ian Davis
Non-executive director
Chair of the Gulf of Mexico
committee; member of the
remuneration, nomination and
chairman’s committees
Professor Dame Ann Dowling
Non-executive director
Chair of the remuneration committee;
member of the SEEA, nomination
and chairman’s committees
Brendan Nelson
Non-executive director
Chair of the audit committee;
member of the nomination and
chairman’s committees
Phuthuma Nhleko
Non-executive director
Member of the audit, geopolitical and
chairman’s committees
Paula Rosput Reynolds
Non-executive director
Member of the audit and chairman’s
committees
Sir John Sawers
Non-executive director
Member of the SEEA, geopolitical
and chairman’s committees
Andrew Shilston
Senior independent director
Member of the audit, geopolitical,
remuneration, nomination and
chairman’s committees
David Jackson
Company secretary
a
Safety, ethics and environment assurance.
56
BP Annual Report and Form 20-F 2015
Carl-Henric Svanberg
Chairman
Tenure
Appointed 1 September 2009
Outside interests
Chairman of AB Volvo
Age 63 Nationality Swedish
Career
Carl-Henric Svanberg became chairman
of the BP board on 1 January 2010.
He spent his early career at Asea Brown
Boveri and the Securitas Group, before
moving to the Assa Abloy Group as
president and chief executive officer.
From 2003 until 31 December 2009,
when he left to join BP, he was
president and chief executive officer of
Ericsson, also serving as the chairman
of Sony Ericsson Mobile
Communications AB. He was a
non-executive director of Ericsson
between 2009 and 2012. He was
appointed chairman and a member of
the board of AB Volvo in April 2012.
He is a member of the External Advisory
Board of the Earth Institute at Columbia
University and a member of the
Advisory Board of Harvard Kennedy
School. He is also the recipient of the
King of Sweden’s medal for his
contribution to Swedish industry.
Relevant skills and experience
Carl-Henric Svanberg is a highly
experienced leader of global
corporations. He has served as both
chief executive officer and chairman to
high profile businesses, giving him a
deep understanding of international
strategic and commercial issues. His
experience allows him to co-ordinate the
diverse range of knowledge and skills
provided by the board.
Bob Dudley
Group chief executive
Tenure
Appointed to the board 6 April 2009
Outside interests
Non-executive director of Rosneft
Member of Tsinghua Management
University Advisory Board,
Beijing, China
Member of BritishAmerican Business
International Advisory Board
Member of UAE/UK CEO Forum
Member of the Emirates Foundation
Board of Trustees
Member of the World Economic Forum
(WEF) International Business Council
Chair of the WEF Oil and Gas Climate
Initiative
Member of the Russian Geographical
Society Board of Trustees
Fellow of the Royal Academy of
Engineering
Age 60 Nationality American
Career
Bob Dudley became group chief
executive on 1 October 2010.
Career
Dr Brian Gilvary was appointed chief
financial officer on 1 January 2012.
SEEAC with that of the audit committee,
to provide a cohesive and robust
overview of business risks.
Bob joined Amoco Corporation in 1979,
working in a variety of engineering and
commercial posts. Between 1994 and
1997, he worked on corporate
development in Russia. In 1997 he
became general manager for strategy
for Amoco and in 1999, following the
merger between BP and Amoco, was
appointed to a similar role in BP.
Between 1999 and 2000, he was
executive assistant to the group chief
executive, subsequently becoming
group vice president for BP’s
renewables and alternative energy
activities. In 2002 he became group vice
president responsible for BP’s upstream
businesses in Russia, the Caspian
region, Angola, Algeria and Egypt.
From 2003 to 2008 he was president
and chief executive officer of TNK-BP.
On his return to BP in 2009 he was
appointed to the BP board and oversaw
the group’s activities in the Americas
and Asia. Between 23 June and 30
September 2010 he served as the
president and chief executive officer of
BP’s Gulf Coast Restoration
Organization in the US. He was
appointed a director of Rosneft in 2013
following BP’s acquisition of a stake in
Rosneft.
Relevant skills and experience
Bob Dudley has spent his whole career
in the oil and gas industry. He has held
senior management roles in Amoco and
BP and as the chief executive officer of
TNK-BP from 2003 to 2008.
Over the five years that he has been
group chief executive, Bob has
transformed BP into a safer, stronger
and simpler business. By focusing the
group’s approach on value not volume
and operating through a set of
consistent values, Bob has guided BP’s
recovery to a position of greater
resilience, to enable it to continue
delivering results in an uncertain
economic environment.
Dr Brian Gilvary
Chief financial officer
Tenure
Appointed to the board 1 January 2012
Outside interests
Visiting professor at Manchester
University
External advisor to director general
(spending and finance), HM
Treasury Financial Management
Review Board
Nominated for appointment by the AGM
as a non-executive director of L’Air
Liquide S.A. from May 2016
Member of the 100 Group Committee
GB Age Group triathlete
Age 54 Nationality British
He joined BP in 1986 after obtaining a
PhD in mathematics from the University
of Manchester. Following a variety of
roles in the Upstream, Downstream and
trading in Europe and the US, he
became Downstream’s chief financial
officer and commercial director from
2002 to 2005. From 2005 to 2009 he
was chief executive of the integrated
supply and trading function, BP’s
commodity trading arm. In 2010 he was
appointed deputy group chief financial
officer with responsibility for the finance
function.
He was a director of TNK-BP over two
periods, from 2003 to 2005 and from
2010 until the sale of the business and
acquisition of Rosneft equity in 2013.
Brian will also take on accountability for
integrated supply and trading and
shipping during 2016.
Relevant skills and experience
Dr Brian Gilvary has spent his entire
career with BP. He has a strong
knowledge of finance and trading, a
deep understanding of BP’s assets and
businesses and has very broad
experience of the business as a whole.
Brian has been instrumental in
transforming BP’s capital structure and
operational costs during its recovery and
as it adjusts to a low oil price
environment, while ensuring the group
is capable of meeting new opportunities
going forward.
Paul Anderson
Independent non-executive director
Tenure
Appointed 1 February 2010
Outside interests
No external appointments
Age 70 Nationality American
Career
Paul Anderson was formerly chief
executive at BHP Billiton and Duke
Energy, where he also served as
chairman of the board. Having previously
been chief executive officer and
managing director of BHP Limited and
then BHP Billiton Limited and BHP
Billiton Plc, he rejoined these latter two
boards in 2006 as a non-executive
director, retiring in January 2010.
Previously he served as a non-executive
director of BAE Systems PLC and on a
number of boards in the US and
Australia, and was also chief executive
officer of Pan Energy Corp.
Relevant skills and experience
Paul Anderson has spent his career in
the energy industry working with global
organizations, and brings the skills of an
experienced chairman and chief
executive officer to the board. As
chairman of the SEEAC since 2012, he
has maintained the board’s focus on
safety and broader non-financial issues.
This year he has worked with Brendan
Nelson to integrate the oversight of the
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His experience of business in the US
and its regulatory environment has
greatly assisted the work of the Gulf of
Mexico committee and is an asset to the
geopolitical committee.
Alan Boeckmann
Independent non-executive director
Tenure
Appointed 24 July 2014
Outside interests
Non-executive director of Sempra
Energy
Non-executive director of Archer Daniels
Midland
Age 67 Nationality American
Career
Alan Boeckmann retired as non-
executive chairman of Fluor Corporation
in February of 2012, ending a 35-year
career with the company. Between
2002 and 2011, he held the post of
chairman and chief executive officer and
was president and chief operating
officer from 2001 to 2002. His tenure
with the company included
responsibility for global operations. As
chairman and CEO, he refocused the
company on engineering, procurement,
construction and maintenance services.
After graduating from the University of
Arizona with a degree in electrical
engineering, he joined Fluor in 1974 as
an engineer and worked in a variety of
domestic and international locations,
including South Africa and Venezuela.
Alan was previously a non-executive
director of BHP Billiton and the
Burlington Santa Fe Corporation and has
served on the boards of the American
Petroleum Institute and the National
Petroleum Council. He was also a board
member and trustee of the Eisenhower
Medical Center in Rancho Mirage,
California and the Advisory Board of
Southern Methodist University’s Cox
School of Business.
He led the formation of the World
Economic Forum’s ‘Partnering Against
Corruption’ Initiative in 2004.
Relevant skills and experience
Alan Boeckmann has been a chairman
and chief executive officer in the
worldwide engineering and construction
industry and in the energy sector. He
brings deep experience to the board and
in his roles on the SEEAC and Gulf of
Mexico committee, not only from his
profession as an engineer but also of
international project management and
procurement.
Alan joined the remuneration committee
in 2015.
BP Annual Report and Form 20-F 2015
57
Admiral Frank
Bowman
Independent non-executive director
Tenure
Appointed 8 November 2010
Outside interests
President of Strategic Decisions, LLC
Director of Morgan Stanley
Mutual Funds
Director of Naval and Nuclear
Technologies, LLP
Age 71 Nationality American
Career
Frank L Bowman served for more than
38 years in the US Navy, rising to the
rank of Admiral. He commanded the
nuclear submarine USS City of Corpus
Christi and the submarine tender USS
Holland. After promotion to flag officer,
he served on the joint staff as director of
political-military affairs and as the chief
of naval personnel. He served over eight
years as director of the Naval Nuclear
Propulsion Program where he was
responsible for the operations of more
than one hundred reactors aboard the
US navy’s aircraft carriers and
submarines. He holds two masters
degrees in engineering from the
Massachusetts Institute of Technology.
After his retirement as an Admiral in
2004, he was president and chief
executive officer of the Nuclear Energy
Institute until 2008. He served on the
BP Independent Safety Review Panel
and was a member of the BP America
External Advisory Council. He was
appointed Honorary Knight Commander
of the British Empire in 2005. He was
elected to the US National Academy of
Engineering in 2009.
Frank is a member of the CNA military
advisory board and has participated in
studies of climate change and its impact
on national security. Additionally he was
co-chair of a National Academies study
investigating the implications of climate
change for naval forces.
Relevant skills and experience
Frank Bowman brings exceptional
experience in safety issues arising from
his time with the US Navy and the
Nuclear Energy Institute, coupled with
direct knowledge of BP’s safety goals
from his work on the BP Independent
Safety Review Panel. He also has a
broad perspective of systems and of
people from the many other roles
throughout his career.
He has built on this experience with the
Gulf of Mexico and SEEA committees
since 2010 and his background and
experience of US and global political and
regulatory systems are valuable assets
to the geopolitical committee.
58
Antony Burgmans
Independent non-executive director
Tenure
Appointed 5 February 2004
Outside interests
Member of the supervisory board of
SHV Holdings NV
Chairman of the supervisory board of
TNT Express
Chairman of Akzo Nobel NV
Age 69 Nationality Dutch
Career
Antony Burgmans joined Unilever in
1972, holding a succession of marketing
and sales posts, including the
chairmanship of PT Unilever Indonesia
from 1988 until 1991.
In 1991, he was appointed to the board
of Unilever, becoming business group
president, ice cream and frozen foods
Europe in 1994, and chairman of
Unilever’s Europe committee,
co-ordinating its European activities. In
1998, he became vice chairman of
Unilever NV and in 1999, chairman of
Unilever NV and vice chairman of
Unilever PLC. In 2005 he became
non-executive chairman of Unilever NV
and Unilever PLC until his retirement in
2007. During his career he has lived and
worked in London, Hamburg, Jakarta,
Stockholm and Rotterdam.
Relevant skills and experience
Antony Burgmans is an experienced
chairman and chief executive who spent
his executive career at Unilever where
he developed skills in production,
distribution and marketing.
His experience of consumer facing
business has meant that he has been
able to provide the board with deep
insight in the fields of reputation, brand,
culture and values. He has served on
the board for 12 years and has made a
major contribution to the SEEA and
remuneration committees and latterly
through chairing the geopolitical
committee.
Cynthia Carroll
Independent non-executive director
Tenure
Appointed 6 June 2007
Outside interests
Chair of Vedanta Resources Holding Ltd
Non-executive director of Hitachi Ltd
Age 59 Nationality American
Career
Cynthia began her career as a petroleum
geologist with Amoco Production
company in Denver, Colorado, after
completing a masters degree in geology.
In 1989 she joined Alcan (Aluminum
Company of Canada) and ran a
packaging company, led a global bauxite,
alumina and speciality chemicals
business and later was president and
chief executive officer of the Primary
Metal Group, responsible for operations
in more than 20 countries. In 2007
she became chief executive of Anglo
American plc, the global mining group,
operating in 45 countries with 150,000
employees, and was chairman of
De Beers s.a. and Anglo Platinum
Limited. She stepped down from
these roles in April 2013.
Relevant skills and experience
Cynthia Carroll has led multiple large
complex global businesses in the
extractive industries. This has required
deep strategic and operational
involvement. In leading these
businesses a high level of interaction
with governments, the media, special
interest groups and other stakeholders
has been needed.
Cynthia is an experienced former chief
executive who has spent all of her
career in the extractive industries,
having trained as a petroleum geologist.
Her leadership experience related to
enhancing safety in the mining industry
brings a strong contribution to the work
of the SEEAC, as does her
understanding of business strategy in an
industry with a long capital return cycle.
Her international experience with
governments is an asset to the
geopolitical committee.
Ian Davis
Independent non-executive director
Tenure
Appointed 2 April 2010
Outside interests
Chairman of Rolls-Royce Holdings plc
Non-executive director of Majid Al
Futtaim Holding LLC
Non-executive director of Johnson &
Johnson Inc
Non-executive director of Teach for All
Age 64 Nationality British
Career
Ian Davis is senior partner emeritus of
McKinsey & Company. He was a
partner at McKinsey for 31 years until
2010 and served as chairman and
managing director between 2003 and
2009.
Ian has a MA in Politics, Philosophy and
Economics from Balliol College,
University of Oxford.
Relevant skills and experience
Ian Davis brings the skills of a managing
director with significant financial and
strategic experience to the board. He has
worked with and advised global
organizations and companies in a wide
variety of sectors including oil and gas
and the public sector, enabling him to
draw on knowledge of diverse issues
and outcomes to assist the board. His
role in the Cabinet Office, from which he
stepped down in March 2016, gives him
a unique perspective on government
affairs.
He has chaired the Gulf of Mexico
committee since its formation and has
led the board’s oversight of the response
in the Gulf.
Professor Dame Ann
Dowling
Independent non-executive director
Tenure
Appointed 3 February 2012
Outside interests
President of the Royal Academy of
Engineering
Deputy vice-chancellor and Professor
of Mechanical Engineering at the
University of Cambridge
Member of the Prime Minister’s Council
for Science and Technology
Non-executive director of the
Department for Business, Innovation
& Skills (BIS)
Age 63 Nationality British
Career
Dame Ann Dowling is a deputy
vice-chancellor at the University of
Cambridge, where she was appointed a
professor of mechanical engineering in
the department of engineering in 1993.
She was head of the department of
engineering at the University of
Cambridge from 2009 to 2014. Her
research is in fluid mechanics, acoustics
and combustion, and she has held
visiting posts at MIT and at Caltech. She
was appointed director of the University
Gas Turbine Partnership with
Rolls-Royce in 2001, and chairman in
2009. Between 2003 and 2008 she
chaired the Rolls-Royce propulsion and
power systems advisory board and now
chairs BP’s technical advisory
committee.
She is a fellow of the Royal Society and
the Royal Academy of Engineering and
is a foreign associate of the US National
Academy of Engineering and the French
Academy of Sciences. She has honorary
degrees from nine universities, including
the University of Oxford, Imperial
College London and the KTH Royal
Institute of Technology, Stockholm.
She was elected President of the Royal
Academy of Engineering in September
2014. In December 2015 she was
appointed to the Order of Merit, which
is in the sole gift of the Queen and
limited to just 24 members.
Relevant skills and experience
Dame Ann Dowling is an internationally
respected leader in engineering
research and the practical application of
new technology in industry. The
department of engineering at
Cambridge University that she led is one
of the leading centres for engineering
research worldwide, and her
contribution has been widely recognized
by universities around the world. She
chairs BP’s technical advisory
committee and makes a significant
contribution to the work of the SEEAC.
Dame Ann became chair of the
remuneration committee in 2015 and
has spent time with key shareholders to
listen and reflect their views in the work
of the committee.
BP Annual Report and Form 20-F 2015
Paula has led several groups through
restructuring and mergers so can
contribute knowledge and experience to
the board when considering
simplification and value creation.
Andrew Shilston
Senior independent non-executive
director
Tenure
Appointed 1 January 2012
Outside interests
Chairman of Morgan Advanced
Materials plc
Non-executive director of Circle
Holdings plc
Age 60 Nationality British
Career
Andrew Shilston trained as a chartered
accountant before joining BP as a
management accountant. He
subsequently joined Abbott
Laboratories before moving to
Enterprise Oil plc in 1984 at the time of
flotation. In 1989 he became treasurer
of Enterprise Oil and was appointed
finance director in 1993. After the sale
of Enterprise Oil to Shell
in 2002, in 2003 he became finance
director of Rolls-Royce plc until his
retirement in December 2011.
He has served as a non-executive
director on the board of Cairn Energy plc
where he chaired the audit committee.
Relevant skills and experience
Andrew Shilston is a highly
knowledgeable director with wide
experience from roles in finance, from
several positions as a chief financial
officer, and the oil and gas industry in
general. His deep understanding of
commercial issues has assisted the
board in its work in overseeing the
group’s strategy and in particular the
evaluation of capital projects, while his
financial skills are an asset to both the
audit and remuneration committees.
As senior independent director he has
overseen the evaluation of the chairman
and led the external evaluation of the
board in 2015.
David Jackson
Company secretary
Tenure
Appointed 2003
David Jackson, a solicitor, is a director of
BP Pension Trustees Limited.
Sir John Sawers
Independent non-executive director
Tenure
Appointed 14 May 2015
Outside interests
Chairman and partner of Macro Advisory
Partners LLP
Visiting professor at King’s College
London
Governor, Ditchley Foundation
Age 60 Nationality British
Career
John Sawers spent 36 years in public
service in the UK, working on foreign
policy, international security and
intelligence.
John was Chief of the Secret
Intelligence Service, MI6, from 2009 to
2014, a period of international upheaval
and growing security threats as well as
closer public scrutiny of the intelligence
agencies. Prior to that, the bulk of his
career was in diplomacy, representing
the British government around the world
and leading negotiations at the UN, in
the European Union and in the G8. He
was the UK ambassador to the United
Nations (2007-09), political director and
main board member of the Foreign
Office (2003-07), special representative
in Iraq (2003), ambassador to Egypt
(2001-03) and foreign policy advisor to
the Prime Minister (1999-2001). Earlier
in his career, he was posted to
Washington, South Africa, Syria and
Yemen.
John is now chairman of Macro
Advisory Partners, a firm which advises
clients on the intersection of policy,
politics and markets.
Relevant skills and experience
Sir John Sawers’ deep experience of
international political and commercial
matters is an asset to the board in
navigating the complex issues faced by
a modern global company. His
management of reform at MI6 also
complements BP’s focus on value and
simplification.
As a former UK government
representative, Sir John brings
knowledge and skills related to
analysing and negotiating on a
worldwide basis, which are invaluable to
the geopolitical and SEEA committees.
Brendan Nelson
Independent non-executive director
Tenure
Appointed 8 November 2010
Outside interests
Non-executive director and chairman of
the group audit committee of
The Royal Bank of Scotland Group plc
Member of the Financial Reporting
Review Panel
Age 66 Nationality British
Career
Brendan Nelson is a 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.
He served for six years as a member of
the Financial Services Practitioner Panel
and in 2013 was the president of the
Institute of Chartered Accountants of
Scotland.
Relevant skills and experience
Brendan Nelson’s career in audit and
finance makes him ideally suited to chair
the audit committee and to act as its
financial expert. He held a range of
senior leadership roles at KPMG giving
him broad management and business
experience. His specialism in the
financial services industry allows him to
contribute insight into the challenges
faced by global businesses by regulatory
frameworks.
Brendan brings related input from his
role as the chair of the audit committee
of a major bank and as a member of the
Financial Reporting Review Panel.
Phuthuma Nhleko
Independent non-executive director
Tenure
Appointed 1 February 2011
Outside interests
Non-executive director and chairman of
MTN Group Ltd
Chairman of the Pembani Group
Age 55 Nationality South African
Career
Phuthuma Nhleko began his career as a
civil engineer in the US and as a project
manager for infrastructure
developments in southern Africa.
Following this he became a senior
executive of the Standard Corporate and
Merchant Bank in South Africa. He later
held a succession of directorships
before joining MTN Group, a pan-African
and Middle Eastern telephony group
represented in 21 countries, as group
president and chief executive officer in
2002. During his tenure at the MTN
Group he led a number of substantial
mergers and acquisitions transactions.
He stepped down as group chief
executive of MTN Group at the end of
March 2011. He was formerly a director
of a number of listed South African
companies, including Johnnic Holdings
(formerly a subsidiary of the Anglo
American group of companies),
Nedbank Group, Bidvest Group and
Alexander Forbes.
Relevant skills and experience
Phuthuma Nhleko has had a wide-
ranging career in infrastructure, banking
and telephony as well as the extractive
industries. This broad experience
leading multinational companies,
particularly in emerging markets,
enables him to contribute strongly to the
board and geopolitical committee on
strategic matters. His commercial
experience also gives him insight into
financial issues relevant to the audit
committee.
Paula Rosput
Reynolds
Independent non-executive director
Tenure
Appointed 14 May 2015
Outside interests
Non-executive director of BAE Systems
Ltd
Non-executive director of
TransCanada Corporation
Non-executive director of Siluria
Technologies
Age 59 Nationality American
Career
Paula Rosput Reynolds is the former
chairman, president and chief executive
officer of Safeco Corporation, a Fortune
500 property and casualty insurance
company that was acquired by Liberty
Mutual Insurance Group in 2008. She
also served as vice-chair and chief
restructuring officer for American
International Group (AIG) for a period
after the US government became the
financial sponsor from 2008 to 2009.
Previously Paula was an executive in the
energy industry. She was chairman,
president and chief executive officer of
AGL Resources Inc., an operator of
natural gas infrastructure in the US. Prior
to this, she led a subsidiary of Duke
Energy Corporation that was a merchant
operator of electricity generation. She
commenced her energy career at PG&E
Corp.
She currently chairs the board of the
Fred Hutchinson Cancer Research
Center in Seattle, Washington. In 2014
Paula was awarded the National
Association of Corporate Directors (US)
Lifetime Achievement Award.
Relevant skills and experience
Paula Rosput Reynolds has had a long
career leading global companies in the
energy and financial sectors. Her
experience with international and US
companies gives her insight into
strategic and regulatory issues, and her
financial background is an asset to the
audit committee.
59
Corporate governanceBP Annual Report and Form 20-F 2015
Prior to this, Bob was chief executive
of BP Angola and also held several
management positions in Trinidad,
including chief operating officer for
Atlantic LNG and vice president of
operations. Bob has also served in a
variety of engineering and management
positions in onshore US and deepwater
Gulf of Mexico.
During 2016 Bob will also take on
accountability for remediation
management.
Career
Tufan Erginbilgic was appointed chief
executive, Downstream on 1 October
2014.
Prior to this, Tufan was the chief
operating officer of the fuels business,
accountable for BP’s fuels value chains
worldwide, the global fuels businesses
and the refining, sales and commercial
optimization functions for fuels. Tufan
joined Mobil in 1990 and BP in 1997
and has held a wide variety of roles in
refining and marketing in Turkey, various
European countries and the UK.
In 2004 he became head of the European
fuels business. Tufan took up leadership
of BP’s lubricant business in 2006 before
moving to head the group chief
executive’s office. In 2009 he became
chief operating officer for the eastern
hemisphere fuels value chains and
lubricants businesses.
Andy Hopwood
Current position
Chief operating officer, strategy and
regions, Upstream
Executive team tenure
Appointed 1 November 2010
Outside interests
No external appointments
Age 58 Nationality British
Career
Andy Hopwood is responsible for BP’s
upstream strategy, portfolio, and
leadership of its global regional
presidents.
Andy joined BP in 1980, spending his
first 10 years in operations in the North
Sea, Wytch Farm, and Indonesia. In 1989
Andy joined the corporate planning team
formulating BP’s upstream strategy, and
subsequent portfolio rationalization. Andy
held commercial leadership positions in
Mexico and Venezuela, before becoming
the Upstream’s planning manager.
Following the BP-Amoco merger, Andy
spent time leading BP’s businesses in
Azerbaijan, Trinidad & Tobago, and
onshore North America. In 2009, he
joined the upstream executive team as
head of portfolio and technology and in
2010 was appointed executive vice
president, exploration and production.
Bob Fryar
Current position
Executive vice president, safety and
operational risk
Executive team tenure
Appointed 1 October 2010
Outside interests
No external appointments
Age 52 Nationality American
Career
Bob Fryar is responsible for
strengthening safety, operational risk
management and the systematic
management of operations across the
BP group. He is group head of safety
and operational risk, with accountability
for group-level disciplines including
engineering, health, safety, security
and the environment. In this capacity,
he looks after the group-wide operating
management system implementation
and capability programmes.
Bob has 30 years’ experience in the
oil and gas industry, having joined
Amoco Production Company in 1985.
Between 2010 and 2013, Bob was
executive vice president of the
production division and was
accountable for safe and compliant
exploration and production operations
and stewardship of resources across
all regions.
Executive team
As at 4 March 2016
Rupert Bondy
Current position
Group general counsel
Executive team tenure
Appointed 1 May 2008
Outside interests
Non-executive director, Indivior PLC
Age 54 Nationality British
Career
Rupert Bondy is responsible for legal and
compliance matters across the BP group.
Rupert began his career as a lawyer in
private practice. In 1989 he joined US law
firm Morrison & Foerster, working in San
Francisco and London, and from 1994 he
worked for UK law firm Lovells in London.
In 1995 he joined SmithKline Beecham
as senior counsel for mergers and
acquisitions and other corporate matters.
He subsequently held positions of
increasing responsibility and, following the
merger of SmithKline Beecham and
GlaxoWellcome to form GlaxoSmithKline,
was appointed senior vice president and
general counsel of GlaxoSmithKline
in 2001.
In April 2008 he joined the BP group, and
he became the group general counsel in
May 2008.
Tufan Erginbilgic
Current position
Chief executive, Downstream
Executive team tenure
Appointed 1 October 2014
Outside interests
Independent non-executive director
of GKN plc
Member of the Turkish-British Chamber
of Commerce & Industry Board of
Directors
Age 56 Nationality British and Turkish
60
BP Annual Report and Form 20-F 2015
Katrina Landis
Current position
Executive vice president, corporate
business activities
Executive team tenure
Appointed 1 May 2013
Outside interests
Independent director of Alstom SA
Founding member of Alstom’s Ethics,
Compliance and Sustainability
Committee
Member of Earth Day Network’s
Global Advisory Committee
Ambassador to the US Department of
Energy’s US Clean Energy
Education & Empowerment
program
Age 56 Nationality American
Career
Katrina Landis is responsible for BP’s
integrated supply and trading activities,
renewable energy activities, shipping,
technology and remediation
management.
Katrina began her career with BP in 1992
in Anchorage, Alaska and held a variety
of senior roles. She was chief executive
officer of BP’s integrated supply and
trading – Oil Americas – from 2003 to
2006, group vice president of BP’s
integrated supply and trading from 2007
to 2008, and chief operating officer of BP
Alternative Energy from 2008 to 2009.
She was then appointed chief executive
officer of BP Alternative Energy in 2009.
In May 2013, she became executive vice
president, corporate business activities.
Since mid-2010 she has served as an
independent director of Alstom SA, a
world leader in transport infrastructure,
power generation and transmission, and
is a founding member of Alstom’s ethics,
compliance and sustainability committee.
Katrina will step down from her executive
vice president role in May 2016 and will
retire from BP in July 2016.
Bernard Looney
Lamar McKay
Dev Sanyal
Helmut Schuster
Current position
Chief operating officer, production
Current position
Chief executive, Upstream
Executive team tenure
Appointed 1 November 2010
Executive team tenure
Appointed 16 June 2008
Outside interests
Fellow of the Royal Academy of
Engineering
Member of the Stanford University
Graduate School of Business
Advisory Council
Fellow of the Energy Institute
Age 45 Nationality Irish
Career
Bernard Looney is responsible for BP’s
operated production, with specific
accountability for drilling, operations,
engineering, procurement and supply
chain management, and health, safety
and environment in the Upstream.
Bernard joined BP in 1991 as a drilling
engineer, working in the North Sea,
Vietnam and the Gulf of Mexico. In 2005
he became senior vice president for BP
Alaska, before moving in 2007 to be head
of the group chief executive’s office.
In 2009 he became the managing
director of BP’s north sea business in the
UK and Norway. At the same time,
Bernard became a member of the Oil &
Gas UK Board. He became executive
vice president, developments, in October
2010 and took up his current role in
February 2013.
During 2016 Bernard will take on the role
of chief executive, upstream, in addition
to maintaining his current portfolio.
Outside interests
Member of Mississippi State
University Dean’s Advisory Council
Age 57 Nationality American
Career
Lamar McKay is responsible for the
Upstream segment which consists of
exploration, development and production.
Lamar started his career in 1980 with
Amoco and held a range of technical and
leadership roles.
During 1998 to 2000, he worked on the
BP-Amoco merger and served as head of
strategy and planning for the exploration
and production business. In 2000 he
became business unit leader for the
central North Sea. In 2001 he became
chief of staff for exploration and
production, and subsequently for BP’s
deputy group chief executive. Lamar
became group vice president, Russia and
Kazakhstan in 2003. He served as a
member of the board of directors of
TNK-BP between February 2004 and
May 2007.
In 2007 he was appointed executive vice
president, BP America. In 2008 he
became executive vice president, special
projects where he led BP’s efforts to
restructure the governance framework
for TNK-BP. In 2009 Lamar was
appointed chairman and president of BP
America, serving as BP’s chief
representative in the US. In January
2013, he became chief executive,
Upstream.
During 2016 Lamar will take on the role
of deputy group chief executive. In
addition to assuming some of the group
chief executive’s duties he will be
accountable for group strategy and
long-term planning, safety and
operational risk, group technology and
will also focus on various corporate
governance activities including ethics
and compliance.
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Current position
Executive vice president, strategy and
regions
Current position
Executive vice president, group human
resources
Executive team tenure
Appointed 1 January 2012
Executive team tenure
Appointed 1 March 2011
Outside interests
Non-executive director of Ivoclar
Vivadent AG, Germany
Age 55 Nationality Austrian
Career
Helmut Schuster became group human
resources (HR) director on 1 March 2011.
He completed his post graduate diploma
in international relations and his PhD in
economics at the University of Vienna
and then began his career working for
Henkel in a marketing capacity. Since
joining BP in 1989 Helmut has held a
number of leadership roles. He has
worked in BP in the US, UK and
continental Europe and within most parts
of refining, marketing, trading, and gas
and power.
Before taking on his current role his
portfolio of responsibilities as a vice
president, HR included the refining and
marketing segment of BP, and corporate
and functions. That role saw him leading
the people agenda for roughly 60,000
people across the globe and included
businesses such as petrochemicals, fuels
value chains, lubricants and functional
experts across the group. He is also a
non-executive director of BP Europa SE.
Outside interests
Independent non-executive director of
Man Group plc
Member of the Accenture Global
Energy Board
Member of the Board of Advisors of
the Fletcher School of Law and
Diplomacy
Vice Chairman of the Centre for China in
the World Economy, Tsinghua
University
Age 50 Nationality British and Indian
Career
Dev Sanyal is responsible for the
Europe and Asia regions and
functionally for group strategy and
long-term planning, risk management,
government and political affairs, policy
and group integration.
Dev joined BP in 1989 and has held a
variety of international roles in London,
Athens, Istanbul, Vienna and Dubai.
He was general manager, former Soviet
Union and eastern Europe, prior to being
appointed chief executive, BP Eastern
Mediterranean Fuels in 1999.
In November 2003 he was appointed
chief executive officer of Air BP
International. In June 2006 he was
appointed head of the group chief
executive’s office. He was appointed
group vice president and group treasurer
in 2007. During this period, he was also
chairman of BP Investment Management
Ltd and was accountable for the group’s
aluminium interests.
During 2016 Dev will take on the role of
chief executive, alternative energy and
executive vice president, regions.
The executive team represents the
principal executive leadership of the
BP group. Its members include BP’s
executive directors (Bob Dudley and
Dr Brian Gilvary whose biographies
appear on page 57) and the senior
management listed left.
The ages of the executive team are
correct as at 4 March 2016.
BP Annual Report and Form 20-F 2015
61
Introduction from the chairman
It is vital that the work of the board evolves
with the business. We cannot be working
to one rhythm while the business works
to another.
The membership and work of the board have continued to evolve during
2015. This has been driven by several factors, not least the challenging oil
price environment which now dominates our industry. In the years
following the Deepwater Horizon accident, the workload of the board, as I
have previously reported, increased substantially in response to the issues
with which the company was faced. While the number of our meetings
has decreased, we still face evolving challenges and I am grateful to Bob,
his executive colleagues and my fellow directors for the work that they
have done. The commitment required of all of us certainly has not reduced
with the number of meetings.
This means that we have to keep refreshed the way in which we work,
the matters that we discuss and the decisions that we take. It remains our
goal to keep our board time clear for strategic thinking while asking the
committees to undertake much of the core tasks of monitoring and
oversight. We need to ensure that we have the right skills round the board
table to carry out these tasks.
External interest in what boards do increases year on year and it is for this
reason that we set out, in the following detail, a description of our
activities. Our agendas are prepared in such a way that we have the time
to discuss the key issues of the moment without affecting the proper
oversight of those matters with which we have to deal. As will be seen
from the reports of the committees, directors have visited a number of
BP’s facilities during the year. This is a key part not only of building our
understanding of the business but also testing the mood and the morale
of our people in these difficult times.
As we look to the future, it is vital that the work of the board evolves with
the business. We cannot be working to one rhythm while the business
works to another. It is all too easy for a board to work to a historic schedule
created to address past challenges. For this reason I am pleased that this
year we have carried out a fully externally facilitated evaluation. We are
reflecting on the conclusions which are set out elsewhere; it is important
that we keep on learning. However, behind all of this an effective board
has to keep asking itself two key questions: are we talking about the right
things and are we adding value?
It is some time since we reviewed our governance policies. We will be
doing this in 2016. The results of our evaluation will be part of this
process. Prompted by changes to the Governance Code, we have further
focused on risk and our systems of internal control. This has been a
valuable process for the board. After what seems almost annual changes
to the Code, I welcome the FRC’s decision that this will not be reviewed
again until 2019, enabling the UK governance landscape to settle and
establish. I am however looking forward to BP being able to contribute to
the FRC’s work on succession and culture, which both remain key issues
for any board.
Carl-Henric Svanberg
Chairman
BP governance framework
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Owners/shareholders
BP board
Nomination
committee
Remuneration
committee
Chairman’s
committee
Gulf of Mexico
committee
SEEAC
Geopolitical
committee
Audit
committee
Strategy/group risks/annual plan
Group chief executive
Group chief executive’s delegations
Executive management
Resource
commitments
meeting
(RCM)
Group people
committee
(GPC)
Group
disclosure
committee
(GDC)
Group financial
risk committee
(GFRC)
Group
operations risk
committee
(GORC)
Group ethics
and compliance
committee
(GECC)
62
BP Annual Report and Form 20-F 2015
BP board
governance
principles:
(cid:127) BP goal
(cid:127) Governance process
(cid:127) Delegation model
(cid:127) Executive limitations
Delegation
Delegation of authority
through policy with
monitoring
Accountability
Assurance through
monitoring and
reporting
Monitoring,
information
and assurance
Group audit
Finance function
Safety and
operational risk
function
Group ethics and
compliance function
Business integrity
function
External market
and reputation
research
Independent auditor
Independent adviser
Independent advice
(if requested)
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The board in 2015
Board membership
On 1 January 2016 the board had 15 directors – the chairman, two executive
directors and 12 independent non-executive directors (NEDs).
NEDs are expected to be independent in character and judgement and free
from any business or other relationship that could materially interfere with
exercising that judgement. It is the board’s view that all NEDs, with the
exception of the chairman, are independent. See page 244 for a description
of BP’s board governance principles relating to director independence.
The board benefits significantly from the diverse balance of background,
gender, skills and experience represented by the NEDs. There are three
female directors on the board and three directors from non-UK/US
backgrounds.
Director
Paul Anderson
Alan Boeckmann
Admiral Frank Bowman
Antony Burgmans
Cynthia Carroll
Key skills and experience
Oil and gas industry experience; leading
a global business
Engineering, construction and
procurement; leading a global business
Safety, technology, engineering and risk
management
Food and consumer goods; leading a
global business
Oil, gas and extractive industry
experience; leading a global business
Professor Dame Ann Dowling Engineering, technology and education
Ian Davis
Strategy, advisory and consulting
Brendan Nelson
Audit, financial services and trading
Phuthuma Nhleko
Civil engineering, telecoms and banking
Paula Rosput Reynolds
Sir John Sawers
Andrew Shilston
Carl-Henric Svanberg
Energy industry; leading a global
business
International affairs
Oil and gas industry experience; finance
Manufacturing and telecoms; leading a
global business
The board is satisfied that there is no compromise to the independence of,
and nothing to give rise to conflicts of interest for, those directors who
serve together as directors on the boards of outside entities or who hold
other external appointments. The nomination committee keeps the other
interests of the NEDs under review to ensure that the effectiveness of the
board is not compromised.
Succession
Paula Rosput Reynolds joined the board in May 2015 as a non-executive
director. She is a member of the audit committee and the chairman’s
committee.
Sir John Sawers also joined the board in May 2015 as a non-executive
director. He is a member of the safety, ethics and environment assurance
committee, the geopolitical committee and the chairman’s committee.
George David, a non-executive director, retired from the board at the annual
general meeting on 16 April 2015.
Professor Dame Ann Dowling became the chair of the remuneration
committee when Antony Burgmans stood down from the role in July 2015.
Andrew Shilston and Alan Boeckmann joined the remuneration committee
after the 2015 annual general meeting.
Antony Burgmans became chair of the newly formed geopolitical
committee in September 2015. Antony Burgmans will step down from the
board at the 2016 AGM after 12 years of service as a non-executive director.
Sir John Sawers will then take the chair of the geopolitical committee.
Phuthuma Nhleko will step down from the board at the 2016 AGM after five
years of service due to external business commitments.
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Board meetings
There were 13 board meetings in 2015, of which two were carried out by
teleconference. All directors attended every meeting for which they were
eligible, with the following exceptions:
• Phuthuma Nhleko did not attend the board meeting scheduled at short
notice on 15 June due to prior commitments.
• Antony Burgmans, Cynthia Carroll, Brendan Nelson, Paula Rosput
Reynolds and Sir John Sawers did not attend the board meeting
scheduled at short notice on 23 June due to prior commitments.
• Phuthuma Nhleko did not attend the board meeting on 3 December due
to urgent business commitments.
Board evaluation
Each year BP undertakes a review of the board, its committees and
individual directors. The chairman’s performance is evaluated by the
chairman’s committee and his evaluation is led by the senior independent
director.
The evaluation operates on a three-year cycle, with one externally led
evaluation followed by two subsequent years of internal evaluations
carried out using a questionnaire prepared by an external facilitator.
Activity following prior year evaluation
An evaluation was carried out at the end of 2014 by means of a
questionnaire, facilitated by an external consultant (Lintstock). The
evaluation concluded that reports from the business and on major
projects were robust and informative. In a changing economic and
geopolitical climate, the board was keen to ensure that it managed its
time to allow appropriate levels of discussion by balancing the board’s
monitoring activities with discussion on strategic matters: this has been
achieved by agenda planning during the year. The evaluation highlighted
the future role of technology in delivering BP’s strategy: briefings on this
topic were planned into the board’s agenda, including a technology
presentation with respect to climate change.
2015 evaluation
For 2015 an externally facilitated evaluation was held in addition to, and to
an extent based on, the established annual questionnaire process.
Following a selection process led by the senior independent director,
Bvalco was engaged as the external evaluator. The results of the annual
questionnaire process were shared with the external evaluator who
conducted a series of interviews with each director, members of the
executive team and those who attended or supported the board.
Interviews were focused on evaluating the effectiveness and
performance of the board, and separately that of the chairman. In addition
to these interviews, the evaluators reviewed the board agendas and
materials for the past year and observed a board meeting.
The evaluation tested key areas of the board’s work including its participation
in the formation of strategy, succession and composition, and its oversight
of business performance, risk and governance processes. The effectiveness
of the committees in alleviating the oversight task of the board was also
tested and focus was given to whether the board added value.
Results of the board evaluation and feedback from these interviews were
collectively discussed by the board at its meeting in January 2016, with the
results of the chairman’s evaluation discussed by the chairman’s committee.
The evaluation concluded:
• Recognizing the current state of the market and important
developments for the company during the year, there was a continued
desire to ensure an effective strategy process that focused on the long
term and which acknowledged the important role of the board in this
process.
• Good progress had been made in succession for the board; going
forward this would continue to be built on.
• The board was seen to have a collaborative and inclusive environment.
To build on this further, the board agreed to try and put more of their
monitoring tasks into the committees to allow more time for broader
discussions at the board.
• Committee work was seen as being of a high quality. Given the breadth of
topics covered by the committees, further steps should be taken to ensure
that where appropriate all directors could access information and attend
external visits for those committees of which they were not members.
It was noted that the board governance principles would be reviewed and
amended to capture these conclusions, where appropriate, and to reflect
the current roles and practices within the board.
BP Annual Report and Form 20-F 2015
63
Board activity
The board’s activities are structured to enable the directors to fulfil their role,
in particular with respect to strategy, risk, performance and monitoring.
Board focus in 2015
• Low oil price environment.
• Geopolitical influences.
• Climate change.
• Long-term technology view.
• Economic and competitor outlook.
• Organizational capability.
• Group risk process.
• Identification and allocation of risks to
the board and committees for 2016.
• Major projects delivery risk.
• Geopolitical risk.
Strategy
Performance
Risk
Monitoring
• Chief executive’s report.
• Group performance report.
• Group financial outlook.
• Effectiveness of investment review.
• Quarterly and full year results.
• Shareholder distributions.
• Feedback from committees.
• BP brand and global reputation.
• Ethics monitor report.
• Process safety expert report.
• Employee survey results.
• Board evaluation.
.
Strategy
The board discussed strategy or strategic elements at every full meeting.
The board also reviewed the BP Energy Outlook, updated in February 2015,
which looks at long-term energy trends and develops projections for world
energy markets over the next two decades.
Monitoring
All meetings include a report from the chair of each committee that has
met since the last meeting. These are supplemented with feedback on
board and committee site visits, including a ‘deep dive’ on exploration at
the upstream learning centre in Sunbury in May.
In January the executive team presented the 2015 annual plan to describe
how the strategy should be implemented. The board met for two days in
Houston in September to review the strategy in depth.
The board monitors employee opinion via an annual pulse survey which
includes measurement of how the BP values are incorporated into daily
culture around our global operations.
The board received an update in December on BP’s reputation in the US
and UK compared with competitors, based on the results of our 2015
reputation research across a number of consistent reputational attributes
measured over time.
Risk
During the year the board, either directly or through its committees,
regularly reviewed the processes whereby risks are identified, evaluated
and managed. The effectiveness of the group’s system of internal control
and risk management was also assessed.
The board considered the allocation of group risks between the monitoring
committees (the audit, SEEA, and Gulf of Mexico committees, and from
September, the geopolitical committee) and the board itself, and confirmed
the schedule for oversight of these risks. The group risks reviewed by the
board during 2015 included risks associated with the delivery of major
projects★, particularly in the Upstream, and geopolitical risk associated
with BP’s operations around the world. For 2016 the group risks allocated
to the board for review include financial resilience (which examines how
the group is able to respond to a volatile oil and gas price environment) and
cybersecurity (with the audit committee and SEEAC reviewing elements of
cybersecurity risk in their work over the year). The group risks allocated to
the committees for review over the year are outlined in the reports of the
committees on pages 68-72.
Further information on BP’s system of risk management is outlined in Our
management of risk on page 51. Information about BP’s system of internal
control is given on page 93.
Performance
The board reviews financial and operational performance at each meeting.
It receives regular updates on the group’s performance for the year across
a range of metrics as well as the latest view on expected full-year delivery
against external scorecard measures. Updates are also given on various
components of value delivery for BP’s business.
The board reviews the quarterly and full-year results, including reviewing
shareholder distribution policy. Both the 2014 and 2015 annual reports
were assessed in terms of the directors’ obligations and appropriate
regulatory requirements.
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Training and induction
To help develop an understanding of BP’s business, the board continues to
build its knowledge through briefings and field visits. In 2015 the board
received training on ethics and compliance, and the introduction of the new
longer-term viability statement. The board met local management and
external stakeholders at its board meetings in Sunbury and Houston.
NEDs are expected to attend at least one field visit per year. In 2015 the
audit committee visited the cybersecurity centre in Houston and members
of the SEEAC visited BP’s operations in Trinidad, Oman and Rotterdam.
After each visit, the board or appropriate committee was briefed on the
impressions gained by the directors during the visit.
The two new NEDs, Paula Rosput Reynolds and Sir John Sawers followed
a structured induction process. This included one-to-one meetings with
management and the external auditors and also covered the board
committees that they joined.
Director induction programme
Board and governance
BP’s board governance model, directors’ duties, interests and
potential conflicts.
Business introduction
BP’s business.
Upstream (exploration, development, production, overview of
our operations).
Downstream (refining, marketing and lubricants).
Strategy and planning.
BP’s performance relative to its competitors.
Functional input
Finance and tax.
Audit committee visit to cybersecurity centre
During a strategy meeting in Houston, the audit committee and the
chairman visited the cybersecurity centre.
Directors met the cybersecurity leadership team and saw
demonstrations of how the group monitors and defends against attacks,
and considers broader digital security trends.
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Shareholder engagement
The company operates an active investor relations programme and the
board receives feedback on shareholder views through results of an
anonymous investor audit and reports from management and those
directors who met with shareholders over the year.
Controls, external auditors and internal audit.
Shareholder engagement cycle 2015
Human resources.
Ethics and compliance.
Safety and operational risk (S&OR), BP’s operating management
system (OMS) and environmental performance.
Research and technology.
Trading.
After completing the induction, the directors are asked for feedback on the
process to help further improve it going forward.
January
February
March
April
June
July
August
BP Energy Outlook presentation
Fourth quarter results
Investor roadshows with the group chief
executive and chief financial officer
Engagement on remuneration and governance
issues
Chairman and board committee chairs meeting
UKSA private shareholders’ meeting
SRI roadshow following the launch of
BP Sustainability Report 2014
Annual general meeting
First quarter results
BP’s response to lower oil prices launch
BP Statistical Review of World Energy launch
Second quarter results
Investor roadshows with the group chief
executive and chief financial officer
Institutional Investors Group on Climate Change
meeting
Engagement with UKSA private shareholder
panel on BP’s 2014 financial reports
September
Oil and gas sector conferences
October
November
Third-quarter results and medium-term outlook
SRI annual meeting
BP Technology Outlook launch
Meetings with investors on remuneration (into
December)
December
Medium-Term Outlook launched on bp.com
★ Defined on page 256.
BP Annual Report and Form 20-F 2015
65
Institutional investors
Senior management regularly meets with institutional investors through
roadshows, group and one-to-one meetings and events for socially
responsible investors (SRIs).
During the year the chairman and remuneration committee chair held
individual investor meetings to discuss strategy, the board’s view on BP’s
performance, governance and remuneration. In March the chairman and all
board committee chairs held an annual investor event. This meeting
enabled BP’s largest shareholders to hear about the work of the board and
its committees and for NEDs to engage with investors.
In November the chairman and members of the executive team met with
socially responsible investors as part of BP’s annual SRI meeting. The
meeting examined a number of operational and strategic issues, including
how the board looks at risk and strategy, the group’s approach to
operational risk, context for the sector and BP in terms of oil price and
energy supply-demand, operating and energy performance in the
Upstream, and BP’s response to the shareholder resolution.
See bp.com/investors for investor presentations, including the group’s
financial results and information on the work of the board and its
committees.
Private investors
BP held a further event for private investors in conjunction with the UK
Shareholders’ Association (UKSA) in 2015. The chairman and head of
investor relations made presentations on BP’s annual results, strategy and
the work of the board. The shareholders asked questions on BP’s activities
and performance. Later in the year, the UKSA met with the company to
give feedback on BP’s 2014 financial reports.
AGM
Voting levels decreased slightly in 2015 to 62.28% (of issued share capital,
including votes cast as withheld), compared to 63.13% in 2014 and
64.24% in 2013. Each year the board receives a report after the AGM
giving a breakdown of the votes and investor feedback on their voting
decisions to inform the board on any issues arising.
UK Corporate Governance Code compliance
BP complied throughout 2015 with the provisions of the UK Corporate
Governance Code (the Code) except in the following aspects:
B.3.2 Letters of appointment do not set out fixed-time commitments
since the schedule of board and committee meetings is subject to
change according to the demands of business and other events. Our
letters of appointment set a general guide of a time commitment
between 30-40 days per year. All directors are expected to
demonstrate their commitment to the work of the board on an
ongoing basis. This is reviewed by the nomination committee in
recommending candidates for annual re-election.
D.2.2 The remuneration of the chairman is not set by the remuneration
committee. Instead the chairman’s remuneration is reviewed by the
remuneration committee which makes a recommendation to the
board as a whole for final approval, within the limits set by
shareholders. This wider process enables all board members to
discuss and approve the chairman’s remuneration, rather than solely
the members of the remuneration committee.
International advisory board
BP’s international advisory board (IAB) advises the chairman, group chief
executive and the board on geopolitical and strategic issues relating to the
company. This group meets once or twice a year and between meetings
IAB members remain available to provide advice and counsel when
needed.
The IAB is chaired by BP’s previous chairman, Peter Sutherland. Its
membership in 2015 comprised Kofi Annan, Lord Patten of Barnes, Josh
Bolten, President Romano Prodi, Dr Ernesto Zedillo and Dr Javier Solana.
The chairman and chief executive attend meetings of the IAB. Issues
discussed during the year included emerging geopolitical issues that could
impact BP’s business, developments in the Middle East and Latin America,
the effects of migration in Europe and the 2016 US election.
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How the board works
The board operates within a system of governance that is set out in the BP
board governance principles. These principles define the role of the board,
its processes and its relationship with executive management.
This system is reflected in the governance of the group’s subsidiaries.
See bp.com/governance for the board governance principles.
Role of the board
The board is responsible for the overall conduct of the group’s business
and the directors have duties under both UK company law and BP’s
Articles of Association.
The primary tasks of the board include:
Active consideration and direction of long-term strategy and
approval of the annual plan.
Monitoring of BP’s performance against the strategy and plan.
Obtaining assurance that the principal risks and uncertainties to
BP are identified and that systems of risk management and
control are in place to mitigate such risk.
Board and executive management succession.
The board seeks to set the ‘tone from the top’ for BP by working with
management to agree BP values and considering specific issues including
health, safety, the environment and reputation.
Key roles and responsibilities
The chairman
Carl-Henric Svanberg
• Provides leadership of the board.
• Acts as main point of contact between the board and management.
• Speaks on board matters to shareholders and other parties.
• Ensures that systems are in place to provide directors with accurate,
timely and clear information to enable the board to operate effectively.
• Is responsible for the integrity and effectiveness of the BP board’s
system of governance.
The group chief executive
Bob Dudley
• Is responsible for day-to-day management of the group and executes
strategy.
• Chairs the executive team (ET), the membership of which is set out
on pages 60 to 61.
The senior independent director
Andrew Shilston
• Acts as an internal sounding board for the chairman.
• Serves as intermediary for other directors with the chairman when
necessary.
• Is available to shareholders if they have concerns that cannot be
addressed through normal channels.
• Leads the chairman’s evaluation.
Neither the chairman nor the senior independent director are employed as
an executive of the group.
Appointment and time commitment
The chairman and NEDs have letters of appointment; there is no term limit
on a director’s service, as BP proposes all directors for annual re-election
by shareholders (a practice followed since 2004).
While the chairman’s appointment letter sets out the time commitment
expected of him, letters of appointment for NEDs do not set a fixed-time
commitment, but instead set a general guide of between 30-40 days per
year. The time required of directors may fluctuate depending on demands
of BP business and other events, and they are expected to allocate
sufficient time to BP to perform their duties effectively and make
themselves available for all regular and ad-hoc meetings.
Executive directors are permitted to take up one external board
appointment, subject to the agreement of the chairman. Fees received for
an external appointment may be retained by the executive director and are
reported in the annual report on remuneration (see page 76).
Board diversity
BP recognizes the importance of diversity, including gender diversity, at
the board and all levels of the group. We are committed to increasing
diversity across our operations and have a wide range of activities to
support the development and promotion of talented individuals, regardless
of gender and ethnic background.
The board operates a policy that aims to promote diversity in its
composition. Under this policy, director appointments are evaluated against
the existing balance of skills, knowledge and experience on the board, with
directors asked to be mindful of diversity, inclusiveness and meritocracy
considerations when examining nominations to the board.
Implementation of this policy is monitored through agreed metrics. During
its annual evaluation, the board considered diversity as part of the review
of its performance and effectiveness.
We continue to support the UK government’s review of gender diversity
on boards, undertaken by Lord Davies in 2011, and maintain an aspiration
to increase female representation to 25%. At the end of 2015, there were
three female directors (2014 2, 2013 2) on our board of 15. Our nomination
committee remains mindful of diversity in considering potential candidates
for appointment to the board.
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BP Annual Report and Form 20-F 2015
67
Members
Brendan Nelson (chair) Member since November 2010; committee
chair since April 2011
George David
Member from February 2008 to April 2015
Phuthuma Nhleko
Member since February 2011
Paula Rosput Reynolds Member since May 2015
Andrew Shilston
Member since February 2012
Brendan Nelson is chair of the audit committee. He was formerly vice
chairman of KPMG and president of the Institute of Chartered Accountants
of Scotland. Currently he is chairman of the group audit committee of The
Royal Bank of Scotland Group plc. The board is satisfied that Mr Nelson is
the audit committee member with recent and relevant financial experience
as outlined in the UK Corporate Governance Code. 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. 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 Mr Nelson may be regarded as an audit
committee financial expert as defined in Item 16A of Form 20-F.
Meetings and attendance
There were 11 committee meetings in 2015, of which three were carried
out by teleconference and five were joint meetings with the SEEAC. All
directors attended every meeting for which they were eligible, with the
following exceptions:
• George David did not attend the teleconference on 25 February 2015
due to prior commitments.
• Phuthuma Nhleko did not attend the committee meeting on 23 April
2015 due to a clash with the AGM of another company.
• Paula Rosput Reynolds did not attend the committee meeting on
23 September 2015 due to a conflicting board meeting.
Meetings are also attended by the chief financial officer, group controller,
chief accounting officer, head of group audit and external auditor.
Activities during the year
Training
The committee held a learning event on changes to the UK Corporate
Governance Code and received technical updates during the year from
the chief accounting officer on developments in financial reporting and
accounting policy.
Financial disclosure
The committee reviewed the quarterly, half-year and annual financial
statements with management, focusing on the integrity and clarity of
disclosure, compliance with relevant legal and financial reporting standards
and the application of critical accounting policies and judgements.
The committee jointly reviewed with the SEEAC whether the BP Annual
Report and Form 20-F 2015 was fair, balanced and understandable and
provided the information necessary for shareholders to assess the group’s
position and performance, business model and strategy. The two
committees considered the processes underpinning the compilation and
assurance of the report in relation to financial and non-financial
management information. Following this joint review, the full board
reviewed the report as a whole – including tone, balance, language and
consistency between the narrative sections and financial statements. Part
of the board’s evaluation included a review of the company’s internal
processes that form the group’s reporting governance framework. The
board’s statement on the report is on page 93.
Committee reports
Audit committee
Chairman’s introduction
2015 was another active year for the audit committee. We took the
opportunity of the new UK Corporate Governance Code reporting
requirements to take a fresh look at the company’s risk management
processes. This involved reviewing the group’s principal risks, considering
scenarios that might impact the company’s longer-term viability and
debating the categorization of what would constitute significant failings and
weaknesses in our system of internal control.
The committee continued to build its understanding of BP’s business,
including how key risks are identified and mitigated and how segments and
functions are performing to achieve the group’s strategy. To complement
the presentations received in the board room, the committee met
employees on several site visits – including trading floors in Houston and
London and the group’s cybersecurity monitoring centre.
During 2015 the committee’s membership evolved, with our longest-serving
member George David retiring in April and Paula Rosput Reynolds joining us
in May. I would like to thank George for his insight and challenge during his
tenure and to welcome Paula, who brings broad financial and corporate
knowledge from her business career. The skills and experience of our
committee membership remain strong and I believe that the committee has
performed effectively over the year.
Brendan Nelson
Committee chair
Role of the committee
The committee monitors the effectiveness of the group’s financial
reporting, systems of internal control and risk management and the
integrity of the group’s external and internal audit processes.
Key responsibilities
• Monitoring and obtaining assurance that the management or mitigation
of financial risks is appropriately addressed by the group chief executive
and that the system of internal control is designed and implemented
effectively in support of the limits imposed by the board (executive
limitations) as set out in the BP board governance principles.
• Reviewing financial statements and other financial disclosures and
monitoring compliance with relevant legal and listing requirements.
• Reviewing the effectiveness of the group audit function, BP’s internal
financial controls and system of internal control and risk management.
• 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 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.
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Areas of audit committee focus in 2015
• Financial results announcements.
• Annual Report and Form 20-F.
• Accounting judgements and estimates.
• Developments in financial reporting
and accounting.
• Oil and gas reserves disclosure.
• Fair, balanced and understandable.*
• Review of effectiveness of BP’s system
of internal control and risk management.*
• Quarterly group audit reports.
• Quarterly significant allegations and
investigations reports.
• Quarterly ethics and compliance reports.
• Annual ethics certification.*
• Ethics and compliance function remit.*
• Principal risks, viability and significant
failings and weaknesses.*
* Undertaken jointly with the SEEAC.
Financial
disclosure
System of internal
control and risk
management
External
audit
Risk
reviews
• Confirmation of external auditor
independence.
• Non-audit fees: policy and approval.
• Audit plan, fees and engagement.
• Auditor performance and effectiveness.
• Proposed regulations for non-audit work.
• Key areas of judgement for year-end audit.
• Audit tendering.
• Cybersecurity.
• Trading, compliance and control.
• Compliance with business regulations.
• Review of the Downstream segment.
• Tax.
• Going concern.
• Succession and people development in
the finance function.
• Pensions and post-retirement benefits
assumptions.
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Significant areas of accounting judgement considered by the committee during the year
Key issues/judgements in financial reporting
Audit committee review
Oil and natural gas
accounting
BP uses judgement and estimations when accounting for oil
and gas exploration, appraisal and development expenditure
and determining the group’s estimated oil and gas reserves.
Recoverability of asset
carrying values
Determination as to whether and how much an asset is
impaired involves management judgement and estimates on
highly uncertain matters such as future pricing or discount
rates. Judgements are also required in assessing the
recoverability of overdue receivables and deciding whether
a provision is required.
Accounting for
interests in other
entities
BP exercises judgement when assessing the level of control
obtained in a transaction to acquire an interest in another
entity and when determining the fair value of assets acquired
and liabilities assumed, and the level of control which
continues to be exercised going forward.
The group’s trading
activities
BP uses judgement when estimating the fair value of some
derivative instruments in cases where there is an absence of
liquid market pricing information – for example, relating to
supply and trading activities.
Provisions and
contingencies
The group holds provisions for the future decommissioning of
oil and natural gas production facilities and pipelines at the
end of their economic lives. Most of these decommissioning
events are in the long term and the requirements that will
have to be met when a removal event occurs are uncertain.
Judgement is applied when estimating issues such as
settlement dates, technology and legal requirements.
The committee reviewed judgemental aspects of oil and gas
accounting such as intangible asset balances relating to
exploration and appraisal activities as part of the company’s
quarterly due-diligence process. It also examined the
governance framework for the oil and gas reserves process,
training for staff and developments in regulations and
controls. Significant exploration write-offs during the year
were disclosed in the relevant quarter.
The committee reviewed the discount rates for impairment
testing as part of its annual process and examined the
assumptions for long-term oil and gas prices and refining
margins. It received updates from management at each
quarter relating to market forward prices used for impairment
testing and considered whether any further impairment
indicators were present. The committee also reviewed
management’s approach to reviewing the carrying values of
upstream assets following further falls in market forward
prices. Significant impairments during the year were
disclosed as non-operating items★ in the relevant quarter.
The committee continued to review the accounting for BP’s
investment in Rosneft including the judgement on whether
the group has significant influence over Rosneft. During the
year the committee received reports from management and
the external auditor that assessed the extent of BP’s
influence, including participation in decision making through
the election of two BP nominees to the Rosneft board. It also
assessed other factors, including the signing of binding
agreements for BP to complete the purchase of a 20%
interest in Taas-Yuryakh Neftegazodobycha, a Rosneft
subsidiary.
The committee received a detailed briefing on the group’s
trading risk, controls and compliance and visited BP’s trading
floors in Houston and London. The committee considered the
controls in place to prevent unauthorized trading activity and
received information on the valuation of the group’s derivative
instruments and the financial models that are used.
The committee received briefings on the group’s
decommissioning, environmental remediation and litigation
provisioning, including key assumptions used, the governance
framework applied (covering accountabilities and controls),
discount rates and the movement in provisions over time.
★ Defined on page 256.
BP Annual Report and Form 20-F 2015
69
Accounting judgements and estimates (continued)
Key issues/judgements in financial reporting
Audit committee review
Gulf of Mexico oil spill
Judgement was applied during the year around the significant
uncertainties over provisions and contingencies relating to the
incident.
Pensions and other
post-retirement
benefits
Accounting for pensions and other post-retirement benefits
involves judgement about uncertain events, including
discount rates, inflation and life expectancy.
Taxation
Computation of the group’s tax expense and liability,
provisioning for potential tax liabilities and the level of deferred
tax asset recognition in relation to accumulated tax losses are
underpinned by management judgement.
The committee regularly discussed BP’s provisioning for and
the disclosure of contingent liabilities relating to the Gulf of
Mexico oil spill with management and the external auditors,
including as part of the review of BP’s stock exchange
announcement at each quarter end. The committee examined
the provisions booked as a result of the agreements in
principle signed in July. In instances where a reliable estimate
could not be made of the provision required, the committee
considered management’s conclusions and monitored
developments while considering the impact on the financial
statements and other disclosures.
The committee examined the assumptions used by
management as part of its annual reporting process.
The committee reviewed the judgements exercised on tax
provisioning as part of its annual review of key provisions.
Risk reviews
The group risks allocated to the audit committee for monitoring in 2015
included those associated with trading activities, compliance with applicable
laws and regulations and security threats against BP’s digital infrastructure.
The committee held in-depth reviews of these group risks over the year. It
also examined the group’s information technology risks, its governance of
the tax function and the use of financial models including their associated
controls framework. The committee further considered the financial group
(or principal) risks identified for 2016 and the group’s process to assess,
mitigate and monitor them. BP’s principal risks are listed on page 53. For
2016, the board has agreed that the committee will monitor cybersecurity,
trading activities and compliance with applicable laws and regulations.
Other reviews
During the year the committee reviewed succession and development of
the group’s finance function, including an overview of the demographics
and key capability challenges for finance staff. The group’s Downstream
segment was reviewed to examine the financial performance and strategic
priorities of the individual fuels, lubricants and petrochemicals businesses,
including key areas of financial risk management.
Internal control and risk management
The committee reviewed the group’s system of internal control and risk
management throughout the year, holding a joint meeting with the SEEAC
to discuss key audit findings and management’s actions. The committee
reviewed the scope, activity and effectiveness of the group audit function
and met privately with the head of group audit and his leadership team
during the year.
During the year the committee examined the requirements of the revised
UK Corporate Governance Code in relation to the assessment and
reporting of longer-term viability, risk management and internal control. The
committee looked at key elements of BP’s risk management process,
including the reporting and categorisation of risk across the group, and
jointly with the SEEAC examined what might constitute a significant failing
or weakness in the system of internal control. The two committees also
reviewed the modelling undertaken to stress test different financial and
operational events and considered the appropriate period for which the
company was viable.
See our statements on risk management and internal control on page 93
and on longer-term viability on page 94.
The committee received quarterly reports on the findings of group audit,
on significant allegations and investigations and on key ethics and
compliance issues; a joint meeting was held with the SEEAC to discuss
the annual report certifying compliance with the BP code of conduct. The
two committees also met to discuss future programmes for the group
audit and ethics and compliance functions. The committee held a private
meeting with the group ethics and compliance officer during the year.
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External audit
The external auditors set out their audit strategy, identifying key risks to be
considered during the year – including longer-term oil and gas prices, the
group’s cost outlook, the capital framework in a lower oil price
environment, discount rate assumptions, considerations around
impairments, estimation of oil and gas reserves and resources,
decommissioning, valuation of exploration assets, accounting for BP’s
investment in the Rosneft subsidiary Taas, deferred taxation, estimation of
the group’s pension obligations, the recovery of receivables and
management of change.
The committee received updates during the year on the audit process,
including how the auditors had independently considered the group’s
assumptions on these issues.
The audit committee reviews the fee structure, resourcing and terms of
engagement for the external auditor annually. Fees paid to the external
auditor for the year were $51 million (2014 $53 million), of which 6% was
for non-assurance work (see Financial statements – Note 35). Non-audit or
non-audit related assurance fees were $3 million (2014 $5 million). The
$2-million reduction in non-audit fees relates primarily to decreases in tax
advisory and other assurance services. Non-audit or non-audit related
assurance services consisted of tax compliance services, tax advisory
services, other assurance services and services relating to corporate
finance transactions. The audit committee is satisfied that this level of fee
is appropriate in respect of the audit services provided and that an effective
audit can be conducted for this fee.
Audit/non-audit service three-year comparison ($m)
Audit and audit-related assurance services
Non-audit and other assurance services
Services relating to BP pension plans
50
40
30
20
10
0
47
47
47
1
5
2013
1
5
2014
3
1
2015
The effectiveness of the audit process was evaluated through two surveys
– one completed by committee members only and the second by those BP
personnel impacted by the audit. The surveys used a set of criteria to
measure the auditors’ performance against the quality commitment set
out in their annual audit plan. This included the robustness of the audit
process, independence and objectivity, quality of delivery, quality of people
and service and value added advice.
Overall the 2015 evaluation concluded that the external auditor
performance had either improved or remained consistent in key areas with
the previous year. Areas with high scores included independence,
objectivity and the quality of delivery of the audit. Areas of suggested focus
for the auditors included audit team turnover and more liaison between
BP’s own audit function and the external auditors, with the intent that
improved planning could prevent duplication. There was also feedback that
the technical knowledge and experience of the audit team remained strong.
The committee held private meetings with the external auditors during the
year and the chair met privately with the external auditor before each
meeting.
Auditor appointment and independence
The committee considers the reappointment of the external auditor each
year before making a recommendation to the board and shareholders. It
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 seven years. No partners or
senior staff associated with the BP audit may transfer to the group. The
current lead partner has been in place since the start of 2013.
Audit tendering
During the year the committee reviewed the group’s position on its audit
services contract and examined a number of options regarding the timing
of tendering for BP’s external audit, including the mandatory rotation of the
group’s audit firm, taking into account the UK Corporate Governance Code
and the reforms of the audit market by the Competition and Markets
Authority (CMA) and the European Union.
The committee concluded that the best interests of the group and its
shareholders would be served by utilizing the transition arrangements
outlined by the Financial Reporting Council and retaining BP’s existing audit
firm until the conclusion of the term of its current lead partner. The
committee intends that the audit contract will be put out to tender in 2016
so that a decision can be taken and communicated to shareholders at BP’s
AGM in 2017. It is expected that the new audit services contract would be
effective from 2018.
BP has complied throughout 2015 with the provisions of The Statutory
Audit Services Order 2014, issued by the CMA.
Non-audit services
BP’s policy on non-audit services states that the auditors may not perform
non-audit services that are prohibited by the SEC, Public Company
Accounting Oversight Board (PCAOB) and UK Auditing Practices Board
(APB).
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 only considered for permitted non-audit services when its
expertise and experience of the company is important. A two-tier system
for approval of audit-related and non-audit work operates. For services
relating to accounting, auditing and financial reporting matters, internal
accounting and risk management control reviews or non-statutory audit,
the committee has agreed to pre-approve these services up to an annual
aggregate level. For all other services which fall under the permitted
services categories, approval above a certain financial amount must be
sought on a case-by-case basis. Any proposed service not included in the
permitted services categories must be approved in advance either by the
audit committee chairman or the audit committee before engagement
commences. The audit committee, chief financial officer and group
controller 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 accountants’ fees and services on page 245.
During the year, the committee reviewed the group’s policy on audit-
related and non-audit services and it was determined that transfer-pricing
services should be moved into the category of work requiring approval
from the audit committee chairman or the full committee.
Committee review
The audit committee undertakes an annual evaluation of its performance
and effectiveness. In late 2015 the committee used an online survey and
externally facilitated interviews to examine governance issues such as
committee processes and support, the work of the committee and
priorities for change. The review concluded that the committee had
performed effectively. Areas of focus arising from the evaluation included
continuing broader segment and business reviews in the committee’s
2016 agenda, examining how areas of overlap between the committee and
the SEEAC in terms of financial and operational risk could be managed and
suggestions for further committee training and committee visits.
Safety, ethics and environment assurance
committee (SEEAC)
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Chairman’s introduction
The SEEAC has continued to monitor closely and provide constructive
challenge to management in the drive for safe and reliable operations at
all times. This included the committee receiving individual reports on the
company’s management of highest priority group risks in marine, wells,
pipelines, explosion or release at our facilities, and major security incidents.
The committee also undertook a number of field visits as well as
maintaining its schedule of regular meetings with executive management.
We received final reports from the independent experts we engaged in
Upstream (Carl Sandlin) and Downstream (Duane Wilson). They provided
valuable insights and advice on many aspects of process safety and we are
grateful to them for their work.
We were pleased to welcome Sir John Sawers to the committee in July.
John brings valuable experience and insight from his time in government
service.
Paul Anderson
Committee chair
Role of the committee
The role of the SEEAC 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 and receiving assurance that processes to identify and mitigate such
non-financial risk are appropriate in design and effective in implementation.
Key responsibilities
The committee receives specific reports from the business segments as
well as cross-business information from the functions. These include, but
are not limited to, the safety and operational risk function, group audit, group
ethics and compliance, business integrity and group security. The SEEAC
can access any other independent advice and counsel it requires, on an
unrestricted basis.
At a joint meeting with the audit committee, the SEEAC reviewed the
general auditor’s report on the system of internal control and risk
management for the year in preparation for the board’s report to
shareholders in the annual report – see Risk management and internal
control on page 93. In that meeting the committees also reviewed the group
audit programme for the year ahead to ensure both committees endorsed
the coverage. The committees worked together, through their chairs and
secretaries, to ensure that the agendas did not overlap or omit coverage of
any key risks during the year.
BP Annual Report and Form 20-F 2015
71
Members
Paul Anderson
(chairman)
Member since February 2010; committee chair
since December 2012
Alan Boeckmann
Member since September 2014
Frank Bowman
Member since November 2010
Antony Burgmans
Member since February 2004
Cynthia Carroll
Member since June 2007
Ann Dowling
John Sawers
Member since February 2012
Member since July 2015
Meetings and attendance
There were six committee meetings in 2015, plus an additional five joint
meetings with the audit committee. All directors attended every meeting
for which they were eligible, with the following exceptions:
• Alan Boeckmann did not attend the committee meeting on
13 May 2015 due to prior commitments.
• Cynthia Carroll did not attend the committee meeting on
2 December 2015 due to a conflicting board meeting.
In addition to the committee membership, all SEEAC meetings were
attended by the group chief executive, the executive vice president for
safety and operational risk (S&OR) and the head of group audit or his
delegate. The external auditor attended some of the meetings (and was
briefed on the other meetings by the chair and secretary to the
committee), as did the group general counsel and group ethics and
compliance officer. The committee scheduled private sessions for the
committee members only (without the presence of executive
management) at the conclusion of each meeting to discuss any issues
arising and the quality of the meeting.
Activities during the year
Safety, operations and environment
The committee received regular reports from the S&OR function, including
quarterly reports prepared for executive management on the group’s
health, safety and environmental performance and operational integrity.
These included quarter-by-quarter measures of personal and process
safety, environmental and regulatory compliance and audit findings.
Operational risk and performance forms a large part of the committee’s
agenda.
During the year the committee received specific and separate reports on
the company’s management of risks in marine, wells, pipelines, explosion
or release at our facilities and major security incidents. The committee
reviewed these risks and their risk management and mitigation in depth
with relevant executive management.
SEEAC focus in 2015
• GCE operations risk reports.
• Quarterly reports on HSE performance and operational
Independent expert – Upstream
Mr Carl Sandlin continued in his role as an independent expert to provide
further oversight regarding the implementation of the Bly Report
recommendations. He formally reported directly to the SEEAC twice in
2015 and presented detailed reports on his work, including reporting on a
number of visits made to company operations around the world; he also
met in private with the chair and other members of the committee during
the year. He reported that all 26 recommendations in the Bly Report were
completed by the end of 2015. He gave his final report to the SEEAC in
January 2016 and his engagement ceased in February 2016. We thank him
for his work with the committee since 2012.
Process safety expert – Downstream
Mr Duane Wilson finalized his engagement with the committee in his role
as process safety expert for the Downstream segment. He completed his
work with segment management to monitor and advise on the process
safety culture and learnings across the segment. He submitted his final
report to the SEEAC in January 2015 and completed his engagement in
April 2015. The committee thanks him for his work, including on process
safety culture.
Reports from group audit, group ethics and compliance and the
business integrity functions
The committee received quarterly reports from each of these functions. In
addition, both the head of group audit and the group ethics and compliance
officer met in private with the chairman and other members of the
committee during the year.
Field trips
In June members of the committee visited Trinidad to examine both the
offshore facilities (the Cassia platform) and the onshore liquefied natural
gas terminal (Atlantic LNG). In November the chairman and other
committee members visited operations at the Khazzan gas field
development in Oman; in December the chairman and other members of
the committee and the board visited the Rotterdam refinery in the
Netherlands. In all cases, the visiting committee members received
briefings on operations, the status of local operating management
system★ (OMS) implementation and risk management and mitigation.
Committee members then reported back in detail about each visit to the
committee and subsequently to the board.
Committee review
For its 2015 evaluation, the committee examined its performance and
effectiveness through a questionnaire and interviews by external
facilitators. Topics covered included the balance of skills and experience
among its members, the quality and timeliness of information the
committee receives, the level of challenge between committee members
and management and how well the committee communicates its activities
and findings to the board.
Monitoring of
operations and
reporting
System of internal
control and risk
management
External and
internal audit
Risk reviews
integrity.
• Sustainability reporting annual overview.
• Fair, balanced and understandable.*
• Field trips led by the SEEAC (including visits to
Trinidad, Oman and Rotterdam refinery).
• Review of effectiveness of BP’s system of
internal control and risk management*.
• Quarterly group audit reports.
• Quarterly significant allegations and
investigations reports.
• Quarterly ethics and compliance reports.
• Annual ethics certification*.
• Ethics and compliance function remit*.
• Principal risks, viability and significant failings and
weaknesses*.
* Undertaken jointly with the audit committee.
72
BP Annual Report and Form 20-F 2015
• External auditor assurance of
sustainability reporting.
• Group audit assurance of system of
internal control.
• S&OR audit assurance (as part of group
audit).
• Explosion or release at facilities.
• Major security incidents.
• Well incident.
• Pipeline incident.
• Marine incident.
The evaluation results were generally positive. Committee members
considered that the committee continued to possess the right mix of skills
and background, had an appropriate level of support and received open and
transparent briefings from management. The committee considered that
the field trips remained an important element of its work, in particular as
such trips gave committee members the opportunity to examine how risk
management is being embedded in businesses and facilities, including
management culture. An area of focus for 2016 will be examining areas of
overlap across the committee and the audit committee in terms of how
financial and operational risk could be better managed.
Gulf of Mexico committee
Chairman’s introduction
The Gulf of Mexico committee continued to oversee the group’s response
to the Deepwater Horizon accident, ensuring the company fulfils all its
legitimate obligations while protecting and defending the interests of
the group. The major development in the year was the execution of
agreements in principle with the United States and five Gulf states
(Alabama, Florida, Louisiana, Mississippi and Texas) on 2 July. These
agreements, subject to final court approval of the proposed Consent
Decree, resolve all Clean Water Act penalties, natural resource damage
claims and various economic loss claims pursued by the Gulf states.
Assuming that the Consent Decree order is approved by the court as
anticipated, we intend to recommend to the board that the committee
ceases its activities and is stood down at the end of the first quarter of
2016. Reporting of remaining proceedings will be made directly to the
board or other committees as appropriate thereafter.
Ian Davis
Committee chair
Role of the committee
The committee was formed in July 2010 to oversee the management and
mitigation of legal and licence to operate risks arising out of the Deepwater
Horizon accident and oil spill. Its work is integrated with that of the board,
which retains ultimate accountability for oversight of the group’s response
to the accident.
Key responsibilities
• Oversee the legal strategy for litigation, investigations and suspension/
debarment actions arising from the accident and its aftermath, including
the strategy connected with settlements and claims.
• Review the environmental work to remediate or mitigate the effects of
the oil spill in the waters of the Gulf of Mexico and on the affected
shorelines.
• Oversee management strategy and actions to restore the group’s
reputation in the US.
• Review compliance with government settlement agreements arising out
of the Deepwater Horizon accident and oil spill, including the SEC
Consent Order, the Department of Justice plea agreement and the EPA
administrative agreement. This is done in co-ordination with other
committees and board oversight.
Members
Ian Davis (chair)
Member since July 2010; committee chair
since July 2010
Paul Anderson
Member since July 2010
Alan Boeckmann
Member since September 2014
Frank Bowman
Member since February 2012
George David
Member from July 2010 to April 2015
George David ceased to be a member of the committee when he retired
from the board in April 2015.
Meetings and attendance
There were five committee meetings in 2015, including one by
teleconference. All directors attended every meeting for which they were
eligible, with the exception of George David who did not attend the
committee meeting called at short notice on 9 February 2015 due to a prior
commitment.
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Gulf of Mexico committee focus in 2015
• Multi-district litigation 2179 and 2185.
• Natural resource damages.
• Suspension and debarment actions.
• Claims administration.
• Other litigation and investigation.
• External affairs and community outreach.
• US government and media communications.
• Internal communications.
• Licence to operate.
• Response and remediation activities.
• Natural resource damages assessment.
• Restoration projects.
Legal
Operational
Reputation
Compliance
• Department of Justice plea agreement.
• SEC consent order.
★ Defined on page 256.
BP Annual Report and Form 20-F 2015
73
Geopolitical committee
Chairman’s and nomination committees
Chairman’s introduction
I am pleased to report on the two board committees that I chair. Both
actively sought to develop the membership of the board and its
governance during the year.
Carl-Henric Svanberg
Committees’ chair
Chairman’s committee
Role of the committee
To provide a forum for matters to be discussed among the non-executive
directors.
Key responsibilities
• Evaluate the performance and the effectiveness of the group chief
executive.
• Review the structure and effectiveness of the business organization.
• Review the systems for senior executive development and determine
the succession plan for the group chief executive, the executive
directors and other senior members of executive management.
• Determine any other matter that is appropriate to be considered by
non-executive directors.
• Opine on any matter referred to it by the chairman of any committees
comprised solely of non-executive directors.
Members
The committee comprises all non-executive directors who join the
committee at the date of their appointment to the board. The chief
executive attends the committee when requested.
Activities during the year
The committee met seven times in the year. During the year the
committee:
• Monitored the progress of the Gulf of Mexico litigation and, in particular,
considered the proposals which led to the Agreements in Principle to
settle federal and state claims and claims made by local government
entities.
• Reviewed BP’s strategy in light of the continuing decline in oil prices.
• Considered the succession and organization of the executive team.
• Evaluated the performance of the chairman and chief executive.
Chairman’s introduction
I am pleased to report on the work of this committee that was formed
during 2015. I have been asked to chair this committee until the 2016
AGM, when I will retire from the board and Sir John Sawers will take the
chair.
Antony Burgmans
Committee chair
Role of the committee
The committee monitors the company’s identification and management of
geopolitical risk.
Key responsibilities
• To monitor the company’s identification and management of major and
correlated geopolitical risk and to consider reputational as well as
financial consequences:
– Major geopolitical risks are those brought about by social, economic
or political events that occur in countries where BP has material
investments that can be jeopardized;
– 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.
• To review the company’s activities in the context of political and
economic developments on a regional basis and to advise the board on
these elements in its consideration of BP’s strategy and the annual plan.
Members
Antony Burgmans
(chair)
Member and committee chair since
September 2015
Paul Anderson
Member since September 2015
Frank Bowman
Member since September 2015
Cynthia Carroll
Member since September 2015
Phuthuma Nhleko
Member since September 2015
John Sawers
Member since September 2015
Andrew Shilston
Member since September 2015
Carl-Henric Svanberg and Bob Dudley attend all committee meetings and
the executive vice president, strategy and regions and the vice president,
government and political affairs attend as required.
Activities during the year
The committee met twice during the year. During those meetings it
considered:
• The committee’s terms of reference.
• An overview of the company’s current geopolitical risks.
• The relationship of the committee with the International Advisory Board.
• The effect of the oil price on geopolitical matters.
• The company’s relationships with national oil companies.
• The company’s relationships in specific countries and regions.
74
BP Annual Report and Form 20-F 2015
Nomination committee
Role of the committee
The committee ensures an orderly succession of candidates for directors
and the company secretary.
Key responsibilities
• Identify, evaluate and recommend candidates for appointment or
reappointment as directors.
• Identify, evaluate and recommend candidates for appointment as
company secretary.
• Keep under review the mix of knowledge, skills and experience of the
board to ensure the orderly succession of directors.
• Review the outside directorship/commitments of non-executive
directors.
Members
Carl-Henric Svanberg
(chair)
Member since September 2009; committee
chair since January 2010
Paul Anderson
Member since April 2012
Cynthia Carroll
Member from May 2011 to May 2015
Antony Burgmans
Member since May 2011
Ann Dowling
Member since May 2015
Ian Davis
Member since August 2010
Brendan Nelson
Member since April 2012
Andrew Shilston
Member since May 2015, but attended
previously as senior independent director
During the year Ann Dowling and Andrew Shilston joined the committee
and Cynthia Carroll stood down.
Activities during the year
In 2014 the committee had previously identified Paula Reynolds and
Sir John Sawers as candidates to join the board; they then both joined in
May 2015. With the total number of the board standing at 15, the
committee met once during the year to carry out a broader review of board
composition and skills in light of BP’s strategy and the potential sequencing
of board retirements. The committee focused on non-executive
membership of the board as executive succession is considered in the
chairman’s committee.
By most standards the board would be considered large. The committee
notes that as Antony Burgmans and Phuthuma Nhleko will be standing
down at the 2016 AGM, the optimum size of the board should be
considered together with the skills relevant for the board and its
committees. The committee was of the view that the current board is well
balanced with an appropriate breadth of skills. Industry experience needs
to be maintained as does the balance between former chief executives and
those with different functional and sectoral expertise. The need to maintain
diversity in all forms remains a major consideration for a board in a global
business and the committee reviewed how potential appointments meet
the board’s aspirations on diversity, inclusiveness and meritocracy. The
committee also remained mindful of BP’s commitment to Lord Davies’
report and work on women on boards.
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BP Annual Report and Form 20-F 2015
75
Directors’ remuneration report
The Chairman’s Statement (which forms part of the Directors’ Remuneration Report) is located on pages 22-23. Please refer to this for an overview from
Professor Dame Ann Dowling on the performance and pay outcomes for 2015.
2015 annual report on remuneration
Highlights of the year
Strong safety and operational performance in a difficult
environment
• Responded early and decisively to lower oil price environment.
• Excellent safety standards with continuous improvement over the
past three years, leading to improvements in reliability and operations.
• Strong operating cash flow★ and underlying replacement cost profit
relative to plan.
• Net investment (organic)★ managed aggressively to reflect ‘lower for
longer’ oil price environment.
• Executive directors’ pay outcomes reflect strong operating
performance relative to plan.
• Alignment between executives and shareholders with the majority of
executive director remuneration paid in equity with lengthy retention
requirements.
Remuneration policy
Throughout this report, the word policy refers to the directors’
remuneration policy approved by shareholders at the company’s annual
general meeting on 10 April 2014. As shown below, BP’s strategy is
reflected in the measures adopted by the committee in 2016 for the
executive directors and the metrics and targets are designed to assess
performance against that strategy. Net investment (organic) has been
removed as a measure for 2016. The same measures and targets are used
for the wider management. A summary of the policy is located on pages
88-89 and the full policy is available at bp.com/remuneration and is set out
in the BP Annual Report and Form 20-F 2013. The committee has again
reviewed the terms of the executive directors’ remuneration and confirmed
Strategic priorities
77
83
84
84
84
85
88
90
Salary and benefits
Annual bonus
Deferred bonus
Performance shares
Pension
Executive directors
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78
79
80
82
Remuneration committee
Shareholder engagement
External appointments
Historical data and statistics
Directors’ shareholdings
Remuneration policy table
Non-executive directors
that malus and clawback provisions exist in all terms save the cash
element of the annual bonus. It will consider this on the next occasion that
it reviews the remuneration policy. Separate sections of this report contain
information pertaining to executive and non-executive directors. The
remuneration of executive directors is set by the remuneration committee
under delegated powers from the board. The committee makes a
recommendation to the board for the remuneration of the chairman. The
remuneration of non-executive directors is set by the board based on a
recommendation from the chairman, the group chief executive and the
company secretary.
Safe, reliable and
compliant operations
Clear priorities
Competitive
project
execution
Disciplined
financial
choices
Source
future
growth
Focus on
high-value
upstream
assets
Quality portfolio
Build high-quality
downstream businesses
Advanced
technology
Distinctive capabilities
Proven
expertise
Strong
relationships
Group key
performance
indicator.
2016 bonus and equity plans supporting BP’s strategic priorities
Short term: annual bonus
Long term: performance share plan
Safety and operational risk
Value
Relative total shareholder return
Loss of primary containment
Operating cash flow
Cumulative operating cash flow
Process safety tier 1 events
Underlying replacement cost profit
Recordable injury frequency
Corporate and functional costs
Major project delivery
Strategic imperatives:
Relative reserves replacement ratio
Safety and operational risk
Major project delivery
Creating long-term shareholder value
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BP Annual Report and Form 20-F 2015
Executive directors
Total remuneration summary 2015
The table below shows the total remuneration received by executive
directors in 2015 and reflects the following:
Salary – no increases were granted for 2015, in line with the group-wide
salary freeze. The last increase was in July 2014.
Annual bonus – the key focus for 2015 was safe and reliable operations,
delivery of strong operating cash flow relative to plan and major projects
within the year. This resulted in a final overall group score of 1.70 but
limited to 1.50 for executive directors.
Deferred bonus – 2012 deferred bonus was conditional on safety and
environmental sustainability performance over the period 2013 through to
2015. There was strong and consistent delivery against this hurdle and
2012 deferred and matching shares vested in full.
Single figure table of remuneration of executive directors in 2015 (audited)
Performance shares – vesting was based one third on relative total
shareholder return (TSR), one third on operating cash flow and one third on
strategic imperatives including safety and operational risk (S&OR), relative
reserves replacement ratio (RRR) and major project delivery★. TSR
performance was third amongst the oil majors. There was strong
performance related to operating cash flow and the strategic imperatives.
On a preliminary assessment 77.6% of the 2013-2015 award is expected
to vest.
Pension – pension figures reflect the UK requirements to show 20 times
the increase in accrued pension over the year for defined benefit plans, as
well as the company match to retirement savings plans and any cash paid
in lieu. The UK requirement overstates the true increase in value of Bob
Dudley’s US pension (see page 82 for explanation).
Remuneration is reported in the currency received by the individual
Annual remuneration
Salary
Annual cash bonusa
Benefits
Total
Vested equity
Deferred bonus and matchb
Performance shares
Total
Total remuneration
Pension
Pension and retirement savings – value increasee
Cash in lieu of future accrual
Total including pension
Bob Dudley
thousand
Dr Brian Gilvary
thousand
2015
$1,854
$1,391
$119
$3,364
2014
$1,827
$1,005
$114
$2,946
2015
£732
£549
£53
£1,334
2014
£721
£396
£51
£1,168
$2,603
$7,116c
$9,719
$3,401
$7,020d
$10,421
£1,272
£2,223c
£3,495
£0
£2,185d
£2,185
$13,083
$13,367
£4,829
£3,353
$6,519
N/A
$19,602
$3,023
N/A
$16,390
£0
£256
£5,085
£21
£252
£3,626
a This reflects the amount of bonus paid in cash with the deferred portion as set out in the conditional equity table below.
b Value of vested deferred bonus and matching shares. The amounts reported for 2015 relate to the 2012 annual bonus deferred over three years, which vested on 9 February 2016 at the market price of
£3.34 for ordinary shares and $28.95 for ADSs and include re-invested dividends on shares vested. The amounts reported for 2014 relate to the 2011 annual bonus.
c Represents the assumed vesting of shares in 2016 following the end of the relevant performance period, based on a preliminary assessment of performance achieved under the rules of the plan and
includes re-invested dividends on shares vested. In accordance with UK regulations, the vesting price of the assumed vesting is the average market price for the fourth quarter of 2015 which was £3.72
for ordinary shares and $33.81 for ADSs. The final vesting will be confirmed by the committee in second quarter 2016 and provided in the 2016 Directors’ remuneration report.
d In accordance with UK regulations, in the 2014 single figure table, the performance outcome value was based on an estimated vesting at an assumed share price of £4.27 for ordinary shares and
$40.74 for ADSs. In May 2015, after the external data became available, the committee reviewed the relative reserves replacement ratio position and assessed that the group was in first place relative
to the other oil majors. This resulted in an adjustment to the final vesting from 60.5% to 63.8%. On 7 May 2015, 167,824 ADSs for Bob Dudley and 478,090 shares for Brian Gilvary vested at prices of
$41.83 and £4.57 respectively. The 2014 values for the total vesting have increased by $628,746 for Bob Dudley and £280,827 for Brian Gilvary.
e Represents (1) the annual increase net of inflation in accrued pension multiplied by 20 as prescribed by UK regulations, and (2) in the case of Bob Dudley only, the aggregate value of the company match
under his US retirement savings arrangements. Full details are set out on page 82. In Bob Dudley’s case, the 2014 amount has been restated to reflect the revised disclosure of Mr Dudley’s
participation in the US retirement savings arrangements.
Conditional equity – to vest in future years, subject to performance
Deferred bonus in respect of bonus year
Total deferred bonus
Total deferred converted to shares Shares
Total matched shares
Shares
Vesting date
Release dateb
Value (thousand)
Performance share element
Potential maximum shares
Vesting date
Release date
a It is anticipated that the 2015 deferred bonus award will be made in May 2016.
b Deferred shares are released at vesting with the exception of matched shares which normally have a further three-year retention period.
Bob Dudley
Dr Brian Gilvary
2015a
$2,781
551,784
551,784
Feb 2019
Feb 2022
2014
$2,010
294,108
294,108
2015a
£1,097
318,042
318,042
Feb 2018 Feb 2019
Feb 2021 Feb 2022
2014
£793
176,576
176,576
Feb 2018
Feb 2021
2015-2017
2015-2017
2014-2016
685,246
1,501,770 1,304,922
Feb 2017
Feb 2018
Feb 2018
Feb 2020 Feb 2021
Feb 2021
2014-2016
605,544
Feb 2017
Feb 2020
Defined on page 256.
77
Corporate governanceBP Annual Report and Form 20-F 2015 Total remuneration in more depth
The committee, in seeking a fair outcome for pay, has for many years
sought to ensure that variable pay is based primarily on true underlying
performance and is not driven by factors over which the directors have no
control. Accordingly, the committee normalizes for changes in oil and gas
price and refining margins. Other factors such as major divestments and
Salary and benefits
Base salary
No increases were granted to executive directors for 2015, in line with
the group-wide salary freeze, therefore the 2015 salaries remained
unchanged from 1 July 2014: $1,854,000 for Bob Dudley and £731,500
for Dr Brian Gilvary.
contributions to the Gulf of Mexico restoration made in the year are also
taken into consideration. In the light of the substantial drop in the price of
oil during the three-year plan, the committee has been focused on
ensuring that its approach to normalization has been consistent with our
previous approach.
2016 implementation
The committee reviewed executive directors’ salaries in January 2016.
Given the continuing low oil price environment, no increases will be applied
to executive directors’ salaries for 2016.
Benefits
Executive directors received car-related benefits, security assistance,
insurance and medical benefits.
Annual bonus
Framework
The committee determined performance measures and their weightings
for the 2015 annual bonus at the beginning of the performance year. The
2015 bonus plan was set in the context of the group’s strategy and
short-term imperatives. It focused on two key priorities: safety and value.
Targets for each measure were challenging but realistic and were set in the
context of the current price and industry environment. Targets for the value
measures were based upon the annual plan. Threshold and maximum
were set on a linear scale around the target.
Continued improvement in safety performance remains a key focus area
and a group priority, particularly given the need to simplify the business.
Safety made up 30% of total bonus. Safety measures included loss of
primary containment, tier 1 process safety events★ and recordable injury
frequency. Challenging targets were set, both to build on the improving
trend of the last three years and to continue to reduce the number of
safety events.
2015 annual cash bonus
Safety
Value
Loss of
primary
containmenta
Tier 1
process
safety events
Recordable
injury
frequencyb
Operating
cash flow
Underlying
replacement
cost profit
Net
investment
(organic)
Corporate
and functional
costs
Major
project
delivery
Total
bonus score
Measures
Weight
On target
Maximum
Weighted
outcome %
Target
Met
Not met
Group key
performance
indicator
Maximum
Plan/target
Threshold
Outcome
10%
20%
20
10%
20%
20
10%
20%
20
20%
20%
20%
20%
40%
36
36%
20%
40%
40
40%
15%
30%
30
30%
10%
20%
20
20%
215
events
253
events
291
events
208
events
20
events
29
events
38
events
20
events
0.235/
200k hours
0.261/
200k hours
0.287/
200k hours
0.223/
200k hours
$19.7bn
$5.0bn
-24%
$17.2bn
$4.2bn
-18%
$14.7bn
$3.4bn
-7%
$19.1bn
$5.9bn
-27%
5%
6 projects
4 projects
2 projects
4 projects
11.8%
improvement
5.9%
improvement
No
improvement
17.6%
improvement
5%
10%
5
100%
200%
191% =
score
1.91
Final score
based on
committee
judgement
1.70
a Adjusted in accordance with the treatment of the LOPC KPI on page 20. Full LOPC is 235.
b Recordable injury frequency excludes biofuels.
78
BP Annual Report and Form 20-F 2015
Value measures made up 70% of total bonus. In order to simplify and
reflect both the current short-term imperatives and the 2015 priorities in
the group’s annual plan, the number of value measures was reduced from
six in 2014 to five in 2015. These measures were more heavily weighted
on operating cash flow and underlying replacement cost profit. The
economic environment was taken into account by looking at capital and
cost discipline and these were reflected through two measures – net
investment (organic) and corporate and functional cost management. As in
previous years, delivery of major projects remained a key focus area.
Bob Dudley and Dr Brian Gilvary’s annual bonus was based 100% on these
group-wide measures. Under the policy, one third of the total bonus is paid
in cash. A director is required to defer a further third in BP shares and the
final third is paid either in cash or voluntarily deferred in BP shares at the
individual’s election. Deferred shares are matched on a one-for-one basis,
and both deferred and matched shares vest after three years depending on
an assessment by the committee of safety and environmental
sustainability over the three-year period.
Based on these results, the overall group performance score was 1.91. The
committee, as is its normal practice, considered this result in the context of
the performance of the group, shareholder feedback, input from the board
and other committees, as well as the circumstances in the wider
environment. Overall, management delivered very well in terms of what
they could control. The committee agreed with the group chief executive’s
view that the dramatic dynamics in the market during the year also needed
to be recognized. He proposed a lower score and the committee agreed
that this reflected a balanced assessment of the year. A final group score
of 1.70 was agreed and applied to BP’s wider management group. In the
case of executive directors, our approved policy limits bonus to a group
score of 1.50.
The overall annual bonus for executive directors was determined by
multiplying the reduced score of 1.5 by the on-target bonus level of 150%
of salary. Both Bob Dudley and Dr Brian Gilvary deferred two thirds of their
2015 annual bonus. As a result Bob Dudley’s and Dr Brian Gilvary’s
bonuses, including the portion deferred, are shown below.
2015 outcomes
In January 2016, the committee considered the group’s performance
during 2015 against the measures and targets set out in the 2015 annual
cash bonus table.
As the table reflects, BP had an excellent year for safety and operational
performance in a difficult environment.
The company’s decision in late 2014 to plan for a ‘lower for longer’ oil price
meant that the leadership acted early and decisively to respond to the low
oil price environment. Strong and continually improving safety standards
have led to higher reliability and improved operations, contributing directly
to better financial outcomes. Cost reduction and net investment have been
managed so as not to compromise future growth. Major projects have
been delivered on time, improving forthcoming performance.
Safety performance was again very encouraging, resulting in maximum
scores for all three measures – tier 1 process safety events, loss of primary
containment and recordable injury frequency.
Operating cash flow for the company was $19.1 billion, well ahead of the
board’s approved plan of the target of $17.2 billion. This target was
normalized upwards since the actual oil price during the year was higher
than original plan assumptions. Underlying replacement cost profit of $5.9
billion was also significantly ahead of the target of $4.2 billion, again
normalized similar to the above. Through greater simplification and
efficiency across all functions, corporate and functional costs were
reduced by 17.6% against a targeted reduction of 5.9%. Capital discipline
was demonstrated through a reduction in the net investment (organic) of
27% against a planned reduction of 18%. Four major projects were
successfully delivered in 2015, as planned.
Deferred bonus
2015 outcomes
Both Bob Dudley and Dr Brian Gilvary deferred two thirds of their 2012
annual bonus in accordance with the terms of the policy then in place.
The three-year performance period concluded at the end of 2015. The
committee reviewed safety and environmental sustainability performance
over this period and sought the input of the safety, ethics and environment
assurance committee (SEEAC). Over the three-year period 2013-15 safety
performance showed steady improvement on a range of measures. All
performance hurdles were met and the group-wide operating
management system★ is now sufficiently embedded throughout the
organization to continue driving improvement in environmental as well as
safety areas.
Following the committee’s review, full vesting of the deferred and matched
shares for the 2012 deferred bonus was approved, as shown in the
following table (as well as in the single figure table on page 77).
Annual bonus summary
Bob Dudley
Dr Brian Gilvary
Overall bonus
$4,171,500
£1,645,875
Paid in cash
$1,390,500
£548,625
Deferred in BP shares
$2,781,000
£1,097,250
2016 implementation
For 2016, 100% of Bob Dudley’s and Dr Brian Gilvary’s bonus will be
based on group results.
For the 2016 annual bonus the committee will continue to focus on the
two overall themes of safety and value. Safety will continue to have a 30%
weight in the overall bonus plan. The value measures are key to short-term
performance within the group and will have an overall weight of 70%.
Continued improvement in safety remains a group priority and is fully
reflected in the measures. As in 2015, the safety targets are anchored
on a realistic and achievable improvement from the average of the previous
three years.
The value measures have been decreased from 5 in 2015 to 4 in 2016,
increasing the weight on operating cash flow and underlying replacement
cost profit and removing the net investment measure. Targets for each
measure are challenging but realistic and have been set in the context of
the current environment. As usual they will be normalized at year end to
reflect changes in oil and gas price and refining margins.
Safety and value targets will be disclosed retrospectively in the 2016
remuneration report to the extent that they are no longer considered
commercially sensitive. The full set of 2016 short-term measures are set
out in the diagram on page 76.
2012 deferred bonus vesting
Name
Bob Dudley
Dr Brian Gilvary
Shares
deferred
458,760
Total shares
Vesting
including
agreed
dividends
100% 539,424
Total
value
at vesting
$2,602,721
315,260
100% 380,905
£1,272,223
Details of the deferred bonus awards made to the executive directors in
early 2015, in relation to 2014 annual bonuses, were set out in last year’s
report. A summary of these awards is included on page 86.
2016 implementation
The committee has determined that the safety and environmental
sustainability hurdle will continue to apply to shares deferred from the
2015 bonus. All matched shares that vest in 2019 will, after sufficient
shares have been sold to pay tax, be subject to an additional three-year
retention period before being released to the individual in 2022. This further
reinforces long-term shareholder alignment and the nature of the
group’s business.
Defined on page 256.
79
Corporate governanceBP Annual Report and Form 20-F 2015 Performance shares
Framework
Performance shares were conditionally awarded to each executive director
in 2013. Maximum awards under the policy were granted representing
five-and-a-half-times salary for Bob Dudley and four-times salary for
Dr Brian Gilvary. Vesting of these awards was subject to delivering targets
set over the three-year performance period.
One third of the award was based on relative total shareholder return
(TSR), one third on operating cash flow and one third on three strategic
imperatives: relative reserves replacement ratio (RRR), safety and
operational risk (S&OR) and major projects delivery, all equally weighted.
Performance against each of these measures was designed to be aligned
with group strategy and key performance indicators (KPIs). Some
measures appear in both the annual cash bonus and performance shares
scorecards as they serve to track in-year performance as well as growth/
improvement over a three-year period.
Relative TSR represents the change in value of a BP shareholding between
the average of the fourth quarter of 2012 and the fourth quarter of 2015
compared to other oil majors (dividends are re-invested). RRR represents
organic reserves added over the three-year performance period divided by
the reserves extracted. This ratio is ranked against like-for-like organic RRR
for other oil major peers.
The 2013-15 comparator group for relative TSR (33.3% weight) and relative
RRR (11.1% weight) was Chevron, ExxonMobil, Shell and Total. The
number of conditional shares that would vest for each of the relative
performance measures for first, second and third place was set at the start
of 2013 and equals 100%, 70% and 35% respectively. This reflects the
approved rules applicable to the 2013-2015 plan. No shares would vest for
fourth or fifth place.
Operating cash flow represented a further one third of the award. BP’s
approved policy specifically states that: operating cash flow has been
identified as a core measure of strategic performance of the company.
Targets reflected agreed plans and normal operating assumptions.
For S&OR, improvement targets were set. For major project delivery, the
committee set a number of projects expected to be delivered over three
years. In reviewing project delivery the committee reviews the cost and
any delays to the original schedule.
2015 outcomes
The committee considered the performance of the group over the
three-year period of the plan and the specific achievements against
each of the targets set for the measures. The results are summarized in
the table below.
Relative TSR, representing a third of the award, was in third place versus
the comparator group resulting in 35% vesting. Consequently 11.7% of the
overall shares for this measure will vest. The significant weight associated
with this measure aligns the actual value delivered to executive directors
with that to shareholders.
Operating cash flow represented a further one third of the award. In
considering measures and targets for performance share awards BP has
historically adopted a normalized or ‘like-for-like’ approach reflecting
changes in oil and gas prices. This avoids windfall gains or penal losses in
periods of extreme volatility. The target set in 2013 for 2015 operating cash
flow was $35 billion based on the plan assumptions relating to oil and gas
price and refining margins at that time. This target was reviewed at the
start of 2015 in the light of divestments and plan assumptions relating to
environment, principally oil and gas prices and refining margins. Consistent
with its previous practice the committee normalized the operating cash
flow target. Based on the above assumptions, adjusting for major
divestments and for contributions to the Gulf of Mexico restoration made
in the year, the operating cash flow target was set at $17.7 billion. A scale
comprising threshold and maximum figures was set around the target on a
linear basis. The actual 2015 operating cash flow was $19.1 billion,
equalling the maximum set and resulting in vesting of 33.3% of all shares
for this measure.
2013-2015 performance shares
Measures
Relative total
shareholder
return
Operating
cash flow
Weight at maximum
Outcome %
33.3%
11.7%
33.3%
33.3%
33.3%
Relative
reserves
replacement
ratio
11.1%
11.1%
Safety and operational risk
11.1%
10.4%
Major
project
delivery
Total
11.1%
11.1%
100%
77.6%
Met
Not met
Group key performance indicator
11.7%
11.1%
11.1%
3.1%
Loss of primary
containmentb
3.7%
3.6%
Tier 1 process
safety events
Recordable
injury frequencyc
Maximum
Plan/target
Threshold
Outcome
First
$19.1bn
First
Outperform
peers
$17.7bn
Outperform
peers
Third
$16.2bn
Third
Third
$19.1bn
Firsta
191
events
212
events
220
events
208
events
27
events
30
events
32
events
20
events
0.220/
200k hours
0.240/
200k hours
0.260/
200k hours
0.223/
200k hours
13 projects
11 projects
9 projects
15 projects
started
a This represents a preliminary assessment.
b Adjusted in accordance with the treatment of the LOPC KPI on page 20. Full LOPC is 235.
c RIF excludes biofuels.
80
BP Annual Report and Form 20-F 2015
Strategic imperatives represented the final third. These included relative
RRR, S&OR, and major project delivery, each weighted equally.
Preliminary assessment of BP’s relative RRR indicated a positive outcome
with an expected first place amongst the comparator group. The final
ranking will be determined once the actual results for 2015 have been
published by other comparator companies. For the purposes of this report,
and in accordance with the UK regulations, first place has been assumed.
Any adjustment to this will be reported in next year’s annual report on
remuneration. Based on a provisional first place assessment, 11.1% of the
overall shares for this measure are expected to vest.
S&OR has improved significantly over the 2013-15 period, with a
downward trend over the period in tier 1 process safety events (53%),
recordable injury frequency (30%), and loss of primary containment (28%).
The operating management system continued to mature and there has
been a continual rise in assessed conformance levels. Consequently
10.4% of overall shares will vest for the safety measures.
Fifteen major projects were delivered over the three years – well ahead of
plan and resulting in full vesting for this measure. As a result, 11.1% of
overall shares will vest.
As in past years, the committee also considered the true underlying
operational and financial performance of the group during the period and
whether any other factors should be taken into account. Following this
review, the committee assessed that a preliminary 77.6% vesting was a
fair reflection of the overall performance, pending confirmation of the
relative reserves replacement ratio result. This will result in the vesting
shown in the table below.
The vested shares for current executive directors are subject to a further
three-year retention period before they will be released to the individuals in
2019.
2013-2015 performance shares preliminary outcome
Shares vested
including dividends
1,262,868
597,628
Shares
awarded
1,384,026
637,413
Bob Dudley
Dr Brian Gilvary
Value of
vested shares
$7,116,261
£2,223,176
2012-2014 final outcomes confirmation
Last year it was reported that the committee had made a preliminary
assessment of second place for the relative RRR in the 2012-2014
performance shares element. In May 2015 the committee reviewed the
results for all comparator companies as published in their reports and
accounts and assessed that BP was in first place relative to other oil majors
and that the full 11.1% of shares would vest for this performance measure
as opposed to 7.8% for second place. This resulted in a final overall vesting
of 63.8% (versus 60.5% as preliminarily outlined in the 2014 report) for the
entire award. This change is reflected in the single figure table on page 77.
2016 implementation
Consistent with application of policy and our previous approach, shares are
expected to be awarded in March 2016 to the maximum value allowed
under the policy, five-and-a-half-times salary for Bob Dudley and four-times
salary for Dr Brian Gilvary. These will be awarded under the performance
share element of the EDIP and will be subject to a three-year performance
period. Those shares that vest are subject, after tax, to an additional
three-year retention period. The 2016-2018 performance share element
will be assessed over three years based on the following measures:
relative TSR (one third); cumulative operating cash flow (one third); and
strategic imperatives (one third) including relative RRR; S∨ and major
project delivery, all equally weighted.
These measures continue to be aligned with BP’s strategic priorities of
safe, reliable and compliant operations, competitive project execution,
disciplined financial choices and sources of future growth. The committee
agreed targets and scales for measures that will be used to assess
performance at the end of the three-year performance period and these
will be disclosed retrospectively, to the extent that they are no longer
commercially sensitive.
For S&OR the committee will study annual results based on outcomes
from the annual cash bonus for the period 2016 to 2018 and make a
determination of the three-year outcome. Similarly for operating cash flow
the committee, at the end of the period, will make a determination of the
three-year outcome by comparing the cumulative actual annual results
against the cumulative actual annual targets.
TSR and RRR will be assessed on a relative basis compared with the other
oil majors Chevron, ExxonMobil, Shell and Total with the following vesting
schedule.
Relative performance ranking
BP’s ranking place versus oil majors
First
Second
Third
Fourth or fifth
Vesting percentage for each
relative performance measure
100%
80%
25%
Nil
81
Corporate governanceBP Annual Report and Form 20-F 2015 Pension
Framework
Executive directors are eligible to participate in group pension schemes
that apply in their home countries which follow national norms in terms
of structure and levels.
US pension and retirement savings
Bob Dudley participates in US pension and retirement savings plans. These
involve a combination of tax-qualified and non-qualified plans, consistent
with applicable US tax regulations. Benefits payable under non-qualified
plans are unfunded and therefore paid from corporate assets.
Details of the pension plans in which Mr Dudley participates are as follows.
The BP Retirement Accumulation Plan (US pension plan) is a US tax-qualified
plan that features a cash-balance formula and includes grandfathering
provisions under final average pay formulas for certain employees of
companies acquired by BP (including Amoco) who participated in these
predecessor company pension plans. The TNK-BP Supplemental Retirement
Plan is based on the same calculation as the benefit under the US pension
plan but reflecting service and earnings at TNK-BP.
The BP Excess Compensation (Retirement) Plan (ECRP) provides a
supplemental benefit which is the difference between (1) the benefit
accrual under the US Pension Plan and the TNK-BP Supplemental
Retirement Plan without regard to the Internal Revenue Service (IRS)
compensation limit (including for this purpose base salary, cash bonus and
bonus deferred into a compulsory or voluntary award under the deferred
matching element of the EDIP), and (2) the actual benefit payable under
the US pension plan and the TNK-BP Supplemental Retirement Plan,
applying the IRS compensation limit. The benefit calculation under the
Amoco formula includes a reduction of 5% per year if taken before age 60.
The BP Supplemental Executive Retirement Benefit Plan (SERB) is a
non-qualified supplemental plan which provides a benefit of 1.3% of final
average earnings (including, for this purpose, base salary plus cash bonus
and bonus deferred into a compulsory or voluntary award under the
deferred matching element of the EDIP) for each year of service (without
regard for tax limits) less benefits paid under all other BP (US) qualified and
non-qualified pension arrangements. The benefit payable under SERB is
unreduced at age 60 but reduced by 5% per year if separation occurs
before age 60.
Mr Dudley also participates in US retirement savings plans on the same
terms as those available to all eligible US employees. These savings plans
provide benefits to employees on or after their retirement. These are
provided through a tax-qualified plan and a non-qualified plan. The BP
Employee Savings Plan (ESP) is a US tax-qualified section 401(k) plan to
which both Mr Dudley and BP contribute within limits set by US tax
regulations. The BP Excess Compensation (Savings) Plan (ECSP) is a
non-qualified, unfunded plan under which BP provides a notional match in
respect of eligible pay that exceeds the limit under the ESP. Mr Dudley
does not contribute to the ECSP. For the purposes of the plans, eligible pay
includes base salary, cash bonus and bonus deferred into a compulsory or
voluntary award under the deferred matching element of the EDIP. Under
both plans, participants are entitled to make investment elections, involving
an investment in the relevant fund in the case of the ESP and a notional
investment (the return on which would be delivered by BP under its
unfunded commitment) in the case of the ECSP.
These retirement savings arrangements pre-date Mr Dudley’s appointment as
a director and are grandfathered as a pre-27 June 2012 obligation for the
purposes of the remuneration policy approved by shareholders in April 2014.
The cost to the company has been fully provided for within the amounts
disclosed for pensions and other post-retirement benefits in the financial
statements. Previous remuneration reports have not disclosed details of Mr
Dudley’s participation in these arrangements but following a review, BP has
determined that disclosure of the company’s contribution to these plans
should now be included in this report.
UK pension
Dr Brian Gilvary participates in a UK final salary pension plan in respect of
service prior to 1 April 2011. This plan provides a pension relating to length
of pensionable service and final pensionable salary. The disclosure of total
pension includes any cash in lieu of additional accrual that is paid to
individuals in the UK plan who have exceeded the annual allowance or
lifetime allowance under UK regulations, and have chosen to cease future
accrual of pension. Dr Gilvary falls into this category and in 2015 received a
cash supplement of 35% of salary in lieu of future service accrual.
In the event of retirement before age 60, the following early retirement
terms would apply:
• On retirement between 55 and 60, in circumstances approved by the
committee, an immediate unreduced pension in respect of the
proportion of benefit for service up to 30 November 2006, and subject
to such reduction as the plan actuary certifies in respect of the period of
service after 1 December 2006. The plan actuary has, to date, applied a
reduction of 3% per annum for each year retirement precedes 60 in
respect of the period of service from 1 December 2006 up to the leaving
date; however a greater reduction can be applied in other circumstances.
• On leaving before age 55, in circumstances approved by the committee,
a deferred pension payable from 55 or later, with early retirement terms
if it is paid before 60 as set out above.
Irrespective of this, on leaving in circumstances of total incapacity, an
immediate unreduced pension is payable from his leaving date.
2015 outcomes
Mr Dudley participates in the US pension and retirement savings plans
described above. The pension plans are aimed at an overall accrual rate
of 1.3% of final earnings (which include salary and bonus), for each year
of service. In 2015, Mr Dudley’s accrued pension increased, net of
inflation, by $309,000. This increase has been reflected in the single
figure table on page 77 by multiplying it by a factor of 20 in accordance
with the requirements of the UK regulations (giving $6,176,000). The
committee will continue to make the required disclosures in accordance
with the UK regulations; however, given the issues and differences set
out below, it would note that around 14 would be a typical annuity
factor in the US compared with the factor of 20 upon which the UK
regulations are based.
In relation to the retirement savings plans, Mr Dudley made pre-tax and
post-tax contributions in 2015 to the ESP totalling $26,500 (2014:
$26,000). For 2015 the total value of BP matching contributions in
respect of Mr Dudley to the ESP and notional matching contributions to
the ECSP was $341,000, 7% of eligible pay (2014: $374,000, 7% of
eligible pay). After adjusting for investment gains within his
accumulating unfunded ECSP account (aggregating the unfunded
arrangements relating to his overall service with BP and TNK-BP) the
amount included in the single figure table on page 77 is $343,000. The
equivalent figure for 2014 has been restated (an increase of $427,000)
to reflect the revised disclosure treatment.
Dr Gilvary participates in the UK pension arrangements described
above. In 2015 Dr Gilvary’s accrued pension did not increase and
therefore net of inflation it reduced. In accordance with the
requirements of the UK regulations, the value shown in the single figure
table on page 77 is zero. He has exceeded the lifetime allowance under
UK pension legislation and, in accordance with the policy, receives a
cash supplement of 35% of salary, which has been separately identified
in the single figure table on page 77.
The committee continues to keep under review the increase in the
value of pension benefits for individual directors. There are significant
differences in calculation of pensions between the UK and the US. US
pension benefits are not subject to cost of living adjustments after
retirement as they are in the UK.
82
BP Annual Report and Form 20-F 2015 Remuneration committee
Members
Activities during the year
During the year, the committee met five times. Key discussions and
decision items are shown in the table below.
Professor Dame Ann
Dowling (chair)
Member since July 2012; committee chair
since May 2015
Remuneration committee 2015 meetings
Jan May
Jul
Sept Dec
Antony Burgmans
Member since May 2009; committee chair
from May 2011 to May 2015
Strategy and policy
Alan Boeckmann
Member since May 2015
George David
Member from May 2009 to April 2015
Ian Davis
Member since July 2010
Andrew Shilston
Member since May 2015
2015 was a year of transition for the committee as the membership
evolved. Dame Ann Dowling took the chair from Antony Burgmans after
the May meeting. George David stood down from the board in April, Alan
Boeckmann and Andrew Shilston joined the committee.
Carl-Henric Svanberg and Bob Dudley attend meetings of the committee
except for matters relating to their own remuneration. The group chief
executive (GCE) is consulted on the remuneration of the other executive
director and the executive team and on matters relating to the performance
of the group. The group human resources director normally attends
meetings of the committee, and other executives may attend relevant parts
of those meetings. The committee consults other relevant committees of
the board, for example the SEEAC, on issues relating to the exercise of its
judgement or discretion.
Key tasks of the remuneration committee
• Determine the policy for the chairman and the executive directors (the
policy) for inclusion in the remuneration policy for all directors as required
by the regulations.
• Review and determine as appropriate the terms of engagement,
remuneration and termination of employment of the chairman and the
executive directors in accordance with the policy, and be responsible for
compliance with all remuneration issues relating to the chairman and the
executive directors required by the regulations.
• Prepare for the board an annual report to shareholders on the
implementation of the policy, so far as it relates to the chairman and the
executive directors, as required by the regulations.
• Approve the principles of any equity plan for which shareholder approval
is to be sought.
• Approve the terms of the remuneration (including pension and
termination arrangements) of the executive team as proposed by the
GCE.
• Approve changes to the design of remuneration as proposed by the
GCE, for the group leaders of the company.
• Monitor implementation of remuneration for group leaders to ensure
alignment and proportionality.
• Engage such independent consultants or other advisers as the
committee may from time to time deem necessary, at the expense of
the company.
In these tasks, regulations means regulations made from time to time
under the Companies Act 2006, the UK Corporate Governance Code
adopted by the Financial Reporting Council and the UK Listing Authority’s
Listing Rules in relation to the remuneration of directors of quoted
companies.
Review and approve directors’ remuneration
report (DRR) for 2015 AGM
Consider DRR votes from 2015 AGM
Review committee tasks and operation
Review of BP remuneration strategy
Salary review
Executive directors
Executive team and leadership group
Annual bonus
Assess performance
Determine bonus for 2014
Agree measures and targets for 2015
Review measures for 2016
Consider measures and targets for 2016
Long-term equity plan
Assess performance
Determine vesting of 2012-2014 plan
Determine vesting of 2011 deferred bonus
Agree measures, targets and awards
for 2015-2017 plan
Review measures for 2016-2018 plan
Consider measures and targets
for 2016-2018 plan
Other items
Review principles for target setting
and disclosure
Other issues as required
Independence and advice
Independence
The board considers all committee members to be independent with no
personal financial interest, other than as shareholders, in the committee’s
decisions.
Advice
During 2015 David Jackson, the company secretary, who is employed by
the company and reports to the chairman of the board, acted as secretary
to the remuneration committee. The company secretary periodically
reviews the independence of the committee’s advisers.
Gerrit Aronson, an independent consultant, is the committee’s
independent adviser with experience of advising a number of companies in
the UK and Europe. He is engaged directly by the committee. Advice and
services on particular remuneration matters were also received from other
external advisers appointed by the committee.
Willis Towers Watson provided information on the global remuneration
market, principally for benchmarking purposes. Freshfields Bruckhaus
Deringer LLP provided legal advice on specific compliance matters to the
committee. Both firms provide other advice in their respective areas to the
group.
Total fees or other charges (based on an hourly rate) paid in 2015 to the
above advisers for the provision of remuneration advice to the committee
as set out above (save in respect of legal advice) are as follows:
Gerrit Aronson £130,000
Willis Towers Watson £38,309
83
Corporate governanceBP Annual Report and Form 20-F 2015 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 accept one non-executive appointment, from which
they may retain any fee. External appointments are subject to agreement
by the chairman and reported to the board. Any external appointment must
not conflict with a director’s duties and commitments to BP. Details of
appointments during 2015 are shown below.
Director
Bob Dudley
Appointee company
Rosnefta
Additional position held at
appointee company
Director
Total fees
0
a Bob Dudley holds this appointment as a result of the company’s shareholding in Rosneft.
Historical data and statistics
Historical TSR performance
FTSE 100
BP
£200
£150
£100
£50
i
g
n
d
o
h
l
0
0
1
£
l
a
c
i
t
e
h
t
o
p
y
h
f
o
e
u
a
V
l
2008
2009
2010
2011
2012
2013
2014
2015
This graph shows the growth in value of a hypothetical £100 holding in
BP p.l.c. ordinary shares over seven years, relative to a hypothetical £100
holding in the FTSE 100 Index of which the company is a constituent. The
values of the hypothetical £100 holdings at the end of the seven-year
period were £99.06 (2014: £107.45) and £190.42 (2014: £194.77)
respectively.
Committee review
The board evaluation process for 2015 included a separate questionnaire
on the work of the remuneration committee. The results were analysed by
an external consultant and discussed at the committee’s meeting in
January 2016. As part of the broader external evaluation described
elsewhere, any issues relating to the committee or its work were
discussed by the board in January 2016.
Shareholder engagement
The committee values its dialogue with major shareholders on
remuneration matters. During the year, the committee’s chair and the
company secretary held individual meetings with several larger
shareholders to ascertain their views and discuss important aspects of the
committee’s policy and its implementation. They also met key proxy
advisers. These meetings supplemented a group meeting of major
shareholders with all committee chairs and the chairman of the board
which took place in March 2015, and a regular dialogue between the
chairman and shareholders. Throughout the year this engagement
provided the committee with an important and direct perspective of
shareholder views and, together with the voting results on remuneration
matters at the AGM, was considered when making decisions.
Against the background of the encouraging vote that had taken place at the
April AGM and the dialogue with shareholders around the meeting, the
committee has noted the shareholders support for the approach taken
regarding retrospective disclosure of targets but notes they wish for
still more.
Accordingly we have this year added additional retrospective disclosure on
targets and scales for both annual bonus and long-term performance
shares. During the year, Dame Ann Dowling met with a number of the
larger shareholders and those who advise them. These have been
constructive meetings and they will be built on in the current year, to aid
the preparation of a revised remuneration policy for the chairman and the
executive directors to be presented to shareholders at the AGM in 2017.
The board’s annual report on remuneration was approved by shareholders
at the 2015 AGM. The votes on the report are shown below.
2015 AGM directors’ remuneration report vote results
Year
% vote ‘against’
2015
% vote ‘for’
88.8%
Votes withheld
11.2% 305,297,190
The committee’s remuneration policy was approved by shareholders at the
2014 AGM. The votes on the policy are shown below.
2014 AGM directors’ remuneration policy vote results
Year
% vote ‘against’
2014
% vote ‘for’
96.4%
Votes withheld
3.6% 125,217,443
The shareholder approved policy now governs the remuneration of the
directors for a period of three years expiring in 2017.
See bp.com/remuneration for a copy of the approved policy.
84
BP Annual Report and Form 20-F 2015
$7,301
Dividendsd
$11,938
Buybacksc
$4,770
Dividendsd
$7,168
History of CEO remuneration
Year
2009
2010c
2011
2012
2013
2014
2015
CEO
Hayward
Hayward
Dudley
Dudley
Dudley
Dudley
Dudley
Dudley
Total
remuneration
thousanda
£6,753
£3,890
$8,057
$8,439
$9,609
$15,086
$16,390
$19,602
Annual bonus
% of
maximum
89b
0
0
67
65
88
73
100
Performance
share vesting
% of maximum
17.5
0
0
16.7
0
45.5
63.8
77.6
a Total remuneration figures include pension. For Bob Dudley this has been restated since 2010 in
accordance with the principles explained on page 82, to include the value of the company’s
contribution to his US retirement savings arrangements. The total figure is also affected by share
vesting outcomes and these numbers represent the actual outcome for the periods up to 2011 or
the adjusted outcome in subsequent years where a preliminary assessment of the performance
for EDIP was made. For 2015, the preliminary assessment has been reflected.
b 2009 annual bonus did not have an absolute maximum and so is shown as a percentage of the
maximum established in 2010.
c 2010 figures show full year total remuneration for both Tony Hayward and Bob Dudley, although
Bob Dudley did not become CEO until October 2010.
Relative importance of spend on pay (million)
Distributions to
shareholders
Remuneration paid to
all employeesa
Capital investmentb
Directors’ shareholdings
Executive directors are required to develop a personal shareholding of five
times salary within a reasonable period of time from appointment. It is the
stated intention of the policy that executive directors build this level of
personal shareholding primarily by retaining those shares that vest in the
deferred bonus and performance share plans which are part of the EDIP.
In assessing whether the requirement has been met, the committee takes
account of the factors it considers appropriate, including promotions and
vesting levels of these share plans, as well as any abnormal share price
fluctuations. The table below shows the status of each of the executive
directors in developing this level. These figures include the value as at
22 February 2016 from the directors’ interests shown below plus the
assumed vesting of the 2013-2015 performance shares and is consistent
with the figures reported in the single figure table on page 77.
Bob Dudley
Dr Brian Gilvary
Appointment date
October 2010
Value of current
shareholding
$12,478,540
January 2012
£3,559,733
% of policy
achieved
135
97
The committee is satisfied that all executive directors’ shareholdings meet
the policy requirement.
The figures below indicate and include all beneficial and non-beneficial
interests of each executive director of the company in shares of BP (or
calculated equivalents) that have been disclosed to the company under the
Disclosure and Transparency Rules (DTRs) as at the applicable dates.
$22,892
$18,748
$12,928
$13,936
Current directors
Bob Dudleya
Dr Brian Gilvary
a Held as ADSs.
Ordinary
Ordinary
shares or
shares or
equivalents at
equivalents at
31 Dec 2015
1 Jan 2015
738,858 1,554,198
903,856
545,217
Ordinary
shares or
Change from
equivalents
31 Dec 2015
total at
to
22 Feb 2016
22 Feb 2016
285,366 1,839,564
201,710 1,105,566
2015
2014
2015
2014
2015
2014
Total 38.8% decrease
7.2% decrease
18.1% decrease
Dividends 1.9%
increase
No buybacks
in 2015
The following table shows both the performance shares and the deferred
bonus element awarded under the EDIP. These figures represent the
maximum possible vesting levels. The actual number of shares/ADSs that
vest will depend on the extent to which performance conditions have been
satisfied over a three-year period.
Current directors
Bob Dudleya
Dr Brian Gilvary
a Held as ADSs.
Performance
shares at
1 Jan 2015
Performance
shares at
31 Dec 2015
5,227,500 5,536,950
2,375,957 2,789,921
Performance
Change from
shares total at
31 Dec 2015 to
22 Feb 2016
22 Feb 2016
(458,760) 5,078,190
(315,260) 2,474,661
a Total remuneration reflects overall employee costs. See Financial statements – Note 34 for further
information.
b Capital investment reflects organic capital expenditure★.
c See Financial statements – Note 30 for further information.
d Dividends includes both scrip dividends as well as those paid in cash. See Financial statements –
Note 9 for further information.
At 22 February 2016, the following directors held the numbers of options
under the BP group share option schemes over ordinary shares or their
calculated equivalent set out below. None of these are subject to
performance conditions. Additional details regarding these options can be
found on page 87.
Percentage change in CEO remuneration
Comparing 2015 to 2014
% change in CEO remuneration
% change in comparator group remuneration
Salary
Benefits
Bonus
1.5% 4.4% 38.4%
0%b 27.9%
0%a
a The comparator group comprises some 31% of BP’s global employee population being
professional/managerial grades of employees based in the UK and US and employed on more
readily comparable terms.
b There was no change in employee benefits level.
Current director
Dr Brian Gilvary
Options
504,191
No director has any interest in the preference shares or debentures of the
company or in the shares or loan stock of any subsidiary company.
There are no directors or other members of senior management who own
more than 1% of the ordinary shares in issue. At 22 February 2016, all
directors and other members of senior management as a group held
interests of 17,529,149 ordinary shares or their calculated equivalent,
8,761,779 performance shares or their calculated equivalent and 6,039,841
options over ordinary shares or their calculated equivalent under the BP
group share option schemes. Senior management comprises members of
the executive team. See pages 60-61 for further information.
Defined on page 256.
85
Corporate governanceBP Annual Report and Form 20-F 2015 Deferred shares (audited)a
Bob Dudleyb
Dr Brian Gilvary
Former executive directors
Iain Conn
Dr Byron Groteb
Bonus year
Type
Performance
period
Date of award of
deferred shares
At 1 Jan
2015
Awarded
2015
At 31 Dec
2015
Potential maximum deferred shares
Number of
ordinary
shares
vested
£
Face value
of the award
Vesting date
Deferred share element interests
Interests vested in 2015 and 2016
2011
2012
2013d
2014e
2011
2012
2013d
2014e
2011
2012
2013d
2011
2012
2012-2014
Comp
2012-2014
Vol
2012-2014
Mat
2013-2015
Comp
2013-2015
Vol
2013-2015
Mat
2014-2016
Comp
2014-2016
Mat
2015-2017
Comp
2015-2017
Vol
Mat
2015-2017
DABf 2012-2014
2013-2015
2013-2015
2013-2015
2014-2016
2014-2016
2015-2017
2015-2017
2015-2017
Comp
Vol
Mat
Comp
Mat
Comp
Vol
Mat
Comp
Vol
Mat
Comp
Vol
Mat
Comp
Mat
Comp
Vol
Mat
Comp
Vol
Mat
2012-2014
2012-2014
2012-2014
2013-2015
2013-2015
2013-2015
2014-2016
2014-2016
2012-2014
2012-2014
2012-2014
2013-2015
2013-2015
2013-2015
08 Mar 2012
08 Mar 2012
08 Mar 2012
11 Feb 2013
11 Feb 2013
11 Feb 2013
12 Feb 2014
12 Feb 2014
11 Feb 2015
11 Feb 2015
11 Feb 2015
15 Mar 2012
11 Feb 2013
11 Feb 2013
11 Feb 2013
12 Feb 2014
12 Feb 2014
11 Feb 2015
11 Feb 2015
11 Feb 2015
08 Mar 2012
08 Mar 2012
08 Mar 2012
11 Feb 2013
11 Feb 2013
11 Feb 2013
12 Feb 2014
12 Feb 2014
08 Mar 2012
08 Mar 2012
08 Mar 2012
11 Feb 2013
11 Feb 2013
11 Feb 2013
109,206
109,206
218,412
114,690
114,690
229,380
149,628
149,628
–
–
–
–
–
–
–
–
– 147,054
– 147,054
– 294,108
–
73,624
–
78,815
–
78,815
–
157,630
–
96,653
–
96,653
88,288
–
–
88,288
– 176,576
–
–
–
114,690
114,690
229,380
149,628
149,628
147,054
147,054
294,108
–
78,815
78,815
157,630
96,653
96,653
88,288
88,288
176,576
–
–
–
–
–
126,444c 11 Feb 2015
–
126,444c 11 Feb 2015
–
252,894c 11 Feb 2015
–
134,856c 9 Feb 2016
–
134,856c 9 Feb 2016
–
269,712c 9 Feb 2016
–
728,688
–
728,688
–
655,861
–
–
655,861
– 1,311,722
–
–
–
–
470,700
470,700
393,764
393,764
787,529
84,491c 15 Jan 2015
95,226c 9 Feb 2016
95,226 c 9 Feb 2016
190,453c 9 Feb 2016
–
–
–
–
–
–
–
–
–
–
80,652
80,652
161,304
80,648
80,648
107,531g
100,563
33,521g
91,638
91,638
91,638g
97,278
97,278
32,424g
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
80,648
80,648
107,531g
100,563
33,521g
–
–
–
97,278
97,278
32,424g
95,196c 11 Feb 2015
95,196c 11 Feb 2015
190,393c 11 Feb 2015
97,441c 9 Feb 2016
97,441c 9 Feb 2016
129,922c 9 Feb 2016
–
–
106,104c 11 Feb 2015
106,104c 11 Feb 2015
106,104c 11 Feb 2015
114,384c 9 Feb 2016
114,384c 9 Feb 2016
38,124c 9 Feb 2016
–
–
–
–
–
–
–
–
489,742
163,247
–
–
–
–
–
–
Comp = Compulsory.
Vol = Voluntary.
Mat = Matching.
DAB = Deferred Annual Bonus Plan.
a Since 2010, vesting of the deferred shares has been subject to a safety and environmental sustainability hurdle, and this will continue. 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 will obtain advice from the SEEAC. There is no identified minimum vesting threshold level.
b Bob Dudley and Dr Byron Grote 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 Represents vestings of shares made at the end of the relevant performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares vested.
The market price of each share used to determine the total value at vesting on the vesting dates of 15 January 2015, 11 February 2015 and 9 February 2016 were £3.93, £4.46 and £3.34 respectively
and for ADSs on 11 February 2015 and 9 February 2016 were $40.35 and $28.95 respectively.
d The face value has been calculated using the market price of ordinary shares on 12 February 2014 of £4.87.
e The market price at closing of ordinary shares on 11 February 2015 was £4.46 and for ADSs was $40.35. The sterling value has been used to calculate the face value.
f Dr Brian Gilvary was granted the shares under the DAB prior to his appointment as a director. The vesting of these shares is not subject to further performance conditions and he receives deferred
shares at each scrip payment date as part of his election choice.
g All matching shares have been pro-rated to reflect actual service during the performance period and these figures have been used to calculate the face value.
86
BP Annual Report and Form 20-F 2015 Performance shares (audited)
Bob Dudleyb
Dr Brian Gilvary
Former executive directors
Iain Conn
Dr Byron Groteb
Performance
period
2012-2014
2013-2015
2014-2016e
2015-2017e
2012-2014
2013-2015
2014-2016e
2015-2017e
Date of award of
performance shares
08 Mar 2012
11 Feb 2013
12 Feb 2014
11 Feb 2015
08 Mar 2012
11 Feb 2013
12 Feb 2014
11 Feb 2015
2012-2014
2013-2015
2014-2016e
2012-2014
2013-2015
08 Mar 2012
11 Feb 2013
12 Feb 2014
08 Mar 2012
11 Feb 2013
At 1 Jan
2015
1,343,712
1,384,026
1,304,922
–
624,434
637,413
605,544
–
660,633
463,126
220,043
414,468
142,278
Share element interests
Interests vested in 2014 and 2015
Potential maximum performance sharesa
Awarded
2015
–
–
–
1,501,770
–
–
–
685,246
At 31 Dec
2015
–
1,384,026
1,304,922
1,501,770
–
637,413
605,544
685,246
Number of
ordinary
shares
vested
–
–
Vesting date
1,006,944c 7 May 2015d
1,262,868c May 2016
–
–
478,090c 7 May 2015d
597,628c May 2016
–
–
–
–
£
Face value
of the award
–
–
6,354,970
6,697,894
–
–
2,948,999
3,056,197
–
–
–
–
–
–
463,126
220,043f
–
142,278f
505,805c 7 May 2015d
434,220c May 2016
–
310,596c 7 May 2015d
129,816c May 2016
–
–
–
1,071,609
–
–
a For awards under the 2012-2014, 2013-2015, 2014-2016 and 2015-2017 plans, performance conditions are measured one third on TSR against ExxonMobil, Shell, Total and Chevron; one third on
operating cash flow; and one third on a balanced scorecard of strategic imperatives. Each performance period ends on 31 December of the third year. There is no identified overall minimum vesting
threshold level but to comply with UK regulations a value of 44.4%, which is conditional on the TSR, operating cash flow and each of the strategic imperatives reaching the minimum threshold, has
been calculated.
b Bob Dudley and Dr Byron Grote 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 Represents vestings of shares made at the end of the relevant performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares vested.
The market price of each share at the vesting date of 7 May 2015 was £4.57 and for ADSs was $41.83. For the assumed vestings dated May 2016 a price of £3.72 per ordinary share and $33.81 per
ADS has been used. These are the average prices from the fourth quarter of 2015.
d The 2012-2014 award vested on 7 May 2015, which resulted in an increase in value at vesting of £297,110 for Iain Conn and $193,922 for Byron Grote. Details for Bob Dudley and Brian Gilvary can be
found in the single figure table on page 77.
e The market price at closing of ordinary shares on 12 February 2014 was £4.87 and for ADSs was $48.38, and on 11 February 2015 was £4.46 and for ADSs was $40.35.
f Potential maximum of performance shares element has been pro-rated to reflect actual service during the performance period and these figures have been used to calculate the face value.
Share interests in share option plans (audited)
Dr Brian Gilvary
Option type
BP 2011
SAYE
At 1 Jan 2015
500,000
4,191
Granted
–
–
Exercised At 31 Dec 2015
500,000
4,191
–
–
Option price
£3.72
£3.68
Market price at
date of exercise
–
–
Date from which
first exercisable
07 Sep 2014
01 Sep 2016
Expiry date
07 Sep 2021
28 Feb 2017
Former executive directors
2,005a
–
Iain Conn
The closing market prices of an ordinary share and of an ADS on 31 December 2015 were £3.54 and $31.26 respectively.
During 2015 the highest market prices were £4.84 and $43.60 respectively and the lowest market prices were £3.23 and $29.38 respectively.
BP 2011 = BP 2011 plan. These options were granted to Dr Brian Gilvary prior to his appointment as a director and are not subject to performance conditions.
SAYE = Save As You Earn all employee share scheme.
a In accordance with the rules, potential maximum shares were pro-rated with a shorter exercise period and the option was exercised on 11 June 2015.
£3.68
2,005
£4.47
SAYE
–
01 Jan 2015
30 Jun 2015
87
Corporate governanceBP Annual Report and Form 20-F 2015
Performance framework
Remuneration policy table
This is a summary of the remuneration policy as set out in the 2014 directors’ remuneration report and approved by shareholders.
Element and purpose
Salary and benefits
Provides base-level fixed remuneration to reflect the scale and dynamics of
the business, and to be competitive with the external market.
Annual bonus
Provides a variable level of remuneration dependent on short-term
performance against the annual plan.
Deferred bonus
Reinforces the long-term nature of the business and the
importance of sustainability, linking a further part of remuneration
to equity.
Performance shares
Ties the largest part of remuneration to long-term performance. The level
varies according to performance relative to measures linked directly to
strategic priorities.
Pension
Recognizes competitive practice in home country.
88
BP Annual Report and Form 20-F 2015
Operation and opportunity
• Salaries are normally set in the home
currency of the executive director and
reviewed annually.
• Salary levels and total remuneration of oil
and other top European multinationals, and
related US corporations, are considered by
the committee. Internally, increases for the
group leaders as well as all employees in
relevant countries are considered.
• Total overall bonus (before any deferral) is
based on performance relative to
measures and targets reflected in the
annual plan, which in turn reflects BP’s
strategy.
• On-target bonus is 150% of salary with
225% as maximum.
• A third of the annual bonus is required to
be deferred and up to a further third can be
deferred voluntarily. This deferred bonus is
awarded in shares.
• Deferred shares are matched on a
one-for-one basis, and both deferred and
matched shares vest after three years
depending on an assessment by the
committee of safety and environmental
sustainability over the three-year period.
• Shares up to a maximum value of five and
a half times salary for the group chief
executive and four times salary for the
other executive directors can be awarded
annually.
• Vesting of shares after three years is
dependent on performance relative to
measures and targets reflecting BP’s
strategy.
• Executive directors participate in the
company pension schemes that apply in
their home country.
• Current UK executive directors remain on
a defined benefit pension plan and
receive a cash supplement of 35% of
salary in lieu of future service accrual
when they exceed the annual allowance
set by legislation.
Element and purpose
Operation and opportunity
• Salary increases will be in line with all
employee increases in the UK and US
and limited to within 2% of average
increase for the group leaders.
• Benefits reflect home country norms.
The current package of benefits will be
maintained, although the taxable value
may fluctuate.
• Achieving annual plan objectives equates
to on-target bonus. The level of threshold
payout for minimum performance varies
according to the nature of the measure
in question.
Performance framework
• Salary increases are not directly linked to
performance. However a base-line level of
personal contribution is needed in order to be
considered for a salary increase and
exceptional sustained contribution may be
grounds for accelerated salary increases.
• Specific measures and targets are determined
each year by the remuneration committee.
• A proportion will be based on safety and
operational risk management and is likely to
include measures such as loss of primary
containment, recordable injury frequency
and tier 1 process safety events.
• The principal measures of annual bonus will
be based on value creation and may include
financial measures such as operating cash
flow, replacement cost operating profit and cost
management, as well as operating measures
such as major project delivery, Downstream
net income per barrel and Upstream unplanned
deferrals. The specific metrics chosen each year
will be set out and explained in the annual report
on remuneration.
C
C
o
o
r
r
p
p
o
o
r
r
a
a
t
t
e
e
g
g
o
o
v
v
e
e
r
r
n
n
a
a
n
n
c
c
e
e
• Where shares vest, additional shares
representing the value of reinvested
dividends are added.
• Before being released, all matched shares
that vest after the three-year performance
period are subject (after tax) to an
additional three-year retention period.
• Both deferred and matched shares must
pass an additional hurdle related to safety and
environmental sustainability performance in
order to vest.
• If there has been a material deterioration in
safety and environmental metrics, or there
have been major incidents revealing underlying
weaknesses in safety and environmental
management then the committee, with advice
from the safety, ethics and environmental
assurance committee, may conclude that
shares vest in part, or not at all.
• All deferred shares are subject to clawback
provisions if they are found to have been
granted on the basis of materially misstated
financial or other data.
• Where shares vest, additional shares
representing the value of reinvested
dividends are added.
• Before being released, those shares that
vest after the three-year performance
period are subject (after tax) to an
additional three-year retention period.
• Performance shares will vest on the following
three performance measures:
– Total shareholder return relative to other
deemed to be more aligned to strategic
priorities. These are explained in the annual
report on remuneration.
oil majors.
– Operating cash flow.
– Strategic imperatives.
• Measures based on relative performance to oil
majors will vest 100%, 80%, 25% for first,
second and third place finish respectively and
0% for fourth or fifth position.
• The committee may exercise judgement to
adjust vesting outcomes if it concludes that the
formulaic approach does not reflect the true
underlying performance of the company’s
business or is inconsistent with shareholder
benefits.
• All performance shares are subject to
• The committee identifies the specific strategic
imperatives to be included every year and may
also alter the other measures if others are
clawback provisions if they are found to have
been granted on the basis of materially
misstated financial or other data.
• Current US executive directors participate
• Pension in the UK is not directly linked to
in transition arrangements related to
heritage plans of Amoco and Arco and
normal defined benefit plans that apply to
executives with an accrual rate of 1.3% of
final earnings (salary plus bonus) for each
year of service.
performance.
• Pension in the US includes bonus in
determining benefit level.
BP Annual Report and Form 20-F 2015
89
Non-executive directors
This section of the directors’ remuneration report completes the directors’ annual report on remuneration with details for the chairman and non-executive
directors (NEDs). The board’s remuneration policy for the NEDs was approved at the 2014 AGM. This policy was implemented during 2014. There has
been no variance of the fees or allowances for the chairman and the NEDs during 2015.
Chairman
Basic fee
• Remuneration is in the form of cash fees, payable monthly. Remuneration practice is consistent with recognized best practice standards for a
chairman’s remuneration and as a UK-listed company, the quantum and structure of the chairman’s remuneration will primarily be compared against
best UK practice.
Operation and opportunity
• The quantum and structure of chairman’s remuneration is reviewed annually by the remuneration committee, which makes a recommendation to the
board.
Benefits and expenses
• The chairman is provided with support and reasonable travelling expenses.
Operation and opportunity
• The chairman is provided with an office and full time secretarial and administrative support in London and a contribution to an office and secretarial
support in Sweden. A chauffeured car is provided in London, together with security assistance. All reasonable travelling and other expenses
(including any relevant tax) incurred in carrying out his duties is reimbursed.
The maximum remuneration for non-executive directors is set in accordance with the Articles of Association.
Fee structure
The table below shows the fee structure for the chairman in place since
1 May 2013. He is not eligible for committee chairmanship and
membership fees or intercontinental travel allowance. He has the use
of a fully maintained office for company business, a chauffeured car and
security advice in London. He receives a contribution to an office and
secretarial support as appropriate to his needs in Sweden.
Chairman
Fee level
£ thousand
785
The table below shows the fees paid for the chairman for the year ending
31 December 2015.
2015 remuneration (audited)
£ thousand
Carl-Henric Svanberg
Fees
2014
785
2015
785
Benefitsa
2015
38
2014
37
2015
823
Total
2014
822
a Benefits include travel and other expenses relating to the attendance at board and other
meetings. Amounts disclosed have been grossed up using a tax rate of 45%, where relevant, as
an estimation of tax due.
Chairman’s interests
The figures below include all the beneficial and non-beneficial interests of
the chairman in shares of BP (or calculated equivalents) that have been
disclosed under the DTRs as at the applicable dates. The chairman’s
holdings represented as a percentage against policy achieved are 944%.
Ordinary
shares or
equivalents at
1 Jan 2015
Ordinary
shares or
equivalents at
31 Dec 2015
1,076,695 2,076,695
Change from
31 Dec 2015
to
22 Feb 2016
Ordinary
shares or
equivalents
total at
22 Feb 2016
– 2,076,695
Chairman
Carl-Henric Svanberg
90
BP Annual Report and Form 20-F 2015
Non-executive directors
Basic fee
• 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 quantum and structure of NED director remuneration will primarily be compared
against best UK practice.
Operation
• The quantum and structure of NEDs’ remuneration is reviewed by the chairman, the group chief executive and the company secretary who make a
recommendation to the board; the NEDs do not vote on their own remuneration.
• Remuneration for non-executive directors is reviewed annually.
Committee fees and allowances
Intercontinental allowance
• The NEDs receive an allowance to reflect the global nature of the Company’s business. The allowance is payable for transatlantic or equivalent
intercontinental travel for the purpose of attending a board or committee meeting or site visits.
Operation
• The allowance will be paid in cash following each event of intercontinental travel.
Committee chairmanship fee
• Those NEDs who chair a committee receive an additional fee. The committee chairmanship fee reflects the additional time and responsibility in
chairing a committee of the board, including the time spent in preparation and liaising with management.
Committee membership fee
• NEDs receive a fee for each committee on which they sit other than as a chairman. The committee membership fee reflects the time spent in
attending and preparation for a committee of the board.
Operation
• Fees for committee chairmanship and membership are determined annually and paid in cash.
The senior independent director (SID)
• In the light of the SID’s broader role and responsibilities, the SID is paid a single fee and is entitled to other fees relating to committees whether as
chair or member.
Operation
• The fee for the SID will be determined from time to time, and is paid in cash monthly.
Benefits and expenses
• The NEDs are provided with support and reasonable travelling expenses.
Operation
• NEDs are reimbursed for all reasonable travelling and subsistence expenses (including any relevant tax) incurred in carrying out their duties.
Professional fees
• Fees will be reimbursed in the form of cash, payable following assistance.
Operation
• 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.
The maximum remuneration for non-executive directors is set in accordance with the Articles of Association.
91
Corporate governanceIntercontinental allowanceCommittee chairmanship feeCommittee membership feeThe senior independent director (SID)Professional fees BP Annual Report and Form 20-F 2015 Fee structure
The table below shows the fee structure for non-executive directors from
1 May 2014:
2015 remuneration (audited)
£ thousand
Senior independent directora
Board member
Audit, geopolitical, Gulf of Mexico, remuneration and
SEEA committees chairmanship feesb
Committee membership feec
Intercontinental travel allowance
Fee level
£ thousand
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 chairmen do not receive an additional membership fee for the committee they chair.
c For members of the audit, geopolitical, Gulf of Mexico, SEEA and remuneration committees.
Paul Anderson
Alan Boeckmann
Admiral Frank Bowman
Antony Burgmans
Cynthia Carroll
George Davidb
Ian Davis
Professor Dame Ann
Dowlingc
Brendan Nelson
Phuthuma Nhleko
Paula Rosput Reynoldsd
Sir John Sawersd
Andrew Shilston
Fees
Benefitsa
Total
2015
177
178
177
149
127
60
145
141
125
167
93
85
165
2014
175
70
165
150
125
185
150
140
125
150
–
–
150
2015
28
14
12
19
68
15
3
1
11
11
56
0
3
2014
48
17
17
9
66
18
5
11
16
9
–
–
8
2015
205
192
189
168
195
75
148
142
136
178
149
85
168
2014
223
87
182
159
191
203
155
151
141
159
–
–
158
a Benefits include travel and other expenses relating to the attendance at board and other
meetings. Amounts disclosed have been grossed up using a tax rate of 45%, where relevant, as
an estimation of tax due.
b Retired on 16 April 2015.
c In addition, Professor Dame Ann Dowling received £25,000 for chairing and being a member of
the BP technology advisory council.
d Appointed on 14 May 2015.
Non-executive director interests
The figures below indicate and include all the beneficial and non-beneficial interests of each non-executive director of the company in shares of BP
(or calculated equivalents) that have been disclosed to the company under the DTRs as at the applicable dates.
Paul Anderson
Alan Boeckmann
Admiral Frank Bowman
Antony Burgmans
Cynthia Carroll
George Davidb
Ian Davis
Professor Dame Ann Dowling
Brendan Nelson
Phuthuma Nhleko
Paula Rosput Reynoldsc
Sir John Sawersc
Andrew Shilston
a Held as ADSs.
b Retired on 16 April 2015.
c Appointed on 14 May 2015.
Ordinary shares
or equivalents at
1 Jan 2015
30,000a
43,890a
16,320a
10,156
10,500a
579,000a
22,420
22,320
11,040
–
–
–
15,000
Ordinary shares
or equivalents at
31 Dec 2015
30,000a
44,772a
24,864a
10,156
10,500a
–
23,854
22,320
11,040
–
52,200a
13,528
15,000
Change from
31 Dec 2015 to
22 Feb 2016
–
–
–
–
–
–
–
–
–
–
–
–
–
Ordinary shares
or equivalents
total at
22 Feb 2016
30,000a
44,772a
24,864a
10,156
10,500a
–
23,854
22,320
11,040
–
52,200a
13,528
15,000
Value of
current
shareholding
$151,500
$226,099
$125,563
£36,257
$53,025
–
£85,159
£79,682
£39,413
–
$263,610
£48,295
£53,550
% of policy
achieved
110
164
91
40
39
–
95
89
44
0
192
54
45
Past directors
Sir Ian Prosser (who retired as a non-executive director of BP in April 2010) was appointed as a director and non-executive chairman of BP Pension
Trustees Limited on 1 October 2010. During 2015, he received £100,000 for this role.
This directors’ remuneration report was approved by the board and signed on its behalf by David J Jackson, company secretary on 4 March 2016.
92
BP Annual Report and Form 20-F 2015
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) as adopted by 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). In preparing the consolidated financial statements the directors
have also elected to comply with IFRSs as issued by the International
Accounting Standards Board (IASB).
Risk management and internal control
Under the UK Corporate Governance 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
group chief executive to operate the company with a comprehensive
system of controls and internal audit to identify and manage the 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 C.2 of the
Code.
The board has processes in place to:
• assess the principal risks facing the company.
• monitor the company’s system of internal control (which includes the
ongoing process for identifying, evaluating and managing the principal
risks).
In preparing those financial statements, the directors are required to:
• review the effectiveness of that system annually.
• 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 proper 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 Article 4 of
the IAS Regulation 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 in accordance with IFRS
as issued by the IASB, IFRS as adopted by the EU and in accordance
with the provisions of the Companies Act 2006, 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.
C-H Svanberg
Chairman
4 March 2016
Non-operated joint arrangements and associates have not been dealt with
as part of this board process.
A description of the principal 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 53. During the year, the board
undertook a robust assessment of the principal risks facing the company.
The principal means by which these risks are managed or mitigated are set
out in Our management of risk on page 51.
In assessing the risks faced by the company and monitoring the system of
internal control, the board and the audit, safety, ethics and environment
assurance, Gulf of Mexico 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 68 to 74.
During the year, the committees also met with management, the group
head of audit and other monitoring and assurance functions (including
group ethics and compliance, safety and operational risk, business
integrity, group control, group legal and group risk) and the external auditor
as appropriate. Responses by management to incidents that occurred
were considered by the appropriate committee or the board.
A joint meeting of the audit and safety, ethics and environment assurance
committees in January 2016 carried out an annual review of the
effectiveness of the system of internal control. In considering this system,
the committees noted that it 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.
This review included a report from the group head of audit which
summarized group audit’s consideration of the design and operation of
elements of BP’s system of internal control over significant risks arising in
the categories of strategic and commercial, safety and operational and
compliance and control and considered the control environment for the
group. The report also highlighted the results of internal audit work
conducted during the year and the remedial actions taken by management
in response to failings and weaknesses identified. Where failings or
weaknesses were identified, the board was satisfied that these were or
are being appropriately addressed by the remedial actions proposed by
management.
A statement regarding the company’s internal controls over financial
reporting is set out on page 244 (Additional disclosures, Controls and
procedures).
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
93
Corporate governanceBP Annual Report and Form 20-F 2015 Going concern
In accordance with provision C.1.3 of the Code, the directors have made an
assessment of the group’s ability to continue as a going concern and
consider it appropriate to adopt the going concern basis of accounting in
preparing the financial statements.
Longer-term viability
In accordance with provision C.2.2 of the Code, the directors have
assessed the prospects of the company over a period significantly longer
than 12 months. The directors believe that an assessment period of three
years is appropriate based on management’s reasonable expectations of
the position and performance of the company over this period, taking
account of its short-term and longer-range plans.
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 three
years.
The directors’ assessment included a review of the financial impact of the
most severe but plausible scenarios that could threaten the viability of the
company and the likely effectiveness of the potential mitigations that
management reasonably believes would be available to the company over
this period.
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.
Fair, balanced 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.
94
BP Annual Report and Form 20-F 2015 Financial
statements
96 Consolidated financial statements of the BP group
Independent auditor’s reports
Group income statement
Group statement of
comprehensive income
96
103
104
Group statement of changes in
equity
Group balance sheet
Group cash flow statement
107 Notes on financial statements
104
105
106
140
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
147
147
148
151
155
156
159
160
161
161
162
163
191
194
205
206
206
206
206
206
206
207
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
117
107
Significant accounting
policies
Significant event – Gulf of
Mexico oil spill
Non–current assets held for
sale
122
Disposals and impairment 122
Segmental analysis
124
Income statement analysis 128
Exploration expenditure
129
Taxation
129
Dividends
131
Earnings per ordinary
share
Property, plant and
equipment
131
12. Capital commitments
13. Goodwill
14.
15.
Intangible assets
Investments in joint
ventures
Investments in associates
16.
17. Other investments
Inventories
18.
Trade and other
19.
receivables
20. Valuation and qualifying
accounts
Trade and other payables
21.
133
133
134
135
136
136
139
139
139
139
140
22.
23.
Provisions
Pensions and other post-
retirement benefits
140
24. Cash and cash equivalents 146
25.
146
26. Capital disclosures and
Finance debt
analysis of changes in net
debt
27. Operating leases
28.
Financial instruments and
financial risk factors
29. Derivative financial
instruments
30. Called-up share capital
31. Capital and reserves
32. Contingent liabilities
33. Remuneration of senior
management and non-
executive directors
Employee costs and
numbers
34.
35. Auditor’s remuneration
36. Subsidiaries, joint
arrangements and
associates
37. Condensed consolidating
information on certain US
subsidiaries
169 Supplementary information on oil and natural gas
(unaudited)
Oil and natural gas exploration
and production activities
Movements in estimated net
proved reserves
170
176
Standardized measure of
discounted future net cash
flows and changes therein
relating to proved oil and gas
reserves
Operational and statistical
information
196 Parent company financial statements of BP p.l.c.
Company balance sheet
Company cash flow statement
Company statement of
changes in equity
Notes on financial statements
1. Significant accounting
policies
Taxation
Investments
2.
3.
4. Debtors
5. Creditors
Pensions
6.
196
197
197
198
198
200
200
201
201
201
Called-up share capital
7.
Capital and reserves
8.
9.
Contingent liabilities
10. Capital management
11. Share-based payments
12. Auditor’s remuneration
13. Directors’ remuneration
Explanation of transition
14.
to FRS 101
15. Related undertakings of
208
the group
BP Annual Report and Form 20-F 2015
95
Consolidated financial statements of the BP group
Independent auditor’s report on the Annual Report and Accounts to the members of BP p.l.c.
Opinion on financial statements
In our opinion:
• the financial statements give a true and fair view of the state of the group’s and of the parent company’s affairs as at 31 December 2015 and of the
group’s loss for the year then ended;
• the group financial statements have been properly prepared in accordance with IFRS as adopted by the European Union;
• the parent company financial statements have been properly prepared in accordance with United Kingdom generally accepted accounting practice
including FRS 101; and
• 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.
Separate opinion in relation to IFRS as issued by the International Accounting Standards Board
As explained in Note 1 to the consolidated financial statements, the group in addition to applying IFRS as adopted by the European Union, has also
applied IFRS as issued by the International Accounting Standards Board (IASB). In our opinion the consolidated financial statements comply with IFRS
as issued by the IASB.
What we have audited
We have audited the financial statements of BP p.l.c. for the year ended 31 December 2015 which comprise:
Group
Group balance sheet as at 31 December 2015.
Parent company
Balance sheet as at 31 December 2015.
Group income statement for the year then ended.
Cash flow statement for the year then ended.
Group statement of comprehensive income for the year then ended.
Statement of changes in equity for the year then ended.
Group statement of changes in equity for the year then ended.
Related Notes 1 to 15 to the financial statements.
Group cash flow statement for the year then ended.
Related Notes 1 to 37 to the financial statements.
The financial reporting framework that has been applied in the preparation of the group financial statements is applicable law and International Financial
Reporting Standards (IFRS) as adopted by the European Union. The financial reporting framework that has been applied in the preparation of the parent
company financial statements is applicable law and United Kingdom accounting standards (United Kingdom generally accepted accounting practice)
including FRS 101.
Our assessment of risks of material misstatement
We identified the risks of material misstatement described below as those that had the greatest effect on our overall audit strategy, the allocation of
resources in the audit and the direction of the efforts of the audit team. In addressing these risks, we have performed the procedures below which
were designed in the context of the financial statements as a whole and, consequently, we do not express any opinion on these individual areas.
These matters are unchanged from those we reported in our 2014 audit opinion.
Risk
Our response to the risk
The determination of the liabilities, contingent liabilities
and disclosures arising from the significant uncertainties
related to the Gulf of Mexico oil spill (as described on page
70 of the report of the audit committee and Notes 1 and 2 of the
financial statements).
On 2 July 2015, the group announced it had reached
agreements in principle with the United States federal
government and five Gulf states to settle all federal and state
claims arising from the incident.
The proposed Consent Decree to resolve all United States and
Gulf states natural resource damage claims and Clean Water Act
penalty claims is awaiting court approval. The United States is
expected to file a motion with the court to enter the Consent
Decree as a final settlement around the end of March, which the
court will then consider. Although there is still risk, the
agreements in principle have significantly reduced the uncertainty
associated with this element of the liability determination for 2015.
Following the agreements in principle, we concluded the
remaining uncertainties were no longer fundamental to a user’s
understanding of the financial statements and therefore we have
removed the Emphasis of Matter from our 2015 audit opinion.
There continues to be uncertainty regarding the outcome of
Plaintiffs’ Steering Committee (‘PSC’) settlements, the most
substantial category being business economic loss claims. The
8 June 2015 deadline for claims resulted in a significant number
of claims received, which have not yet been processed and
quantified. Management concluded that a reliable estimation of
the expected liability still cannot be made at 31 December 2015.
For the Gulf of Mexico oil spill the primary audit engagement
team performed the following audit procedures.
• We walked through and tested the controls designed and
operated by the group relating to the liability accounts for the
Gulf of Mexico oil spill.
• We met with the group’s legal team to understand
developments across all of the Gulf of Mexico oil spill matters
and their status. We discussed legal developments with the
group’s external lawyers and read determinations and
judgments made by the courts.
• We reviewed the agreements in principle, verifying that
specific matters were accurately reflected in the group’s
accounting and disclosures.
• With regard to PSC settlements, we engaged EY actuarial
experts to consider the analysis of available claims data
undertaken by management. We corroborated the data used
in respect of all claim categories, with specific regard to
business economic loss, this being the most complex to
estimate. Our testing included understanding and verifying
trends in the actuarial models, considering the approach in
respect of all claim categories which included comparing with
prior periods.
• We considered the accounting treatment of the liabilities,
contingent liabilities and disclosures under IFRS criteria, to
conclude whether these were appropriate in all the
circumstances.
What we concluded to
the Audit Committee
Based on our
procedures we are
satisfied that the
amounts provided by
management are
appropriate.
We are satisfied that
management is
unable to determine
a reliable estimate
for certain
obligations as
disclosed in Note 2
of the financial
statements.
Given the
agreements in
principle signed on
2 July 2015 we
consider it
appropriate that the
Emphasis of Matter
is no longer required
in our audit opinion.
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
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Risk
Our response to the risk
The significant decrease in current and future oil and gas
prices during 2015 and the impact this has had on the
carrying value of the group’s Upstream assets (as described
on page 69 of the report of the audit committee and Note 1 of
the financial statements).
Declines in commodity prices have had a significant effect on
the carrying value of the group’s assets, as evidenced by the
impairments recognized in the 2015 financial statements and in
the prior year.
The principal risk is in relation to management’s assessment of
future cash flows, which are used to project the recoverability of
tangible and intangible assets.
The estimate of oil and gas reserves and resources has a
significant impact on the financial statements, particularly
impairment testing and depreciation, depletion and
amortization (‘DD&A’) charges (as described on page 69 of
the report of the audit committee and Note 1 of the financial
statements).
The estimation of oil and natural gas reserves and resources is a
significant area of judgement due to the technical uncertainty in
assessing quantities and complex contractual arrangements
dictating the group’s share of reportable volumes.
Reserves and resources are also a fundamental indicator of the
future potential of the group’s performance.
Unauthorized trading activity within the integrated
supply & trading function and the potential impact on
revenue (as described on page 69 of the report of the audit
committee and Note 1 of the financial statements).
Unauthorized trading activity is a fraud risk associated with a
potential deliberate misstatement of the group’s trading
positions or mis-marking of positions with an intention to:
• minimize trading losses.
• maximize trading profits.
• understate profits or move profits to subsequent periods
when bonus ceilings have already been reached, to maximize
individual bonuses across financial years.
These acts would lead to an overstatement or understatement
of the group’s revenue and profits.
We extended the scope of our original planned procedures to
address the changing risk. This included further use of EY
valuation experts in critically assessing and corroborating the
revised assumptions used in impairment testing, the most
significant of these being future market oil and gas prices and
discount rates. We also focused on reserves and resources
volumes, as described elsewhere in our report.
In addressing this risk, audit procedures were performed by the
component teams at each of the group’s 14 Upstream locations
scoped-in for the audit of asset impairment and by the primary
audit engagement team for the remaining assets identified at
risk of impairment.
• We walked through and tested the controls designed and
operated by the group relating to the assessment of the
carrying value of tangible and intangible assets.
• We examined the methodology used by management to
assess the carrying value of tangible and intangible assets
assigned to cash-generating units, to determine its
compliance with accounting standards and consistency of
application.
• We corroborated estimates of future cash flows and
challenged whether these were appropriate in light of future
price assumptions and the cost budgets. We performed
sensitivity analyses over inputs to the cash flow models.
• Together with EY valuation experts we assessed specific
inputs to the determination of the discount rate, including the
risk-free rate and country risk rates, along with gearing and
cost of debt. Such inputs were benchmarked against risk
rates in international markets in which the group operates.
• We performed procedures over the completeness of the
impairment charge and exploration write-offs, also validating
that base data used in the impairment models agreed to the
underlying books and records.
Audit procedures were performed by the component teams at
each of the group’s 14 Upstream locations scoped-in for the
audit of reserves and resources and by the primary audit
engagement team.
• We tested the group’s controls over their internal certification
process for technical and commercial experts who are
responsible for reserves and resources estimation.
• We assessed the competence and objectivity of these
experts, to satisfy ourselves they were appropriately qualified
to carry out the volumes estimation.
• We confirmed that significant changes in reserves and
resources were made in the appropriate period, and in
compliance with the Discovered Resources Management
Policy (‘DRM-P’). We gave specific consideration to BP’s
reported share of reserves in joint arrangements and
associates, including Rosneft.
• Where volumetric movements had a material impact on the
financial statements, we validated these volumes against
underlying information and documentation as required by the
DRM-P, along with checking that assumptions used to
estimate reserves and resources were made in compliance
with relevant regulations.
• We validated that the updated reserves and resources
estimates were included appropriately in the group’s
consideration of impairment and in accounting for DD&A.
Audit procedures on revenue and trading were performed by
component teams and the primary audit engagement team at 7
locations across the US, UK and Singapore.
• We walked through and tested the controls designed and
operated by the group over unauthorized trading activity.
• Using analytics software we identified trades with the highest
risk of unauthorized activity so as to focus our testing on
these trades.
• We obtained confirmations directly from third parties for a
sample of trades.
• We verified the fair value of a sample of derivatives using
contract and external market prices.
• We tested the completeness of the amounts recorded in the
financial statements through performing procedures to detect
unrecorded liabilities as well as detailed cut-off procedures
around sales, purchases, trade receivables and trade
payables.
What we concluded to
the Audit Committee
BP’s oil and gas
price assumptions
are comparable to
the range seen
within the industry at
this time.
The reduction in the
pre-tax discount rate
from 12% to 11%
and the post-tax
discount rate from
8% to 7% are within
the range of our
expectation.
Based on our
procedures, we
believe the
impairment charge is
appropriate.
Based on our
procedures on the
exploration portfolio
we consider the
write-offs were
properly recorded
and remaining
carrying values are
appropriate.
Based on our
procedures we
consider that the
reserves estimations
are reasonable for
use in the
impairment testing
and calculation of
DD&A.
Based on our
procedures we
identified no matters
to report to the Audit
Committee.
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BP Annual Report and Form 20-F 2015
97
Risk
Our response to the risk
The current geopolitical environment in Russia and the
existence of US and EU economic sanctions may impact
BP’s ability to exercise significant influence over Rosneft
and the consequent accounting for the group’s interest in
Rosneft using the equity method (as described on page 69 of
the report of the audit committee and Notes 1 and 16 of the
financial statements).
Geopolitical developments (such as further sanctions) may
present changes which could diminish the ability of the group to
exert significant influence, through diminished participation in
the financial and operating policy decisions of Rosneft.
For the Rosneft operating segment the primary audit
engagement team performed the following audit procedures.
• We assessed the impact of sanctions imposed by the US and
EU to determine the effect on the group’s ability to exercise
significant influence over Rosneft. We did this through
discussion with the group’s legal team and through observing
the interaction between BP and Rosneft. We verified the
second BP-appointed director to the board of Rosneft and
considered whether BP demonstrated significant influence
under IFRS criteria.
• We considered the adequacy of the financial and other
information provided to BP to allow compliance with its
reporting obligations, observing that appropriate review was
completed by BP on the information reported.
• We provided instructions to Rosneft’s independent auditors
who reported in accordance with our timetable and
instructions.
What we concluded to
the Audit Committee
Based on our
procedures we are
satisfied that the
criteria in IFRS for
equity accounting
are met in respect of
Rosneft and that the
impact of sanctions
extant at this time
does not prevent the
exercise of
significant influence
by BP.
The scope of our audit
Our assessment of audit risk, our evaluation of materiality and our allocation of performance materiality determine our audit scope for each entity
within the group. Taken together, this enables us to form an opinion on the consolidated financial statements. We take into account size, risk profile,
the organization of the group and effectiveness of group-wide controls, changes in the business environment and other factors such as recent internal
audit results when assessing the level of work to be performed at each component.
In scoping the audit we reflect the group’s structure (Upstream, Downstream, Rosneft, Other businesses and corporate and Gulf of Mexico oil spill),
plus the group’s functions. In assessing the risk of material misstatement to the group financial statements, and to ensure we had adequate
quantitative coverage of significant accounts in the financial statements, we performed full or specific scope audit procedures over 47 components
covering the UK, US, Angola, Azerbaijan, Germany, Russia, Singapore and the group functions, representing the principal business units within the
group.
Of the 47 components selected, we performed an audit of the complete financial information of 9 components (“full scope components”) which were
selected based on their size or risk characteristics. For the remaining 38 components (“specific scope components”), we performed audit procedures
on specific accounts within that component that we considered had the potential for the greatest impact on the significant accounts in the financial
statements either because of the size of these accounts or their risk profile.
For the current year, the full scope components contributed 43% of the group’s loss before tax, 41% of the group’s revenue and 11% of the group’s
property, plant and equipment. The specific scope components contributed 29% of the group’s revenue and 55% of the group’s property, plant and
equipment. The audit scope of these components may not have included testing of all significant accounts of the component but will have contributed
to the coverage of significant accounts tested for the group. Of the 38 specific scope components, we instructed 7 of these locations to perform
specified procedures over impairment of goodwill and other intangible assets, recoverability of certain receivables and the carrying value of certain
investments held by the group.
The remaining components not subject to full or specific group scoping are not significant individually or in the aggregate. They include many small,
low risk components and balances; each remaining component represents an average of 0.02% of the total group loss before tax and 0.04% of total
group revenue. For these components, we performed other procedures, including evaluating and testing management’s group wide controls across
a range of geographies and segments, specifically testing the oversight and review controls that management has in place to ensure there are no
material misstatements in these locations. We performed analytical and enquiry procedures to address the risk of residual misstatement on a
segment-wide and component basis. We tested consolidation journals to identify the existence of any further risks of misstatement that could have
been material to the group financial statements.
Changes from the prior year
In the current year we designed full and specific procedures for in-scope components, which represents a change from the prior year when specific
scope components only, were included. This change did not result in a significant change in the level of procedures undertaken at locations.
Involvement with component teams
In establishing our overall approach to the group audit, we determined the type of work that needed to be undertaken at each of the components by
us, as the primary audit engagement team, or by component auditors from other EY global network firms operating under our instruction. Of the 9 full
scope components, audit procedures were performed on 5 of these directly by the primary audit engagement team. For the 38 specific scope
components, audit procedures were performed on 18 directly by the primary audit engagement team. Where work was performed by component
auditors, we determined the appropriate level of involvement to enable us to determine that sufficient audit evidence had been obtained as a basis for
our opinion on the group as a whole.
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
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BP Annual Report and Form 20-F 2015
The group audit team continued to follow a programme of planned visits designed to ensure that the Senior Statutory Auditor or his designate visits
significant locations to ensure the audit is executed and delivered in accordance with the planned approach and to confirm the quality of the audit work
undertaken. During the current year’s audit cycle, visits were undertaken by the primary audit engagement team to the component teams in the US,
Angola, Azerbaijan, Germany and Russia. Part of the purpose of these visits is to confirm that appropriate procedures have been performed by the
auditors of the components and that the significant audit areas were covered as communicated in the detailed audit instructions, including the risks of
material misstatement as outlined above. The primary audit engagement team review included examining key working papers and conclusions where
these related to areas of management and auditor judgement with specific focus on the risks detailed above. The primary audit engagement team also
participated in the component teams’ planning, during visits made earlier in the audit period. Telephone and video meetings were held with the
auditors at locations which the primary audit engagement team did not visit in person. This, together with additional procedures performed at group
level, gave us appropriate evidence for our opinion on the group financial statements.
One of the significant locations is Russia, which includes Rosneft, a material associate not controlled by BP. We were provided with appropriate access
to Rosneft’s auditor in order to ensure they had completed the procedures required by ISA 600 on the financial statements of Rosneft, used as the
basis for BP’s equity accounting.
Our application of materiality
We apply the concept of materiality in planning and performing the audit, in evaluating the effect of identified misstatements on the audit and in
forming our audit opinion.
Materiality
The magnitude of an omission or misstatement that, individually or in the aggregate, could reasonably be expected to influence the economic
decisions of the users of the financial statements. Materiality provides a basis for determining the nature and extent of our audit procedures.
We determined materiality for the group to be $0.5 billion (2014 $1 billion), which is 5.7% (2014 5%) of underlying replacement cost profit (as
defined on page 258) before interest and taxation. We believe that underlying replacement cost profit before interest and taxation is the most
appropriate measure upon which to calculate materiality, due to the fact it excludes the impact of both changes in crude oil and product prices and
items disclosed as non-operating items that can significantly distort the group’s results.
During the course of our audit, we re-assessed initial materiality in the context of the group’s performance and this resulted in no change from our
original assessment of materiality.
Performance materiality
The application of materiality at the individual account or balance level. It is set at an amount to reduce to an appropriately low level the probability
that the aggregate of uncorrected and undetected misstatements exceeds materiality.
On the basis of our risk assessments, together with our assessment of the group’s overall control environment, our judgement was that
performance materiality was 75% (2014 75%) of our materiality, namely $375 million (2014 $750 million). We have set performance materiality at
this percentage to reduce to an appropriately low level the probability that the aggregate of uncorrected and undetected misstatements exceeds
materiality.
Audit work at component locations for the purpose of obtaining audit coverage over significant financial statement accounts is undertaken based on a
percentage of total performance materiality. The performance materiality set for each component is based on the relative scale and risk of the
component to the group as a whole and our assessment of the risk of misstatement at that component. In the current year, the range of
performance materiality allocated to components was $75 million to $300 million (2014 $150 million to $640 million).
Reporting threshold
An amount below which identified misstatements are considered as being clearly trivial.
We agreed with the audit committee that we would report to them all uncorrected audit differences in excess of $25 million (2014 $50 million),
which is set at 5% of materiality, as well as differences below that threshold that, in our view, warranted reporting on qualitative grounds.
We evaluate any uncorrected misstatements against both the quantitative measures of materiality discussed above and in light of other relevant
qualitative considerations in forming our opinion.
Scope of the audit of the financial statements
An audit involves obtaining evidence about the amounts and disclosures in the financial statements sufficient to give reasonable assurance that the
financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting
policies are appropriate to the group’s and the parent company’s circumstances and have been consistently applied and adequately disclosed; the
reasonableness of significant accounting estimates made by the directors; and the overall presentation of the financial statements. In addition, we read
all the financial and non-financial information in the annual report to identify material inconsistencies with the audited financial statements and to
identify any information that is apparently materially incorrect based on, or materially inconsistent with, the knowledge acquired by us in the course of
performing the audit. If we become aware of any apparent material misstatements or inconsistencies we consider the implications for our report.
Respective responsibilities of directors and auditor
As explained more fully in the Statement of directors’ responsibilities set out on page 93, the directors are responsible for the preparation of the
financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit and express an opinion on the financial
statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards require us to comply with the
Auditing Practices Board’s Ethical Standards for Auditors.
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.
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BP Annual Report and Form 20-F 2015
99
Opinion 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; and
• 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.
Matters on which we are required to report by exception
ISAs (UK and Ireland) reporting
We are required to report to you if, in our opinion, financial and non-financial
information in the annual report is:
We have no
exceptions to report.
• materially inconsistent with the information in the audited financial statements; or
• apparently materially incorrect based on, or materially inconsistent with, our
knowledge of the group acquired in the course of performing our audit; or
• otherwise misleading.
In particular, we are required to report whether we have identified any
inconsistencies between our knowledge acquired in the course of performing the
audit and the directors’ statement that they consider the annual report and accounts
taken as a whole is fair, balanced and understandable and provides the information
necessary for shareholders to assess the entity’s position and performance, business
model and strategy; and whether the annual report appropriately addresses those
matters that we communicated to the audit committee that we consider should have
been disclosed.
We are required to report to you if, in our opinion:
• adequate accounting records have not been kept by the parent company, or
returns adequate for our audit have not been received from branches not visited by
us; or
• the parent company financial statements and the part of the Directors’
remuneration report to be audited are not in agreement with the accounting
records and returns; or
• certain disclosures of directors’ remuneration specified by law are not made; or
• we have not received all the information and explanations we require for our audit.
We are required to review:
• the directors’ statement in relation to going concern, set out on page 94, and
longer-term viability, set out on page 94; and
• the part of the Corporate governance statement relating to the company’s
compliance with the provisions of the UK Corporate Governance Code specified
for our review.
We have no
exceptions to report.
We have no
exceptions to report.
Companies Act 2006 reporting
Listing Rules review requirements
Statement on the directors’ assessment of the principal risks that would threaten the solvency or liquidity of the entity
ISAs (UK and Ireland) reporting
We have nothing
material to add or to
draw attention to.
We are required to give a statement as to whether we have anything material to add
or to draw attention to in relation to:
• the directors’ confirmation in the annual report that they have carried out a robust
assessment of the principal risks facing the entity, including those that would
threaten its business model, future performance, solvency or liquidity;
• the disclosures in the annual report that describe those risks and explain how they
are being managed or mitigated;
• the directors’ statement in the Directors’ report (Directors’ statements, page 94)
about whether they considered it appropriate to adopt the going concern basis of
accounting in preparing them, and their identification of any material uncertainties
to the entity’s ability to continue to do so over a period of at least twelve months
from the date of approval of the financial statements; and
• the directors’ explanation in the annual report as to how they have assessed the
prospects of the entity, over what period they have done so and why they consider
that period to be appropriate, and their statement as to whether they have a
reasonable expectation that the entity will be able to continue in operation and
meet its liabilities as they fall due over the period of their assessment, including
any related disclosures drawing attention to any necessary qualifications or
assumptions.
John C. Flaherty (Senior Statutory Auditor)
for and on behalf of Ernst & Young LLP, Statutory Auditor
London
4 March 2016
1.
2.
The maintenance and integrity of the BP p.l.c. web site is the responsibility of the directors; 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.
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC
100
BP Annual Report and Form 20-F 2015
Consolidated financial statements of the BP group
Report of Independent Registered Public Accounting Firm
The board of directors and shareholders of BP p.l.c.
We have audited the accompanying group balance sheets of BP p.l.c. as of 31 December 2015 and 31 December 2014, and the related group income
statement, group statement of comprehensive income, group statement of changes in equity and group cash flow statement for each of the three
years in the period ended 31 December 2015. These financial statements are the responsibility of the company’s management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the group financial position of BP p.l.c. at 31 December
2015 and 31 December 2014, and the group results of its operations and its cash flows for each of the three years in the period ended 31 December
2015, in accordance with International Financial Reporting Standards as adopted by the European Union and International Financial Reporting Standards
as issued by the International Accounting Standards Board.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), BP p.l.c.‘s internal control
over financial reporting as of 31 December 2015, based on criteria established in the UK Financial Reporting Council’s Guidance on Risk Management,
Internal Control and Related Financial and Business Reporting and our report dated 4 March 2016 expressed an unqualified opinion.
/s/ Ernst & Young LLP
London, United Kingdom
4 March 2016
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1.
2.
The maintenance and integrity of the BP p.l.c. web site is the responsibility of the directors; 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.
BP Annual Report and Form 20-F 2015
101
Consolidated financial statements of the BP group
Report of Independent Registered Public Accounting Firm
The board of directors and shareholders of BP p.l.c.
We have audited BP p.l.c.’s internal control over financial reporting as of 31 December 2015, based on criteria established in the UK Financial Reporting
Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting. BP p.l.c.’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 on page 244. Our responsibility is to express an opinion on the company’s
internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.
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.
In our opinion, BP p.l.c. maintained, in all material respects, effective internal control over financial reporting as of 31 December 2015, based on the UK
Financial Reporting Council’s Guidance.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the group balance sheets
of BP p.l.c. as of 31 December 2015 and 2014, and the related group income statement, group statement of comprehensive income, group statement
of changes in equity and group cash flow statement for each of the three years in the period ended 31 December 2015, and our report dated 4 March
2016 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
London, United Kingdom
4 March 2016
Consent of independent registered public accounting firm
We consent to the incorporation by reference of our reports dated 4 March 2016, with respect to the group financial statements of BP p.l.c., and the
effectiveness of internal control over financial reporting of BP p.l.c., included in this Annual Report and Form 20-F for the year ended 31 December
2015 in the following Registration Statements:
Registration Statement on Form F-3 (File Nos. 333-208478 and 333-208478-01) of BP Capital Markets p.l.c. and BP p.l.c.; and Registration
Statements on Form S-8 (File Nos. 333-67206, 333-79399, 333-103924, 333-123482, 333-123483, 333-131583, 333-131584, 333-132619,
333-146868, 333-146870, 333-146873, 333-173136, 333-177423, 333-179406, 333-186462, 333-186463, 333-199015, 333-200794, 333-200795,
333-207188 and 333-207189) of BP p.l.c.
/s/ Ernst & Young LLP
London, United Kingdom
4 March 2016
1.
2.
The maintenance and integrity of the BP p.l.c. web site is the responsibility of the directors; 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.
102
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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 expensesa
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 costsa
Net finance expense relating to pensions and other post-retirement benefits
Profit (loss) before taxation
Taxationa
Profit (loss) for the year
Attributable to
BP shareholders
Non-controlling interests
Earnings per share – cents
Profit (loss) for the year attributable to BP shareholders
Basic
Diluted
a See Note 2 for information on the impact of the Gulf of Mexico oil spill on these income statement line items.
Note
2015
2014
5
15
16
6
4
18
5
5
4
7
6
23
8
222,894
(28)
1,839
611
666
225,982
164,790
37,040
1,036
15,219
1,909
2,353
11,553
(7,918)
1,347
306
(9,571)
(3,171)
(6,400)
(6,482)
82
(6,400)
353,568
570
2,802
843
895
358,678
281,907
27,375
2,958
15,163
8,965
3,632
12,266
6,412
1,148
314
4,950
947
4,003
3,780
223
4,003
$ million
2013
379,136
447
2,742
777
13,115
396,217
298,351
27,527
7,047
13,510
1,961
3,441
12,611
31,769
1,068
480
30,221
6,463
23,758
23,451
307
23,758
10
10
(35.39)
(35.39)
20.55
20.42
123.87
123.12
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103
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
2015
(6,400)
2014
4,003
$ million
2013
23,758
Currency translation differences
Exchange gains (losses) on translation of foreign operations reclassified to gain or loss on sale of
(4,119)
(6,838)
(1,608)
businesses and fixed assets
Available-for-sale investments marked to market
Available-for-sale investments reclassified to the income statement
Cash flow hedges marked to market
Cash flow hedges reclassified to the income statement
Cash flow hedges reclassified to the balance sheet
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
Share of items relating to equity-accounted entities, net of tax
Income tax relating to items that will not be reclassified
29
29
29
8
23
8
Other comprehensive income
Total comprehensive income
Attributable to
BP shareholders
Non-controlling interests
a See Note 31 for further information.
Group statement of changes in equitya
At 1 January 2015
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Dividendsb
Share-based payments, net of tax
Share of equity-accounted entities’ changes in equity, net of tax
Transactions involving non-controlling interests
At 31 December 2015
At 1 January 2014
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Dividendsb
Repurchases 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
At 31 December 2014
At 1 January 2013
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Dividendsb
Repurchases 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
At 31 December 2013
a See Note 31 for further information.
b See Note 9 for further information.
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Share
capital
and
capital
Treasury
reserves
shares
43,902 (20,719)
–
–
–
–
755
–
–
43,902 (19,964)
–
–
–
–
–
–
–
Foreign
currency
translation
reserve
(3,409)
–
(3,858)
(3,858)
–
–
–
–
(7,267)
Fair
value
reserves
Profit and
loss
account
(897) 92,564
(6,482)
2,007
(4,475)
(6,659)
(99)
40
(3)
(823) 81,368
–
74
74
–
–
–
–
43,656 (20,971)
–
–
–
–
–
252
–
–
43,902 (20,719)
–
–
–
–
–
246
–
–
43,513 (21,054)
–
–
–
–
–
83
–
–
43,656 (20,971)
–
–
–
–
–
143
–
–
3,525
–
(6,934)
(6,934)
–
–
–
–
–
(3,409)
5,128
–
(1,603)
(1,603)
–
–
–
–
–
3,525
(695) 103,787
3,780
(5,547)
(1,767)
(5,850)
(3,366)
(313)
73
–
(897) 92,564
–
(202)
(202)
–
–
–
–
–
89,184
1,775
23,451
–
(2,470)
3,196
(2,470) 26,647
(5,441)
(6,923)
247
73
–
(695) 103,787
–
–
–
–
–
23
1
–
(178)
249
22
(814)
257
(4,559)
4,139
(1)
(1,397)
2,741
(1,818)
(8,218)
(8,259)
41
(8,218)
51
(1)
1
(155)
(73)
(11)
(2,584)
147
(9,463)
(4,590)
4
1,334
(3,252)
(12,715)
22
(172)
(523)
(2,000)
4
17
(24)
147
(4,137)
4,764
2
(1,521)
3,245
(892)
(8,712)
22,866
(8,903)
191
(8,712)
22,574
292
22,866
BP
shareholders’
equity
111,441
(6,482)
(1,777)
(8,259)
(6,659)
656
40
(3)
97,216
Non-
controlling
interests
1,201
82
(41)
41
(91)
–
–
20
1,171
129,302
3,780
(12,683)
(8,903)
(5,850)
(3,366)
185
73
–
111,441
118,546
23,451
(877)
22,574
(5,441)
(6,923)
473
73
–
129,302
1,105
223
(32)
191
(255)
–
–
–
160
1,201
1,206
307
(15)
292
(469)
–
–
–
76
1,105
$ million
Total
equity
112,642
(6,400)
(1,818)
(8,218)
(6,750)
656
40
17
98,387
130,407
4,003
(12,715)
(8,712)
(6,105)
(3,366)
185
73
160
112,642
119,752
23,758
(892)
22,866
(5,910)
(6,923)
473
73
76
130,407
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
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
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
C-H Svanberg Chairman
R W Dudley Group Chief Executive
4 March 2016
Note
2015
$ million
2014
130,692
11,868
20,907
8,753
10,403
1,228
183,851
659
4,787
4,442
964
2,309
31
197,043
333
18,373
31,038
5,165
1,424
837
329
29,763
87,262
–
87,262
129,758
11,627
18,660
8,412
9,422
1,002
178,881
529
2,216
4,409
1,003
1,545
2,647
191,230
272
14,142
22,323
4,242
1,838
599
219
26,389
70,024
578
70,602
261,832
284,305
31,949
3,239
6,261
6,944
1,080
5,154
54,627
97
54,724
2,910
4,283
890
46,224
9,599
35,960
8,855
40,118
3,689
7,102
6,877
2,011
3,818
63,615
–
63,615
3,587
3,199
861
45,977
13,893
29,080
11,451
108,721
108,048
163,445
171,663
98,387
112,642
97,216
1,171
98,387
111,441
1,201
112,642
11
13
14
15
16
17
19
29
8
23
18
19
29
17
24
3
21
29
25
22
3
21
29
25
8
22
23
31
31
31
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Group cash flow statement
For the year ended 31 December
Operating activities
Profit (loss) before taxation
Adjustments to reconcile profit (loss) 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
Capital expenditure
Acquisitions, net of cash acquired
Investment in joint ventures
Investment in associates
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
Net issue (repurchase) of shares
Proceeds from long-term financing
Repayments of long-term financing
Net increase (decrease) in short-term debt
Net increase (decrease) in non-controlling interests
Dividends paid
BP shareholders
Non-controlling interests
Net cash 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
Note
2015
2014
$ million
2013
(9,571)
4,950
30,221
7
5
4
6
23
23
4
4
9
1,829
15,219
1,243
(1,811)
1,614
(247)
176
1,347
(1,080)
306
321
(592)
11,792
3,375
6,796
(9,328)
(2,256)
19,133
(18,648)
23
(265)
(1,312)
1,066
1,726
110
(17,300)
–
8,173
(6,426)
473
(5)
(6,659)
(91)
(4,535)
(672)
(3,374)
29,763
26,389
3,029
15,163
8,070
(3,372)
1,911
(276)
81
1,148
(937)
314
379
(963)
1,119
10,169
3,566
(6,810)
(4,787)
32,754
(22,546)
(131)
(179)
(336)
1,820
1,671
127
(19,574)
(4,589)
12,394
(6,282)
(693)
9
(5,850)
(255)
(5,266)
(671)
7,243
22,520
29,763
2,710
13,510
(11,154)
(3,189)
1,391
(314)
173
1,068
(1,084)
480
297
(920)
1,061
(1,193)
(2,718)
(2,932)
(6,307)
21,100
(24,520)
(67)
(451)
(4,994)
18,115
3,884
178
(7,855)
(5,358)
8,814
(5,959)
(2,019)
32
(5,441)
(469)
(10,400)
40
2,885
19,635
22,520
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BP Annual Report and Form 20-F 2015
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 the BP group for the year ended 31 December 2015 were approved and signed by the group chief executive
and chairman on 4 March 2016 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 as adopted by the European Union (EU) and in accordance
with the provisions of the UK Companies Act 2006. 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. 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 2015. The accounting policies that follow have been consistently applied
to all years presented.
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 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 could 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 interests in other entities; oil and natural gas accounting, including the
estimation of reserves; the recoverability of asset carrying values; derivative financial instruments, including the application of hedge accounting;
provisions and contingencies, in particular provisions and contingencies related to the Gulf of Mexico oil spill; pensions and other post-retirement
benefits; and taxation.
Basis of consolidation
The 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, and continue to be consolidated until the date
that such 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.
Interests in other entities
Goodwill
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. 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 also 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. Such goodwill is recorded within the corresponding investment in joint ventures and associates.
Interests in joint arrangements
The results, assets and liabilities of joint ventures are incorporated in these 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 financial statements using the equity method of accounting as described below.
Significant estimate or judgement: accounting for interests in other entities
Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity; depending upon the facts
and circumstances in each case, BP may obtain control, joint control or significant influence over the entity or arrangement. Transactions which give
BP control of a business are business combinations. If BP obtains joint control of an arrangement, judgement is also required to assess whether the
arrangement is a joint operation or a joint venture. If BP has neither control nor joint control, it may be in a position to exercise significant influence
over the entity, which is then accounted for as an associate.
Since 21 March 2013, BP has owned 19.75% of the voting shares of OJSC Oil Company Rosneft (Rosneft), a Russian oil and gas company. The
Russian federal government, through its investment company OJSC Rosneftegaz, owned 69.5% of the voting shares of Rosneft at 31 December
2015. BP uses the equity method of accounting for its investment in Rosneft because under IFRS it is considered to have significant influence.
Significant influence is defined as the power to participate in the financial and operating policy decisions of the investee but is not control or joint
control. 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, Bob Dudley, has been a member of the board of directors of
BP Annual Report and Form 20-F 2015
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Rosneft since 2013 and he is a member of the Rosneft board’s Strategic Planning Committee. During 2015, a second BP-nominated director,
Guillermo Quintero, was elected to the Rosneft board. BP also holds the voting rights at general meetings of shareholders conferred by its 19.75%
stake in Rosneft. In management’s judgement, the group has significant influence over Rosneft, as defined by the relevant accounting standard, and
the investment is, therefore, accounted for as an associate. BP’s share of Rosneft’s oil and natural gas reserves is included in the estimated net
proved reserves of equity-accounted entities.
The equity method of accounting
Under the equity method, the 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 directly 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, adjustments
are made to those financial statements to bring the accounting policies used into line with those of the group.
Unrealized gains on transactions 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 events or changes in circumstances indicate that the carrying
value may not be recoverable. If any such indication 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.
The group ceases to use the equity method of accounting from the date on which it no longer has joint control over the joint venture or significant
influence over the associate, or when the interest becomes classified as an asset held for sale.
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. Replacement cost profit for the group is not a recognized measure
under IFRS. For further information see Note 5.
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 assets and liabilities, 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 taken to a separate component of equity and reported in the
statement of 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 taken to other comprehensive income. On disposal or partial disposal of a non-US dollar functional currency
subsidiary, joint venture or associate, the related cumulative exchange gains and losses recognized in equity are reclassified 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.
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 acquired separately from a business are carried initially at cost. An intangible asset acquired as part of a business combination is
measured at fair value at the date of acquisition 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 15 years. Computer software costs generally have a useful life of three to five years.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
The expected useful lives of assets are reviewed on an annual basis and, if necessary, changes in useful lives 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 recognition of proved reserves and internal approval for development, 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 as a dry hole. 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 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. When proved reserves of oil and natural gas are determined and development is approved by management, the relevant expenditure is
transferred to property, plant and equipment.
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 estimate or judgement: oil and natural gas accounting
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 work in the area, remain capitalized on the balance sheet as long as additional exploration or appraisal work is under way or firmly
planned.
It is not unusual to have exploration wells and exploratory-type stratigraphic test wells 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. 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.
One of the facts and circumstances which indicate that an entity should test such assets for impairment is that the period for which the entity has a
right to explore in the specific area has expired or will expire in the near future, and is not expected to be renewed. BP has leases in the Gulf of
Mexico making up a prospect, some with terms which were scheduled to expire at the end of 2013 and some with terms which were scheduled to
expire at the end of 2014. A significant proportion of our capitalized exploration and appraisal costs in the Gulf of Mexico relate to this prospect. This
prospect requires the development of subsea technology to ensure that the hydrocarbons can be extracted safely. BP is in negotiation with the US
Bureau of Safety and Environmental Enforcement in relation to seeking extension of these leases so that the discovered hydrocarbons can be
developed. BP remains committed to developing this prospect and expects that the leases will be renewed and, therefore, continues to carry the
capitalized costs on its balance sheet.
Property, plant and equipment
Property, plant and equipment 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 any, and, for assets that
necessarily take a substantial period of time to get ready for their intended use, 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. The capitalized value of a finance lease is also included within
property, plant and equipment.
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 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.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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 7 years
5 to 15 years
The expected useful lives of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives 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.
Significant estimate or judgement: estimation of oil and natural gas reserves
The determination of the group’s estimated oil and natural gas reserves requires significant judgements and estimates to be applied and these are
regularly reviewed and updated. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and
divestment activity, drilling of new wells, and commodity prices all impact on the determination of the group’s estimates of its oil and natural gas
reserves. 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.
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 169, which is unaudited. Details on BP’s proved reserves and production compliance and governance processes are provided on
page 228.
Estimates of oil and natural gas reserves are used to calculate depreciation, depletion and amortization charges for the group’s oil and gas properties.
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. Oil and natural gas reserves also have a direct impact on the assessment of the recoverability of asset carrying values
reported in the financial statements. If proved reserves estimates are revised downwards, earnings could be affected by changes in depreciation
expense or an immediate write-down of the property’s carrying value.
The 2015 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 169. 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 11 and Note 5
respectively.
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, 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. 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. 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 and are discounted to their present value 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.
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 cash-generating units 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.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
Significant estimate or judgement: 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 future commodity prices, the effects of inflation on operating expenses, discount rates, production profiles and
the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas and refined products.
For oil and natural gas properties, the expected future cash flows are estimated using management’s best estimate of future oil and natural gas
prices and production and reserves volumes. Judgement is also required when determining the appropriate grouping of assets into a CGU or the
appropriate grouping of CGUs for impairment testing purposes.
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.
Fair value less costs of disposal may be determined based on similar recent market transaction data or, where recent market transactions for the
asset are not available for reference, using discounted cash flow techniques. Where discounted cash flow analyses are used to calculate fair value
less costs of disposal, accounting judgements 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. The post-tax discount rate used is based upon the cost of funding
the group derived from an established model. Adjustments are made, where applicable, to take into account any specific risks relating to the country
where the cash-generating unit is located. In 2015 the discount rate used to determine recoverable amounts based on fair value less costs of
disposal was 7% (2014 8%), with a 2% premium added in higher-risk countries.
When estimating the fair value of our Upstream assets, assumptions reflect all reserves that a market participant would consider when valuing the
asset, which are usually broader in scope than the reserves used in a value-in-use test. Discounted cash flow analyses used to calculate fair value
less costs of disposal use market prices for the first five years and long-term price assumptions that are consistent with the assumptions used by
the group for investment appraisal purposes thereafter. The long-term price assumptions used in such tests are $90 per barrel for Brent in 2021
(2014 $97 per barrel in 2020) and $5.60/mmBtu for Henry Hub in 2021 (2014 $6.00/mmBtu in 2020), both inflated at a rate of 2% per annum for the
remaining life of the asset (2014 2.5%). These long-term assumptions are derived from the $80 per barrel real oil price and $5/mmBtu real Henry
Hub assumptions used for investment appraisal. In the current price environment, the market prices used for the first five years of both value-in-use
and fair value less costs of disposal impairment tests are particularly volatile. Market prices used for the first five years of both value-in-use and fair
value less costs of disposal impairment tests performed at the year end are shown in the table below:
Price assumptions for the first five years
Brent oil price ($/bbl)
Henry Hub natural gas price ($/mmBtu)
Brent oil price ($/bbl)
Henry Hub natural gas price ($/mmBtu)
2016
40
2.38
2015
61
3.11
2017
47
2.76
2016
69
3.53
2018
52
2.90
2017
73
3.82
as at 31 December 2015
2019
54
3.03
2020
56
3.18
as at 31 December 2014
2018
76
4.00
2019
77
4.15
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For value-in-use calculations, future cash flows are adjusted for risks specific to the cash-generating unit and are discounted using a pre-tax discount
rate. The pre-tax discount rate is derived from the cost of funding the group calculated using an established model, and is adjusted, where
applicable, to take into account any specific risks relating to the country where the cash-generating unit is located. In 2015 the discount rate used to
determine recoverable amounts based on value in use was 11% (2014 12%), with a 2% premium added in higher-risk countries. The discount rates
applied in assessments of impairment are reassessed each year. Reserves assumptions for value-in-use tests are restricted to proved and probable
reserves.
For value-in-use calculations relating to Upstream assets, prices for oil and natural gas used for future cash flow calculations are based on market
prices for the first five years (consistent with those shown in the table above) and the group’s flat nominal long-term price assumptions thereafter.
As at 31 December 2015, the group’s long-term flat nominal price assumptions were $90 per barrel for Brent and $6.50/mmBtu for Henry Hub (2014
$90 per barrel and $6.50/mmBtu). These long-term price assumptions are subject to periodic review.
Irrespective of whether there is any indication of impairment, BP is required to test annually for impairment of goodwill acquired in a business
combination. The group carries goodwill of approximately $11.6 billion on its balance sheet (2014 $11.9 billion), principally relating to the Atlantic
Richfield, Burmah Castrol, Devon Energy and Reliance transactions. In testing goodwill for impairment, the group uses the approach described
above to determine recoverable amount. If there are low oil or natural gas prices, refining margins or marketing margins for an extended period, the
group may need to recognize goodwill impairment charges.
The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and development
expenditure above.
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 11, Note 13 and Note 14.
Inventories
Inventories, other than inventories held for 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 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.
Leases
Finance leases are capitalized at the commencement of the lease term at the fair value of the leased item or, if lower, at the present value of the
minimum lease payments. Finance charges are allocated to each period so as to achieve a constant rate of interest on the remaining balance of the
BP Annual Report and Form 20-F 2015
111
1. Significant accounting policies, judgements, estimates and assumptions – continued
liability and are charged directly against income. Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or
the lease term.
Operating lease payments are recognized as an expense on a straight-line basis over the lease term.
Financial assets
Financial assets are recognized initially at fair value, normally being the transaction price plus, in the case of financial assets not at fair value through
profit or loss, directly attributable transaction costs. The subsequent measurement of financial assets depends on their classification, as follows:
Loans and receivables
Loans and receivables are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are
recognized in income when the loans and receivables are derecognized or impaired, as well as through the amortization process. This category of
financial assets includes trade and other receivables. 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 have a maturity of three months or less from the date of acquisition.
Financial assets at fair value through profit or loss
Financial assets at fair value through profit or loss 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 classified as held for trading and are included in this
category.
Derivatives designated as hedging instruments in an effective hedge
These derivatives 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.
Held-to-maturity financial assets
Held-to-maturity financial assets are measured at amortized cost, using the effective interest method, less any impairment.
Available-for-sale financial assets
Available-for-sale financial assets are measured at fair value, with gains or losses recognized within other comprehensive income, except for
impairment losses, and, for available-for-sale debt instruments, foreign exchange gains or losses, interest recognized using the effective interest
method, and any changes in fair value arising from revised estimates of future cash flows, which are recognized in profit or loss.
Impairment of loans and receivables
The group assesses at each balance sheet date whether a financial asset or group of financial assets is impaired. If there is objective evidence that an
impairment loss on loans and receivables carried at amortized cost has been incurred, the amount of the loss is measured as the difference between
the asset’s carrying amount and the present value of estimated future cash flows discounted at the financial asset’s original effective interest rate. The
carrying amount of the asset is reduced, with the amount of the loss recognized in the income statement.
Significant estimate or judgement: recoverability of trade receivables
Judgements are required in assessing the recoverability of overdue trade receivables and determining whether a provision against those receivables
is required. Factors considered include the credit rating of the counterparty, the amount and timing of anticipated future payments and any possible
actions that can be taken to mitigate the risk of non-payment. See Note 28 for information on overdue receivables.
Financial liabilities
The measurement of financial liabilities depends on their classification, as follows:
Financial liabilities at fair value through profit or loss
Financial liabilities at fair value through profit or loss 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 classified as held for trading and are included in this
category.
Derivatives designated as hedging instruments in an effective hedge
These derivatives 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 transaction costs. For interest-bearing loans and borrowings this is 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, except finance debt designated in a fair value hedge relationship.
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.
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 ‘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 are recognized immediately through the income statement.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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,
and how the entity will assess the hedging instrument effectiveness in offsetting the exposure to changes in the hedged item’s fair value or cash flows
attributable to the hedged risk. Such hedges are expected at inception to be highly effective in achieving offsetting changes in fair value or cash flows.
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. The group applies fair value hedge
accounting when hedging interest rate risk and certain currency risks on fixed rate borrowings.
If the criteria for hedge accounting are no longer met, or if the group revokes the designation, the accumulated adjustment to the carrying amount of a
hedged item at such time is then amortized to profit or loss over the remaining period to maturity.
Cash flow hedges
The effective portion of the gain or loss on a cash flow hedging instrument is recognized within other comprehensive income, while the ineffective
portion is recognized in profit or loss. Amounts taken to other comprehensive income are reclassified to the income statement when the hedged
transaction affects profit or loss.
Where the hedged item is 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 reclassified 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, except for cash flow hedges of variable interest rate risk which are
reclassified to finance costs.
If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or if its designation as a hedge is revoked,
amounts previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to the
income statement or to the initial carrying amount of a non-financial asset or liability as above.
Significant estimate or judgement: application of hedge accounting
The decision as to whether to apply hedge accounting within subsidiaries, and by equity-accounted entities, can have a significant impact on the
group’s financial statements. Cash flow and fair value hedge accounting is applied to certain finance debt-related instruments in the normal course of
business and cash flow hedge accounting is applied to certain highly probable foreign currency transactions as part of the management of currency
risk. See Note 16, Note 28 and Note 29 for further information.
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.
Significant estimate or judgement: valuation of derivatives
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 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 and modelled using the
maximum available external pricing information. Additionally, where limited data exists for certain products, prices are determined using historic and
long-term pricing relationships. Price volatility is also an input for options models.
Changes in the key assumptions could have a material impact on the fair value gains and losses on derivatives recognized in the income statement.
For more information see Note 29.
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, contingencies and reimbursement assets
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. A provision is discounted using either a nominal discount rate of 2.75% (2014 2.75%) or a real discount rate of
0.75% (2014 0.75%), as appropriate. 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).
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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 financial statements but are disclosed unless the possibility of an outflow of
economic resources is considered remote.
Where the group makes contributions into a separately administered fund for restoration, environmental or other obligations, which it does not control,
and the group’s right to the assets in the fund is restricted, the obligation to contribute to the fund is recognized as a liability where it is probable that
such additional contributions will be made. The group recognizes a reimbursement asset separately, being the lower of the amount of the associated
restoration, environmental or other provision and the group’s share of the fair value of the net assets of the fund available to contributors.
Significant estimate or judgement: provision relating to the Gulf of Mexico oil spill
Detailed information on the Gulf of Mexico oil spill, including the financial impacts, is provided in Note 2.
During 2015, BP signed agreements in principle, which were subject to execution of definitive agreements, to settle all federal and state claims and
claims made by more than 400 local government entities. Further detail is provided in Note 2. Certain agreements are subject to approval by the
court of a Consent Decree. A provision for amounts payable under these agreements has, therefore, been recognized. The agreements significantly
reduce the uncertainties faced by BP following the Gulf of Mexico oil spill in 2010. However, there continues to be uncertainty regarding the
outcome or resolution of current or future litigation and the extent and timing of costs relating to the incident not covered by these agreements.
The provision recognized is the reliable estimate of expenditures required to settle certain present obligations at the end of the reporting period.
There are future expenditures, however, for which it is not possible to measure the obligation reliably. These are not provided for, are disclosed as
contingent liabilities, and are described in Note 2. Contingent liabilities are disclosed in relation to business economic loss (BEL) claims under the
Plaintiffs’ Steering Committee (PSC) settlement, securities-related litigation, other litigation, including claims from parties excluded from or who
opted out of the PSC settlement, and under the settlement agreements with Anadarko and MOEX and other agreements.
Management believes that no reliable estimate can currently be made of any BEL claims not yet processed or processed but not yet paid, except
where an eligibility notice has been issued and is not subject to appeal by BP within the claims facility. The submission deadline for BEL claims
passed on 8 June 2015; no further claims can be submitted. A significant number of BEL claims have been received but have not yet been
processed and it is not possible to quantify the total value of the claims. A revised policy for the matching of revenue and expenses for BEL claims
was introduced in May 2014 and, of the claims assessable under the new policy, the majority have not yet been determined at this time. For this
and other reasons set out in Note 2, we are unable to reliably estimate future trends of the number and proportion of claims that will be determined
to be eligible, nor can we reliably estimate the value of such claims. A provision for such BEL claims will be established when these uncertainties are
sufficiently reduced and a reliable estimate can be made of the liability.
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 current prices or future assumptions, depending on the expected timing of the activity, and
discounted using the real discount rate. The weighted average period over which these costs are generally expected to be incurred is estimated to be
approximately 17 years.
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 the provision, any change in the present value of the estimated
expenditure is reflected as an adjustment to the provision and the corresponding asset.
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 current prices and discounted using a real discount rate. The weighted average period over which these costs
are generally expected to be incurred is estimated to be approximately five years.
Significant estimate or judgement: 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 well as
political, environmental, safety and public expectations. BP believes that the impact of any reasonably foreseeable change to these provisions on the
group’s results of operations, financial position or liquidity will not be material. 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, judgement must be used to determine whether BP is then
responsible for decommissioning, and if so the extent of that responsibility. The timing and amounts of future cash flows are subject to significant
uncertainty. Any changes in the expected future costs are reflected in both the provision and the asset.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
Decommissioning provisions associated with downstream and petrochemicals facilities are generally not recognized, as the potential obligations
cannot be measured, given their indeterminate settlement dates. The group performs periodic reviews of its downstream and petrochemicals long-
lived assets for any changes in facts and circumstances 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 estimates because of changes in laws and regulations, public expectations,
prices, discovery and analysis of site conditions and changes in clean-up technology.
Other provisions and liabilities are recognized in the period when it becomes probable that there will be a future outflow of funds resulting from past
operations or events and the amount of cash outflow can be reliably estimated. The timing of recognition and quantification of the liability require the
application of judgement to existing facts and circumstances, which can be subject to change. Since the cash outflows can take place many years in
the future, the carrying amounts of provisions and liabilities are reviewed regularly and adjusted to take account of changing facts and
circumstances.
The timing and amount of future expenditures are reviewed annually, together with the interest rate used in discounting the cash flows. The interest
rate used to determine the balance sheet obligation at the end of 2015 was a real rate of 0.75% (2014 0.75%), which was based on long-dated US
government bonds.
Provisions and contingent liabilities relating to the Gulf of Mexico oil spill are discussed in Note 2. Information about the group’s other provisions is
provided in Note 22. As further described in Note 32, the group is subject to claims and actions. 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 at the date at which equity instruments 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.
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 in 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 or judgement: pensions and other post-retirement benefits
Accounting for pensions and other post-retirement benefits involves judgement about uncertain events, including estimated retirement dates, salary
levels at retirement, mortality rates, determination of discount rates for measuring plan obligations and net interest expense and assumptions for
inflation rates.
These assumptions are based on the environment in each country. The assumptions used may vary from year to year, which would affect future net
income and net assets. Any differences between these assumptions and the actual outcome also affect future net income and net assets.
Pension 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 used are provided in Note 23.
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The discount rate and inflation rate have a significant effect on the amounts reported. A sensitivity analysis of the impact of changes in these
assumptions on the benefit expense and obligation is provided in Note 23.
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. Mortality assumptions reflect best practice
in the countries in which we provide pensions and have been chosen with regard to the latest available published tables adjusted where appropriate
to reflect the experience of the group and an extrapolation of past longevity improvements into the future. A sensitivity analysis of the impact of
changes in the mortality assumptions on the benefit expense and obligation is provided in Note 23.
Income taxes
Income tax expense represents the sum of current tax and deferred tax. Interest and penalties relating to income tax are also included in the income
tax expense.
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 that sufficient
taxable profit will be available to allow all or part of the deferred tax asset to be utilized.
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.
Significant estimate or judgement: income taxes
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 provisions for income taxes.
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.
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 8.
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 on an appropriate basis.
Customs duties and sales taxes
Customs duties and sales taxes which are passed on 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.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
Own equity instruments – Treasury shares
The group’s holdings in its own equity instruments are shown as deductions from shareholders’ equity at cost. 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 financial statements as treasury shares. Consideration, if any, received for the sale of such shares is also recognized in equity, with any
difference between the proceeds from sale and the original cost being taken to the profit and loss account reserve. 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
Revenue arising from the sale of goods is recognized when the significant risks and rewards of ownership have passed to the buyer, which is typically
at the point that title passes, and the revenue can be reliably measured.
Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods provided in the normal
course of business, net of discounts, customs duties and sales taxes.
Physical exchanges are reported net, as are sales and purchases made with a common counterparty, as part of an arrangement similar to a physical
exchange. Similarly, 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. Additionally, where forward sale and purchase contracts for oil, natural gas or power have been
determined to be for trading purposes, the associated sales and purchases are reported net within sales and other operating revenues whether or not
physical delivery has occurred.
Generally, revenues from the production of oil and natural gas properties in which the group has an interest with joint operation partners are recognized
on the basis of the group’s working interest in those properties (the entitlement method). Differences between the production sold and the group’s
share of production are not significant.
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.
Impact of new International Financial Reporting Standards
There are no new or amended standards or interpretations adopted during the year that have a significant impact on the financial statements.
Not yet adopted
The following pronouncements from the IASB will become effective for future financial reporting periods and have not yet been adopted by the group.
IFRS 9 ‘Financial Instruments’ will supersede IAS 39 ‘Financial Instruments: Recognition and Measurement’ and is effective for annual periods
beginning on or after 1 January 2018. IFRS 9 covers classification and measurement of financial assets and financial liabilities, impairment methodology
and hedge accounting.
IFRS 15 ‘Revenue from Contracts with Customers’ provides a single model for accounting for revenue arising from contracts with customers and is
effective for annual periods beginning on or after 1 January 2018. IFRS 15 will supersede IAS 18 ‘Revenue’.
The IASB has issued IFRS 16 ‘Leases’ which provides a new model for lease accounting in which all leases, other than short-term and small-ticket-item
leases, will be accounted for by the recognition on the balance sheet of a right-to-use asset and a lease liability, and the subsequent amortization of the
right-to-use asset over the lease term. IFRS 16 will be effective for annual periods beginning on or after 1 January 2019 and is expected to have a
significant effect on the group’s financial statements, significantly increasing the group’s recognized assets and liabilities and potentially affecting the
presentation and timing of recognition of charges in the income statement. Information on the group’s leases currently classified as operating leases,
which are not recognized on the balance sheet, is provided in Note 27.
BP does not expect to adopt IFRS 9 or IFRS 15 before 1 January 2018 and has not yet determined its date of adoption for IFRS 16. The group has not
yet completed its evaluation of the effect of adoption of these standards. The EU has not yet adopted IFRS 9, IFRS 15 or IFRS 16.
There are no other standards and 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.
2. Significant event – Gulf of Mexico oil spill
As a consequence of the Gulf of Mexico oil spill in April 2010, BP continues to incur costs and has also recognized liabilities for certain future costs.
Liabilities of uncertain timing or amount, for which no provision has been made, have been disclosed as contingent liabilities.
The cumulative pre-tax income statement charge since the incident amounts to $55.5 billion. For more information on the types of expenditure
included in the cumulative income statement charge, see Impact upon the group income statement below. The cumulative income statement charge
does not include amounts for obligations that BP considers are not possible, at this time, to measure reliably. For further information, including
developments in relation to business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement, see Provisions and contingent
liabilities below.
On 2 July 2015, agreements in principle to settle all federal and state claims and claims made by more than 400 local government entities were signed.
These agreements in principle were subject to execution of definitive agreements, including a Consent Decree with the United States and Gulf states
with respect to the Clean Water Act penalty and natural resource damages and other claims, a Settlement Agreement with five Gulf states with
respect to state claims for economic loss, property damage and other claims, and resolution to BP’s satisfaction of the economic loss, property
damage and other claims with more than 400 local government entities. The proposed Consent Decree between the United States, the Gulf states and
BP was available for public comment until early December 2015 and is subject to final court approval. The Consent Decree and Settlement Agreement
with the five Gulf states are conditional upon each other and neither will become effective unless there is final court approval of the Consent Decree.
The United States is expected to file a motion with the court to enter the Consent Decree as a final settlement around the end of March, which the
court will then consider. During 2015, the Settlement Agreement with the five Gulf states was executed. BP has accepted releases received from the
vast majority of local government entities and payments required under those releases were made during 2015. For more information on the proposed
Consent Decree and Settlement Agreement see Legal proceedings on page 238.
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The agreements described above (the Agreements) significantly reduce the uncertainties faced by BP following the Gulf of Mexico oil spill in 2010.
There continues to be uncertainty regarding the outcome or resolution of current or future litigation and the extent and timing of costs relating to the
incident not covered by the Agreements. The total amounts that will ultimately be paid by BP in relation to the incident will be dependent on many
factors, as discussed under Provisions and contingent liabilities below, including in relation to any new information or future developments. These
uncertainties could have a material impact on our consolidated financial position, results and cash flows.
The impacts of the Gulf of Mexico oil spill on the income statement, balance sheet and cash flow statement of the group are included within the
relevant line items in those statements and are shown in the table below.
Income statement
Production and manufacturing expenses
Profit (loss) before interest and taxation
Finance costs
Profit (loss) before taxation
Less: Taxation
Profit (loss) for the period
Balance sheet
Current assets
Trade and other receivables
Current liabilities
Trade and other payables
Accruals
Provisions
Net current assets (liabilities)
Non-current assets
Other receivables
Non-current liabilities
Other payables
Accruals
Provisions
Deferred tax
Net non-current assets (liabilities)
Net assets (liabilities)
Cash flow statement
Profit (loss) before taxation
Finance costs
Net charge for provisions, less payments
(Increase) decrease in other current and non-current assets
Increase (decrease) in other current and non-current liabilities
Pre-tax cash flows
2015
2014
$ million
2013
11,709
(11,709)
247
(11,956)
3,492
(8,464)
781
(781)
38
(819)
262
(557)
430
(430)
39
(469)
73
(396)
686
1,154
(693)
(40)
(3,076)
(3,123)
(655)
–
(1,702)
(1,203)
–
2,701
(2,057)
(186)
(13,431)
5,200
(10,474)
(2,412)
(169)
(6,903)
1,723
(5,060)
(13,597)
(6,263)
(11,956)
247
11,296
–
(732)
(819)
38
939
(662)
(792)
(1,145)
(1,296)
(469)
39
1,129
(1,481)
(618)
(1,400)
The impact on net cash provided by operating activities, on a post-tax basis, amounted to an outflow of $1,130 million (2014 outflow of $9 million and
2013 outflow of $73 million).
Trust fund
BP established the Deepwater Horizon Oil Spill Trust (the Trust), funded in the amount of $20 billion, to satisfy legitimate individual and business
claims, state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource
damages and related costs. Fines and penalties are not covered by the trust fund. The funding of the Trust was completed in 2012. The obligation to
fund the $20-billion trust fund, adjusted to take account of the time value of money, was recognized in full in 2010 and charged to the income
statement.
BP’s rights and obligations in relation to the $20-billion trust fund are accounted for in accordance with IFRIC 5 ‘Rights to Interests Arising from
Decommissioning, Restoration and Environmental Rehabilitation Funds’. An asset has been recognized representing BP’s right to receive
reimbursement from the trust fund. We use the term ‘reimbursement asset’ to describe this asset. BP does not actually receive any reimbursements
from the trust fund, instead payments are made directly from the trust fund, and BP is released from its corresponding obligation. This is the portion of
the estimated future expenditure provided for that will be settled by payments from the trust fund. During 2014, cumulative charges to be paid by the
Trust reached $20 billion. Subsequent additional costs, over and above those provided within the $20 billion, are expensed to the income statement as
incurred.
At 31 December 2015, $686 million of the provisions and payables are eligible to be paid from the Trust. The reimbursement asset is recorded within
Trade and other receivables on the balance sheet, all of which is classified as current, as payment of all amounts covered by the remaining
reimbursement asset may be requested during 2016. During 2015, $3,022 million of provisions and $147 million of payables were paid from the Trust.
At 31 December 2015, the remaining cash in the Trust not allocated for specific purposes was $25 million. This unallocated amount was exhausted in
January 2016 and BP commenced paying claims and other costs not covered by the specific-purpose cash balances. The total cash remaining in the
Trust and associated qualifying settlement funds, amounting to $1.4 billion, includes $0.7 billion in the seafood compensation fund, $0.2 billion held for
natural resource damage early restoration projects and $0.5 billion held in relation to certain other specified costs under the PSC settlement.
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2. Significant event – Gulf of Mexico oil spill – continued
Other payables
BP reached an agreement with the US government in 2012, which was approved by the court in 2013, to resolve all federal criminal claims arising from
the incident. At 31 December 2015, $2,432 million remains in Other payables in relation to this agreement, of which $530 million falls due in 2016. In
addition, Other payables at 31 December 2015 includes the remaining $219 million for BP’s commitment to fund the Gulf of Mexico Research
Initiative, which is a 10-year research programme to study the impact of the incident on the marine and shoreline environment of the Gulf of Mexico.
Provisions and contingent liabilities
Provisions
BP has recorded provisions relating to the Gulf of Mexico oil spill in relation to environmental expenditure (including spill response costs), litigation and
claims, and Clean Water Act penalties that can be measured reliably at this time.
Movements in each class of provision during the year and cumulatively since the incident are presented in the tables below.
At 1 January
Increase in provision
Unwinding of discount
Change in discount rate
Reclassified to other payables
Utilization – paid by BP
– paid by the trust fund
At 31 December
Of which – current
– non-current
Net increase in provision
Unwinding of discount
Change in discount rate
Reclassified to other payables
Utilization – paid by BP
– paid by the trust fund
At 31 December 2015
Environmental
Litigation
and claims
Clean Water
Act
1,141
5,393
94
(149)
(459)
(23)
(78)
5,919
227
5,692
3,954
5,832
50
(74)
(125)
(234)
(2,944)
6,459
2,849
3,610
3,510
661
68
(110)
–
–
–
4,129
–
4,129
$ million
2015
Total
8,605
11,886
212
(333)
(584)
(257)
(3,022)
16,507
3,076
13,431
$ million
Cumulative since the incident
Environmental
Litigation
and claims
Clean Water
Act
19,992
107
(130)
(459)
(11,710)
(1,881)
32,427
56
(74)
(4,408)
(4,314)
(17,228)
5,919
6,459
4,171
68
(110)
–
–
–
4,129
Total
56,590
231
(314)
(4,867)
(16,024)
(19,109)
16,507
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Environmental
The environmental provision at 31 December 2015 includes amounts payable for natural resource damage costs under the proposed Consent Decree.
These amounts are payable in instalments over 16 years commencing one year after the court approves the Consent Decree; the majority of the
unpaid balance of this natural resource damages settlement accrues interest at a fixed rate. During 2011, BP entered into a framework agreement with
natural resource trustees for the United States and five Gulf states, providing for $1 billion to be spent on early restoration projects to address natural
resource injuries resulting from the oil spill, to be funded from the $20-billion trust fund. Remaining amounts payable under this framework agreement,
that are not yet allocated to specific projects, are also included in environmental provisions.
Litigation and claims
The litigation and claims provision includes amounts that can be estimated reliably for the future cost of settling claims by individuals and businesses
for damage to real or personal property, lost profits or impairment of earning capacity and loss of subsistence use of natural resources (‘Individual and
Business Claims’), and amounts provided under the Agreements in relation to state claims that have not yet been paid. Claims administration costs and
legal costs have also been provided for.
Litigation and claims – PSC settlement
The Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) with the PSC provides for a court-supervised settlement
programme, the Deepwater Horizon Court Supervised Settlement Program (DHCSSP), which commenced operation on 4 June 2012. A separate
claims administrator has been 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 239. BP has provided for its best estimate of the cost associated with the
PSC settlement agreements with the exception of the cost of business economic loss claims, which are provided for where an eligibility notice had
been issued before the end of the month following the balance sheet date and is not subject to appeal by BP within the claims facility.
Management believes that no reliable estimate can currently be made of any business economic loss claims not yet processed or processed but not
yet paid, except where an eligibility notice had been issued before the end of the month following the balance sheet date and is not subject to appeal
by BP within the claims facility.
The submission deadline for business economic loss claims passed on 8 June 2015; no further claims may be submitted. A significant number of
business economic loss claims have been received but have not yet been processed and it is not possible to quantify the total value of the claims.
A revised policy for the matching of revenue and expenses for business economic loss claims was introduced in May 2014 and, of the claims
assessable under the revised policy, the majority have not yet been determined at this time. Uncertainties regarding the proper application of the
revised policy to particular claims and categories of claims continue to arise as the claims administrator has applied the revised policy. Only a small
proportion of claim determinations have been made under some of the specialized frameworks that have been put in place for particular industries,
namely construction, agriculture, professional services and education, and so determinations to date may not be representative of the total population
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of claims. In addition, although some pre-determination data has been provided to BP, detailed data on the majority of pre-determination claims is not
available due to a court order to protect claimant confidentiality. Therefore, there is an insufficient level of detail to enable a complete or clear
understanding of the composition of the underlying claims population.
There is insufficient data available to build up a track record of claims determinations under the policies and protocols that are now being applied
following resolution of the matching and causation issues. We are unable to reliably estimate future trends of the number and proportion of claims that
will be determined to be eligible, nor can we reliably estimate the value of such claims. A provision for such business economic loss claims will be
established when these uncertainties are sufficiently reduced and a reliable estimate can be made of the liability.
The current estimate for the total cost of those elements of the PSC settlement that BP considers can be reliably estimated, including amounts already
paid, is $12.4 billion. Prior to the end of the month following the balance sheet date, the DHCSSP had issued eligibility notices, many of which are
disputed by BP, in respect of business economic loss claims of approximately $402 million which have not been provided for. The total cost of the PSC
settlement is likely to be significantly higher than the amount recognized to date of $12.4 billion because the current estimate does not reflect business
economic loss claims not yet processed, or processed but not yet paid, except where an eligibility notice had been issued before the end of the month
following the balance sheet date and is not subject to appeal by BP within the claims facility.
There continues to be a high level of uncertainty with regards to the amounts that ultimately will be paid in relation to current claims as described
above and there is also uncertainty as to the cost of administering the claims process under the DHCSSP and in relation to future legal costs. The
timing of payment of provisions related to the PSC settlement is dependent upon ongoing claims facility activity and is therefore also uncertain.
Litigation and claims – Other claims
The provision recognized for litigation and claims includes amounts agreed under the Agreements in relation to state claims. The amount provided in
respect of state claims is payable over 18 years from the date the court approves the Consent Decree, of which $1 billion is due following the court
approval of the Consent Decree. The vast majority of local government entities who filed claims have issued releases, which were accepted by BP;
amounts due under those releases were paid during 2015.
Clean Water Act penalties
A provision has been recognized for penalties under Section 311 of the Clean Water Act, as determined in the Agreements. The amount is payable in
instalments over 15 years, commencing one year after the court approves the Consent Decree. The unpaid balance of this penalty accrues interest at a
fixed rate.
Provision movements
The total amount recognized as an increase in provisions during the year was $11,886 million. This increase relates primarily to amounts provided for
the Agreements, and additional increases in the litigation and claims provision for business economic loss claims, associated claims administration
costs and other items. After deducting amounts utilized during the year totalling $3,279 million, comprising payments from the trust fund of
$3,022 million and payments made directly by BP of $257 million (2014 $2,071 million, comprising payments from the trust fund of $1,681 million and
payments made directly by BP of $390 million), and after adjustments for discounting, the remaining provision as at 31 December 2015 was
$16,507 million (2014 $8,605 million).
Contingent liabilities
BP has provided for its best estimate of amounts expected to be paid that can be measured reliably. It is not possible, at this time, to measure reliably
other obligations arising from the incident, nor is it practicable to estimate their magnitude or possible timing of payment. Therefore, no amounts have
been provided for these obligations as at 31 December 2015.
Business economic loss claims under the PSC settlement
The potential cost of business economic loss claims not yet processed and paid (except where an eligibility notice had been issued before the end of
the month following the balance sheet date and is not subject to appeal by BP within the claims facility) is not provided for and is disclosed as a
contingent liability. A significant number of business economic loss claims have been received but have not yet been processed and paid. See
Provisions above for further information.
Securities-related litigation
Proceedings relating to securities class actions (MDL 2185) pending in federal court in Texas, including a purported class action on behalf of purchasers
of American Depositary Shares under US federal securities law, are continuing. A jury trial is scheduled to begin in July 2016 and the timing of any
outflow of resources, if any, is dependent on the duration of the court process. No reliable estimate can be made of the amounts that may be payable
in relation to these proceedings, if any, so no provision has been recognized at 31 December 2015. In addition, no reliable estimate can be made of the
amounts that may be payable in relation to any other securities litigation, if any, so no provision has been recognized at 31 December 2015.
Other litigation
In addition to the securities class actions described above, BP is named as a defendant in approximately 2,700 other civil lawsuits brought by
individuals and corporations in US federal and state courts, as well as certain non-US jurisdictions, resulting from the Deepwater Horizon accident, the
Gulf of Mexico oil spill, and the spill response efforts. Further actions may still be brought. Among other claims, these lawsuits assert claims for
personal injury in connection with the accident and the spill response, commercial and economic injury, damage to real and personal property, breach
of contract and violations of statutes, including, but not limited to, alleged violations of US securities and environmental statutes. In addition, claims
have been received, primarily from business claimants, under the Oil Pollution Act of 1990 (OPA 90) in relation to the 2010 federal deepwater drilling
moratoria. Furthermore, there are also uncertainties around the outcomes of any further litigation including by parties excluded from, or parties who
opted out of, the PSC settlement. Until further fact and expert disclosures occur, court rulings clarify the issues in dispute, liability and damage trial
activity nears or progresses, or other actions such as further possible settlements occur, it is not possible given these uncertainties to arrive at a range
of outcomes or a reliable estimate of the liabilities that may accrue to BP in connection with or as a result of these lawsuits, nor is it possible to
determine the timing of any payment that may arise. Therefore no amounts have been provided for these items as at 31 December 2015.
Settlement and other agreements
Under the settlement agreements with Anadarko and MOEX, the other working interest owners in the Macondo well at the time of the incident, and
with Cameron International, the designer and manufacturer of the Deepwater Horizon blowout preventer, BP has agreed to indemnify Anadarko,
MOEX and Cameron for certain claims arising from the accident. It is therefore possible that BP may face claims under these indemnities, but it is not
currently possible to reliably measure, nor identify the timing of, any obligation in relation to such claims and therefore no amount has been provided
as at 31 December 2015. There are also agreements indemnifying certain third-party contractors in relation to litigation costs and certain other claims.
A contingent liability also exists in relation to other obligations under these agreements.
120
BP Annual Report and Form 20-F 2015
2. Significant event – Gulf of Mexico oil spill – continued
The magnitude and timing of all possible obligations in relation to the Gulf of Mexico oil spill continue to be subject to a high degree of uncertainty. Any
such possible obligations are therefore contingent liabilities and, at present, it is not practicable to estimate their magnitude or possible timing of
payment. Furthermore, other material unanticipated obligations may arise in future in relation to the incident.
Impact upon the group income statement
The amount of the provision recognized during the year can be reconciled to the charge to the income statement as follows:
Net increase in provision
Change in discount rate relating to provisions
Costs charged directly to the income statement
Trust fund liability – discounted
Change in discounting relating to trust fund liability
Recognition of reimbursement asset, net
Settlements credited to the income statement
(Profit) loss before interest and taxation
Finance costs
(Profit) loss before taxation
2015
11,886
(333)
156
–
–
–
–
11,709
247
11,956
2014
1,327
2
114
–
–
(662)
–
781
38
819
$ million
Cumulative since
the incident
56,591
(314)
4,514
19,580
283
(20,000)
(5,681)
54,973
478
55,451
2013
1,860
(5)
136
–
–
(1,542)
(19)
430
39
469
The group income statement for 2015 includes a pre-tax charge of $11,956 million (2014 pre-tax charge of $819 million) in relation to the Gulf of
Mexico oil spill. The costs charged within production and manufacturing expenses in 2015 include $9.4 billion for the amounts provided under the
Agreements, as well as the ongoing costs of operating the Gulf Coast Restoration Organization (GCRO), business economic loss claims, claims
administration costs, legal and litigation costs. Finance costs of $247 million (2014 $38 million) reflect the unwinding of the discount on payables and
provisions. The cumulative amount charged to the income statement to date comprises spill response costs arising in the aftermath of the incident,
amounts charged for the Agreements, GCRO operating costs, amounts charged upon initial recognition of the trust obligation, litigation, claims,
environmental and legal costs not paid through the Trust and estimated obligations for future costs that can be estimated reliably at this time, net of
settlements agreed with the co-owners of the Macondo well and other third parties.
The total amount recognized in the income statement is analysed in the table below.
Trust fund liability – discounted
Change in discounting relating to trust fund liability
Recognition of reimbursement asset
Other
Total (credit) charge relating to the trust fund
Environmental – amount provided
– change in discount rate relating to provisions
– costs charged directly to the income statement
Total charge relating to environmental
Spill response – amount provided
– costs charged directly to the income statement
Total (credit) charge relating to spill response
Litigation and claims – amount provided, net of provision derecognized
– change in discount rate relating to provisions
– costs charged directly to the income statement
Total charge relating to litigation and claims
Clean Water Act penalties – amount provided
– change in discount rate relating to provisions
Total charge relating to Clean Water Act penalties
Other costs charged directly to the income statement
Settlements credited to the income statement
(Profit) loss before interest and taxation
Finance costs
(Profit) loss before taxation
2014
–
–
(662)
–
2013
–
–
(1,542)
–
(662)
(1,542)
190
2
–
192
–
–
–
1,137
–
–
1,137
–
–
–
114
–
781
38
819
47
(5)
–
42
(113)
–
(113)
1,926
–
–
1,926
–
–
–
136
(19)
430
39
469
$ million
Cumulative since
the incident
19,580
283
(20,000)
8
(129)
8,527
(130)
129
8,526
11,465
2,839
14,304
32,428
(74)
184
32,538
4,171
(110)
4,061
1,354
(5,681)
54,973
478
55,451
2015
–
–
–
–
–
5,393
(149)
59
5,303
–
–
–
5,832
(74)
–
5,758
661
(110)
551
97
–
11,709
247
11,956
The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident remains subject to uncertainty as described
under Provisions and contingent liabilities above.
BP Annual Report and Form 20-F 2015
121
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
3. Non-current assets held for sale
On 15 January 2016 BP and Rosneft announced that they had signed a binding agreement to dissolve the German refining joint operation Ruhr Oel
GmbH (ROG). The restructuring, which is expected to be completed in 2016, will result in the transfer of BP’s interests, currently held via ROG, in the
Bayernoil, MiRO Karlsruhe and PCK Schwedt refineries to Rosneft. In exchange, BP will take sole ownership of the Gelsenkirchen refinery and the
solvent production facility DHC Solvent Chemie, both of which are also currently owned by ROG.
The major classes of assets and liabilities relating to BP’s share of ROG’s interests in the Bayernoil, MiRO Karlsruhe and PCK Schwedt refineries
classified as held for sale at 31 December 2015 were:
Assets
Property, plant and equipment
Intangible assets
Inventories
Assets classified as held for sale
Liabilities
Defined benefit pension plan and other post-retirement benefit plan deficits
Liabilities directly associated with assets classified as held for sale
$ million
2015
360
3
215
578
(97)
(97)
The assets classified as held for sale are reported in the Downstream segment. The associated pension liabilities are reported in Other businesses and
corporate.
There were no assets or liabilities classified as held for sale as at 31 December 2014.
4. Disposals and impairment
The following amounts were recognized in the income statement in respect of disposals and impairments.
2015
2014
Gains on sale of businesses and fixed assets
Upstream
Downstream
TNK-BP
Other businesses and corporate
Losses on sale of businesses and fixed assets
Upstream
Downstream
Other businesses and corporate
Impairment losses
Upstream
Downstream
Other businesses and corporate
Impairment reversals
Upstream
Downstream
Impairment and losses on sale of businesses and fixed assets
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
TNK-BP
Other businesses and corporate
122
BP Annual Report and Form 20-F 2015
324
316
–
26
666
2015
124
98
41
263
2,484
265
155
2,904
(1,080)
(178)
(1,258)
1,909
2015
1,066
1,726
2,792
769
1,747
–
276
2,792
$ million
2013
371
214
12,500
30
13,115
$ million
2013
144
78
8
230
1,255
484
218
1,957
(226)
–
(226)
405
474
–
16
895
2014
345
401
3
749
6,737
1,264
317
8,318
(102)
–
(102)
8,965
1,961
2014
1,820
1,671
3,491
2,533
864
–
94
3,491
$ million
2013
18,115
3,884
21,999
1,288
3,991
16,646
74
21,999
4. Disposals and impairment – continued
At 31 December 2015, deferred consideration relating to disposals amounted to $41 million receivable within one year (2014 $1,137 million and 2013
$23 million) and $385 million receivable after one year (2014 $333 million and 2013 $1,374 million). In addition, contingent consideration receivable
relating to disposals amounted to $292 million at 31 December 2015 (2014 $454 million and 2013 $953 million), see Note 29 for further information.
Upstream
In 2015, gains principally resulted from the sale of our interests in the Central Area Transmission System in the North Sea, and from adjustments to
prior year disposals in Canada.
In 2014, gains principally resulted from the sale of certain onshore assets in the US, and the sale of certain interests in the Gulf of Mexico and the
North Sea. Losses principally arose from adjustments to prior year disposals in Canada and the North Sea.
In 2013, gains principally resulted from the sale of certain of our interests in the central North Sea, and the Yacheng field in China.
Downstream
In 2015, gains principally resulted from the disposal of our investment in the UTA European fuel cards business and our Australian bitumen business.
In 2014, gains principally resulted from the disposal of our global aviation turbine oils business. Losses principally arose from costs associated with the
decision to cease refining operations at Bulwer Island in Australia.
In 2013, gains principally resulted from the disposal of our global LPG business and closing adjustments on the sales of the Texas City and Carson
refineries with their associated marketing and logistics assets.
TNK-BP
In 2013, BP disposed of its 50% interest in TNK-BP to Rosneft, resulting in a gain on disposal of $12,500 million.
Summarized financial information relating to the sale of businesses is shown in the table below. The principal transactions categorized as business
disposals in 2015 were the sales of our interests in the Central Area Transmission System in the North Sea and in the UTA European fuel cards
business. The principal transaction categorized as a business disposal in 2014 was the sale of certain of our interests on the North Slope of Alaska in
our upstream business. The principal transactions categorized as business disposals in 2013 were the sales of the Texas City and Carson refineries
with their associated marketing and logistics assets. Information relating to sales of fixed assets is excluded from the table.
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 disposala
Gains on sale of businesses
Total consideration
Consideration received (receivable)b
Proceeds from the sale of businesses related to completed transactions
Depositsc
Proceeds from the sale of businesses
2015
154
80
(70)
(50)
114
16
8
138
446
584
1,116
1,700
26
1,726
2014
1,452
182
(395)
(65)
1,174
(7)
128
1,295
280
1,575
96
1,671
–
1,671
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
$ million
2013
2,124
2,371
(94)
(62)
4,339
23
13
4,375
69
4,444
(414)
4,030
(146)
3,884
a 2013 includes pension and other post-retirement benefit plan curtailment gains of $109 million.
b Consideration received from prior year business disposals or to be received from current year disposals. 2015 includes $1,079 million of proceeds from our Toledo refinery partner, Husky Energy, in
place of capital commitments relating to the original divestment transaction that have not been subsequently sanctioned. 2013 includes contingent consideration of $475 million relating to the disposal
of the Texas City refinery.
c Proceeds received in the current year in advance of business disposals, less deposits received in prior years in relation to business disposals completed in the current year.
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. For information on impairments
recognized by joint ventures see Note 15.
Upstream
The 2015 impairment losses of $2,484 million included $761 million in Angola, of which $371 million related to the Greater Plutonio cash-generating
unit (CGU), which has a recoverable amount of $2,222 million. Impairment losses also included $830 million in relation to CGUs in the North Sea, of
which $328 million relates to the Andrew area CGU, which has a recoverable amount of $766 million. The impairment losses primarily arose as a result
of a lower price environment in the near term, and were also affected to a lesser extent by certain technical reserves revisions and increases in
decommissioning cost estimates. The 2015 impairment reversals of $1,080 million included $945 million in the North Sea business, of which
$473 million related to the Eastern Trough Area Project (ETAP) CGU, which has a recoverable amount of $2,489 million. The impairment reversals
mainly arose as a result of decreases in cost estimates and a reduction in the discount rate applied, offsetting the impact of lower prices in the near
term. Impairment losses and reversals relate to producing assets. The recoverable amounts of the Greater Plutonio CGU, the Andrew area CGU, and
the ETAP CGU are their values in use. See Impairment of property, plant and equipment, intangible assets and goodwill within Note 1 for further
information on assumptions used for impairment testing. The discount rate used to determine the recoverable amount of the Greater Plutonio CGU
included the 2% premium for higher-risk countries as described in Note 1; a premium was not applied in determining the recoverable amount of the
other CGUs.
The 2014 impairment losses of $6,737 million included $4,876 million in relation to CGUs in the North Sea, of which $1,964 million related to the Valhall
CGU, $660 million related to the Andrew area CGU, and $515 million related to the ETAP CGU. Impairment losses also included an $859-million
impairment of our PSVM CGU in Angola, and a $415-million impairment of the Block KG D6 CGU in India. All of the impairments related to producing
BP Annual Report and Form 20-F 2015
123
4. Disposals and impairment – continued
assets. The impairments in the North Sea and Angola arose as a result of a lower price environment in the near term, technical reserves revisions, and
increases in expected decommissioning cost estimates. The impairment of Block KG D6 arose following the introduction of a new formula for Indian
gas prices. The discount rate used to determine the value in use of the PSVM CGU included the 2% premium for higher-risk countries. A premium was
not applied in determining the recoverable amount of the other CGUs.
The main elements of the 2013 impairment losses of $1,255 million were a $251-million impairment loss relating to the Browse project in Australia and
a $253-million aggregate write-down of a number of assets in the North Sea, caused by increases in expected decommissioning costs. Impairment
reversals arose on certain of our interests in Alaska, the Gulf of Mexico, and the North Sea, triggered by reductions in decommissioning provisions due
to continued review of the expected decommissioning costs and an increase in the discount rate for provisions.
Downstream
The 2015 impairment losses of $265 million arose principally in relation to certain manufacturing assets in our petrochemicals business and certain US
midstream assets, where the expected disposal proceeds were lower than the book values.
The 2014 impairment losses of $1,264 million principally related to our Bulwer Island refinery and certain midstream assets in our fuels business, and
certain manufacturing assets in our petrochemicals business.
The 2013 impairment losses of $484 million principally related to impairments of certain refineries in the US and elsewhere in our global fuels portfolio.
Other businesses and corporate
Impairment losses totalling $155 million, $317 million, and $218 million were recognized in 2015, 2014 and 2013 respectively. The amount for 2015 is
principally in respect of our US wind business. The amount for 2014 is principally in respect of our biofuels businesses in the UK and US. The amount
for 2013 is principally in respect of our US wind business.
5. Segmental analysis
The group’s organizational structure reflects the various activities in which BP is engaged. At 31 December 2015, 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.
During 2013, BP completed transactions for the sale of BP’s interest in TNK-BP to Rosneft, and for BP’s further investment in Rosneft. 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 Gulf Coast Restoration Organization (GCRO), which manages aspects of our response to the 2010 Gulf of Mexico incident, was overseen by a
board committee for all periods presented, however it is not an operating segment. Its costs are presented as a reconciling item between the sum of
the results of the reportable segments and the group results. From 2016, we intend to report GCRO as part of Other businesses and corporate.
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 inventory holding gains and lossesa. Replacement cost
profit or loss 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.
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.
124
BP Annual Report and Form 20-F 2015
5. Segmental analysis – continued
By business
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 (loss) 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
Segment assets
Investments in joint ventures and associates
Additions to non-current assetsb
Additions to other investments
Element of acquisitions not related to non-current
assets
Additions to decommissioning asset
Capital expenditure and acquisitions, on an accruals
Upstream
Downstream
Rosneft
Other
businesses
and
corporate
Gulf of
Mexico
oil spill
response
Consolidation
adjustment
and
eliminations
$ million
2015
Total
group
43,235
200,569
(21,949)
21,286
(68)
200,501
–
–
–
2,048
(941)
1,107
192
491
1,330
(202)
–
–
–
–
(937)
(30)
(967)
7,111
(1,863)
5,248
1,310
4
1,314
(1,768)
–
(1,768)
(11,709)
–
(11,709)
4,007
8,866
824
8,304
17,635
906
1,162
611
3,214
2,130
–
–
–
5,797
–
–
77
201
–
–
228
11,553
519
315
340
–
–
–
(22,958)
222,894
22,958
–
–
(36)
–
(36)
–
–
–
–
–
–
222,894
1,811
(6,029)
(1,889)
(7,918)
(1,347)
(306)
(9,571)
4,990
10,229
13,216
17,834
20,080
35
(31)
(553)
–
19,531
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
basis
17,082
2,109
a See explanation of inventory holding gains and losses on page 124.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
BP Annual Report and Form 20-F 2015
125
(37,331)
353,568
37,331
–
–
641
–
641
–
–
–
–
–
–
–
353,568
3,372
12,622
(6,210)
6,412
(1,148)
(314)
4,950
5,210
9,953
2,625
19,156
26,492
160
(366)
(2,505)
23,781
5. Segmental analysis – continued
By business
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
Upstream
Downstream
Rosneft
Other
businesses
and
corporate
Gulf of
Mexico
oil spill
response
Consolidation
adjustment
and
eliminations
$ million
2014
Total
group
65,424
323,486
(36,643)
28,781
173
323,659
–
–
–
1,989
(861)
1,128
1,089
265
2,101
(83)
–
–
–
–
Replacement cost profit (loss) before interest and taxation
Inventory holding gains (losses)a
Profit (loss) before interest and taxation
8,934
(86)
8,848
3,738
(6,100)
(2,362)
2,100
(24)
2,076
(2,010)
–
(2,010)
(781)
–
(781)
Finance costs
Net finance expense relating to pensions and other post-
retirement benefits
Profit before taxation
Other income statement items
Depreciation, depletion and amortizationb
US
Non-US
Charges for provisions, net of write-back of unused
provisions, including change in discount rate
Segment assets
Investments in joint ventures and associates
Additions to non-current assetsc
Additions to other investments
Element of acquisitions not related to non-current assets
Additions to decommissioning asset
4,129
8,404
984
1,336
260
713
7,877
22,587
3,244
3,121
Capital expenditure and acquisitions, on an accruals basis
19,772
3,106
–
–
–
7,312
–
–
97
213
323
723
784
903
–
–
1,329
–
–
–
a See explanation of inventory holding gains and losses on page 124.
b It is estimated that the benefit arising from the absence of depreciation for the assets held for sale during the year was $221 million.
c Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
126
BP Annual Report and Form 20-F 2015
5. Segmental analysis – continued
By business
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 amortizationb
US
Non-US
Charges for provisions, net of write-back of
unused provisions, including change in
discount rate
Segment assets
Upstream
Downstream
Rosneft
TNK-BP
Other
businesses
and
corporate
Gulf of
Mexico
oil spill
response
Consolidation
adjustment
and
eliminations
$ million
2013
Total
group
70,374
351,195
(42,327)
28,047
(1,045)
350,150
–
–
–
1,027
195
2,058
–
–
–
–
1,805
(866)
939
(91)
–
–
–
–
16,657
4
16,661
2,919
(194)
2,725
2,153
(100)
2,053
12,500
–
12,500
(2,319)
–
(2,319)
(430)
–
(430)
(44,238)
379,136
44,238
–
–
579
–
579
–
–
–
–
–
–
379,136
3,189
32,059
(290)
31,769
(1,068)
(480)
30,221
4,466
9,044
2,581
25,835
36,916
41
39
(384)
–
36,612
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
3,538
7,514
747
1,343
161
270
–
–
–
Investments in joint ventures and associates
Additions to non-current assetsc
7,780
19,499
3,302
13,681
4,449
11,941
Additions to other investments
Element of acquisitions not related to non-
current assets
Additions to decommissioning asset
Capital expenditure and acquisitions, on an
–
–
–
–
–
181
187
–
–
295
1,855
1,072
1,027
–
–
–
accruals basis
19,115
4,506
11,941
–
1,050
a See explanation of inventory holding gains and losses on page 124.
b It is estimated that the benefit arising from the absence of depreciation for the assets held for sale at 31 December 2012 until their disposal in 2013 amounted to approximately $201 million.
c Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
BP Annual Report and Form 20-F 2015
127
5. Segmental analysis – continued
By geographical area
Revenues
Third party sales and other operating revenuesa
Other income statement items
Production and similar taxes
Results
Replacement cost profit (loss) before interest and taxation
Non-current assets
Non-current assetsb c
Capital expenditure and acquisitions, on an accruals basis
US
Non-US
$ million
2015
Total
74,162
148,732
222,894
215
821
1,036
(12,243)
6,214
(6,029)
67,776
5,332
111,106
14,199
178,882
19,531
a Non-US region includes UK $51,550 million.
b Non-US region includes UK $19,152 million.
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
By geographical area
Revenues
Third party sales and other operating revenuesa
Other income statement items
Production and similar taxes
Results
Replacement cost profit before interest and taxation
Non-current assets
Non-current assetsb c
Capital expenditure and acquisitions, on an accruals basis
US
Non-US
$ million
2014
Total
122,951
230,617
353,568
690
2,268
2,958
5,251
7,371
12,622
69,125
7,227
114,462
16,554
183,587
23,781
a Non-US region includes UK $77,522 million.
b Non-US region includes UK $18,430 million.
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
By geographical area
Revenues
Third party sales and other operating revenuesa
Other income statement items
Production and similar taxes
Results
Replacement cost profit before interest and taxation
Non-current assets
Non-current assetsb c
Capital expenditure and acquisitions, on an accruals basis
US
Non-US
$ million
2013
Total
128,764
250,372
379,136
1,112
5,935
7,047
3,114
28,945
32,059
70,228
9,176
124,439
27,436
194,667
36,612
a Non-US region includes UK $82,381 million.
b Non-US region includes UK $18,967 million.
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
6. Income statement analysis
Interest and other income
Interest income
Other income
Currency exchange losses charged to the income statementa
Expenditure on research and development
Finance costs
Interest payable
Capitalized at 1.75% (2014 1.94% and 2013 2%)b
Unwinding of discount on provisions and other payables
a Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss.
b Tax relief on capitalized interest is approximately $42 million (2014 $43 million and 2013 $62 million).
128
BP Annual Report and Form 20-F 2015
2015
226
385
611
8
418
2014
258
585
843
36
663
1,065
(179)
461
1,347
1,025
(185)
308
1,148
$ million
2013
282
495
777
180
707
1,082
(238)
224
1,068
7. 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 estimates and judgements made in relation to oil and natural gas accounting see Intangible assets within Note 1.
Exploration and evaluation costs
Exploration expenditure written offa
Other exploration costs
Exploration expense for the year
Impairment losses
Intangible assets – exploration and appraisal expenditure
Liabilities
Net assets
Capital expenditure, on an accruals basis
Net cash used in operating activities
Net cash used in investing activities
2015
2014
1,829
524
2,353
–
3,029
603
3,632
–
$ million
2013
2,710
731
3,441
253
17,286
19,344
20,865
145
227
212
17,141
19,117
20,653
1,197
524
1,216
2,870
603
2,786
4,464
731
4,275
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
a 2015 included a $432-million write-off in Libya as there is significant uncertainty about the timing of future drilling operations. It also includes a $345-million write-off relating to the Gila discovery in the
deepwater Gulf of Mexico and a $336-million write-off relating to the Pandora discovery in Angola as development of these prospects is considered challenging. 2014 included a $544-million write-off
relating to disappointing appraisal results of Utica shale in the US Lower 48 and the subsequent decision not to proceed with its development plans, a $524-million write-off relating to the Bourarhat
Sud block licence in the Illizi Basin of Algeria, a $395-million write-off relating to Block KG D6 in India and a $295-million write-off relating to the Moccasin discovery in the deepwater Gulf of Mexico.
2013 included a $845-million write-off relating to the value ascribed to Block BM-CAL-13 offshore Brazil as a result of the Pitanga exploration well not encountering commercial quantities of oil and gas
and a $257-million write-off of costs relating to the Risha concession in Jordan as our exploration activities did not establish the technical basis for a development project in the concession. For further
information see Upstream – Exploration on page 30.
The carrying amount, by location, of exploration and appraisal expenditure capitalized as intangible assets at 31 December 2015 is shown in the table
below.
Carrying amount
$1 - 2 billion
$2 - 3 billion
$3 - 4 billion
8. Taxation
Tax on profit
Current tax
Charge for the year
Adjustment in respect of prior years
Deferred tax
Origination and reversal of temporary differences in the current year
Adjustment in respect of prior years
Tax charge (credit) on profit or loss
Location
Angola; India
Canada; Egypt; Brazil
US – Gulf of Mexico
2015
2014
1,910
(329)
1,581
(5,090)
338
(4,752)
(3,171)
4,444
48
4,492
(3,194)
(351)
(3,545)
947
$ million
2013
5,724
61
5,785
529
149
678
6,463
In 2015, the total tax charge recognized within other comprehensive income was $1,140 million (2014 $1,481 million credit and 2013 $1,374 million
charge). See Note 31 for further information. The total tax charge recognized directly in equity was $9 million (2014 $36 million charge and 2013
$33 million credit).
For information on significant estimates and judgements made in relation to taxation see Income taxes within Note 1. For information on contingent
liabilities in relation to taxation see Note 32.
Reconciliation of the effective tax rate
The following table provides a reconciliation of the UK statutory corporation tax rate to the effective tax rate of the group on profit or loss before
taxation. With effect from 1 April 2015 the UK statutory corporation tax rate reduced from 21% to 20% on profits arising from activities outside the
North Sea.
For 2015, the items presented in the reconciliation are affected as a result of the overall tax credit for the year and the loss before taxation. In order to
provide a more meaningful analysis of the effective tax rate, the table also presents separate reconciliations for the group excluding the impacts of the
Gulf of Mexico oil spill and impairment losses, and for the impacts of the Gulf of Mexico oil spill and impairment losses in isolation.
For 2014, the items presented in the reconciliation are affected as a result of the tax credits related to the impairment losses recognized in the year and
the effect of the impairment losses on the profit for the year. In order to provide a more meaningful analysis of the effective tax rate for 2014, the table
also presents separate reconciliations for the group excluding the effects of the impairment losses, and for the effects of the impairment losses in
isolation.
BP Annual Report and Form 20-F 2015
129
8. Taxation – continued
For 2013, the effective tax rate is not affected significantly by impairment losses or the impact of the Gulf of Mexico oil spill.
Profit (loss) before taxation
Tax charge (credit) on profit or loss
Effective tax rate
UK statutory corporation tax rate
Increase (decrease) resulting from
UK supplementary and overseas taxes at higher or
lower ratesa
Tax reported in equity-accounted entities
Adjustments in respect of prior years
Movement in deferred tax not recognized
Tax incentives for investment
Gulf of Mexico oil spill non-deductible costs
Permanent differences relating to disposals
Foreign exchange
Items not deductible for tax purposes
Decrease in rate of UK supplementary chargeb
Other
Effective tax rate
2015
excluding
impacts of
Gulf of
Mexico oil
spill and
impairments
2015
impacts of
Gulf of
Mexico oil
spill and
impairments
4,031
(13,602)
945
23%
(4,116)
30%
$ million
2014
excluding
impairments
2014
impacts of
impairments
13,166
5,036
38%
(8,216)
(4,089)
50%
2015
(9,571)
(3,171)
33%
2014
4,950
947
19%
2013
30,221
6,463
21%
% of profit or loss before taxation
20
–
(10)
1
17
(8)
–
(3)
18
10
(23)
1
23
20
18
–
–
(5)
–
(2)
–
–
–
–
(1)
30
20
25
4
–
(14)
3
(3)
1
(8)
(4)
10
(1)
33
21
17
(5)
(2)
4
(4)
–
(1)
4
4
–
–
38
21
34
–
–
(3)
–
–
–
–
(2)
–
–
50
21
23
(11)
(14)
(6)
17
(10)
1
(1)
10
12
–
–
19
4
(2)
1
2
(2)
–
(8)
2
1
–
–
21
a For 2015 excluding impacts of the Gulf of Mexico oil spill and impairments, the most significant countries impacting upon the rate were the US (with an applicable statutory tax rate of 35%), Angola
(50%), Germany (32%), Indonesia (42%) and UK North Sea (50%). However because there were profits in some countries and losses in others, the net impact on the effective tax rate reconciliation
was less than 1%. For 2014 excluding impairments, jurisdictions which contribute significantly to this item are Angola (50%), Trinidad (55%) and the US (35%). For 2013, jurisdictions which contribute
significantly are Angola, the UK North Sea and Trinidad, with applicable statutory tax rates of 50%, 62% and 55% respectively.
b For 2015, this relates to the one-off deferred tax impact of the enactment of legislation to reduce the UK supplementary charge tax rate applicable to profits arising in the North Sea from 32% to 20%.
Deferred tax
Analysis of movements during the year in the net deferred tax liability
At 1 January
Exchange adjustments
Charge (credit) for the year in the income statement
Charge (credit) for the year in other comprehensive income
Charge (credit) for the year in equity
Acquisitions and disposals
At 31 December
2015
11,584
86
(4,752)
1,140
9
(13)
8,054
$ million
2014
16,454
122
(3,545)
(1,563)
36
80
11,584
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
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 liability
Of which – deferred tax liabilities
– deferred tax assets
130
BP Annual Report and Form 20-F 2015
Income statement
$ million
Balance sheet
2015
2014
2013
2015
2014
(102)
84
(326)
59
(285)
12
(2,513)
62
256
(2,239)
(45)
(4,467)
(4,752)
(2,178)
(272)
527
(1,805)
(3,728)
492
52
166
589
(1,397)
281
183
(3,545)
(474)
(691)
99
(298)
(1,364)
787
1,385
30
(174)
(343)
357
2,042
678
28,712
878
961
1,266
31,817
(1,972)
(13,737)
(710)
(43)
(5,985)
(1,316)
(23,763)
8,054
9,599
1,545
29,062
–
1,089
1,356
31,507
(2,761)
(11,237)
(575)
(298)
(3,848)
(1,204)
(19,923)
11,584
13,893
2,309
8. Taxation – continued
The recognition of deferred tax assets of $1,067 million (2014 $1,467 million), in entities which have suffered a loss in either the current or preceding
period, is supported by forecasts which indicate that sufficient future taxable profits will be available to utilize such assets.
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.
At 31 December
Unused US state tax lossesa
Unused tax losses – other jurisdictionsb
Unused tax credits
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
2015
9.6
2.1
20.4
17.5
2.8
23.2
3.9
$ billion
2014
9.0
2.1
20.1
18.0
2.0
17.9
1.0
a Of the gross unused tax losses on which no deferred tax is recognized, $9.6 billion relates to US state taxes which expire in the period 2016-2035 with applicable tax rates ranging from 5% to 12%. An
amendment has been made to the comparative amount.
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 high tax rates. 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 on the overseas tax. These tax credits have no fixed expiry date.
d The US unused tax credits expire in the period 2016-2025.
e Primarily comprises fixed asset temporary differences. Substantially all of the temporary differences have no expiry date.
Impact of previously unrecognized deferred tax or write-down of deferred tax assets on current year charge
Current tax benefit relating to the utilization of previously unrecognized tax credits and losses
Deferred tax benefit relating to the recognition of previously unrecognized tax credits and losses
Deferred tax expense arising from the write-down of a previously recognized deferred tax asset
2015
123
–
768
2014
171
–
153
$ million
2013
216
178
–
9. Dividends
The quarterly dividend expected to be paid on 24 March 2016 in respect of the fourth quarter 2015 is 10 cents per ordinary share ($0.60 per American
Depositary Share (ADS)). The corresponding amount in sterling will be announced on 14 March 2016. A scrip dividend alternative is available, allowing
shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs.
Dividends announced and paid in cash
Preference shares
Ordinary shares
March
June
September
December
Dividend announced, payable in March 2016
Pence per share
Cents per share
2015
2014
2013
2015
2014
2013
2015
2014
$ million
2013
2
2
2
6.6699
6.5295
6.5488
6.6342
5.7065
5.8071
5.9593
6.3769
6.0013
5.8342
5.7630
5.8008
26.3824
23.8498
23.3993
10.00
10.00
10.00
10.00
40.00
10.00
9.50
9.75
9.75
10.00
39.00
9.00
9.00
9.00
9.50
36.50
1,708
1,691
1,717
1,541
6,659
1,841
1,426
1,572
1,122
1,728
5,850
1,621
1,399
1,245
1,174
5,441
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
The details of the scrip dividends issued are shown in the table below.
Number of shares issued (thousand)
Value of shares issued ($ million)
2015
102,810
642
2014
165,644
1,318
2013
202,124
1,470
The financial statements for the year ended 31 December 2015 do not reflect the dividend announced on 2 February 2016 and expected to be paid in
March 2016; this will be treated as an appropriation of profit in the year ended 31 December 2016.
10. Earnings per ordinary share
Basic earnings per share
Diluted earnings per share
2015
(35.39)
(35.39)
2014
20.55
20.42
Cents per share
2013
123.87
123.12
Basic earnings per ordinary share amounts are calculated by dividing the profit (loss) for the year attributable to ordinary shareholders by the weighted
average number of ordinary shares outstanding during the year. The 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 using the treasury stock method. 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. A dilutive effect relating to potentially issuable shares has not been included, therefore, in the
calculation of diluted earnings per share for 2015.
BP Annual Report and Form 20-F 2015
131
10. Earnings per ordinary share – continued
Profit (loss) attributable to BP shareholders
Less: dividend requirements on preference shares
Profit (loss) 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
2015
(6,482)
2
(6,484)
2014
3,780
2
3,778
$ million
2013
23,451
2
23,449
Shares thousand
2015
2014
2013
18,323,646
–
18,385,458
111,836
18,931,021
115,152
18,323,646
18,497,294
19,046,173
The number of ordinary shares outstanding at 31 December 2015, excluding treasury shares, and including certain shares that will be issuable in the
future under employee share-based payment plans was 18,412,392,432. Between 31 December 2015 and 16 February 2016, the latest practicable
date before the completion of these financial statements, there was a net increase of 12,765,658 in the number of ordinary shares outstanding 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 76-92.
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
Outstanding
Exercisable
Dilutive effect
2015
Weighted
average
exercise
price $
8.54
10.21
n/a
2014
Weighted
average
exercise
price $
9.62
10.89
n/a
Number of
optionsa b
thousand
113,206
86,211
5,570
Number of
optionsa b
thousand
70,049
46,520
2,659
a Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
b At 31 December 2015 the quoted market price of one BP ordinary share was £3.54 (2014 £4.11).
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.
Share plans
Vesting
Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
Dilutive effect
2015
2014
Number of
sharesa
thousand
Number of
sharesa
thousand
78,823
76,779
89,654
41,479
695
78,467
91,993
80,966
28,564
222
287,430
101,984
280,212
99,917
a Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
There has been a net increase of 60,530,268 in the number of potential ordinary shares relating to employee share-based payment plans between
31 December 2015 and 16 February 2016.
132
BP Annual Report and Form 20-F 2015
11. Property, plant and equipment
Cost
At 1 January 2015
Exchange adjustments
Additions
Acquisitions
Transfers
Reclassified as assets held for sale
Deletions
At 31 December 2015
Depreciation
At 1 January 2015
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Transfers
Reclassified as assets held for sale
Deletions
At 31 December 2015
Net book amount at 31
December 2015
Cost
At 1 January 2014
Exchange adjustments
Additions
Acquisitions
Transfers
Deletions
At 31 December 2014
Depreciation
At 1 January 2014
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Deletions
At 31 December 2014
Net book amount at 31
December 2014
Assets held under finance leases at net book amount
included above
At 31 December 2015
At 31 December 2014
Assets under construction included above
At 31 December 2015
At 31 December 2014
Land
and land
improvements
Buildings
3,415
(259)
96
–
–
–
(58)
3,194
639
(10)
37
14
–
–
–
(38)
642
3,061
(144)
122
–
–
(66)
(96)
2,877
1,197
(51)
135
2
–
–
(33)
(93)
1,157
Oil and
gas
propertiesa
200,514
–
14,574
–
1,039
–
(561)
215,566
111,175
–
12,004
2,113
(1,079)
21
–
(403)
123,831
Plant,
machinery
and
equipment
Fixtures,
fittings and
office
equipment
Transportation
Oil depots,
storage
tanks and
service
stations
48,815
(1,828)
1,114
27
–
(1,364)
(1,020)
45,744
21,358
(914)
1,760
225
(2)
–
(1,038)
(737)
20,652
3,031
(89)
129
–
–
(31)
(174)
2,866
1,983
(56)
238
1
–
–
(24)
(58)
2,084
13,819
(61)
493
–
–
–
(213)
14,038
8,933
(33)
426
283
(18)
–
–
(152)
9,439
9,046
(772)
551
–
–
–
(407)
8,418
5,724
(452)
323
7
(159)
–
–
(303)
5,140
$ million
Total
281,701
(3,153)
17,079
27
1,039
(1,461)
(2,529)
292,703
151,009
(1,516)
14,923
2,645
(1,258)
21
(1,095)
(1,784)
162,945
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
2,552
1,720
91,735
25,092
782
4,599
3,278
129,758
3,375
(284)
315
31
–
(22)
3,415
550
(5)
84
15
–
(5)
639
3,027
(105)
183
22
–
(66)
3,061
1,141
(46)
156
–
–
(54)
1,197
187,691
–
18,033
–
993
(6,203)
200,514
97,063
–
11,728
6,304
(19)
(3,901)
111,175
48,912
(1,737)
2,008
252
–
(620)
48,815
20,378
(989)
1,833
625
–
(489)
21,358
3,176
(93)
258
3
–
(313)
3,031
1,970
(56)
267
–
–
(198)
1,983
13,314
(44)
1,049
–
–
(500)
13,819
8,833
(27)
343
179
(83)
(312)
8,933
9,961
(871)
521
–
–
(565)
9,046
5,831
(550)
448
504
–
(509)
5,724
269,456
(3,134)
22,367
308
993
(8,289)
281,701
135,766
(1,673)
14,859
7,627
(102)
(5,468)
151,009
2,776
1,864
89,339
27,457
1,048
4,886
3,322
130,692
–
–
2
3
84
135
297
295
–
–
242
244
–
–
625
677
27,755
26,429
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.
12. Capital commitments
Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been signed at 31 December 2015
amounted to $10,379 million (2014 $14,590 million – amended from $15,635 million previously disclosed). BP’s share of capital commitments of joint
ventures amounted to $586 million (2014 $369 million).
BP Annual Report and Form 20-F 2015
133
13. Goodwill and impairment review of goodwill
Cost
At 1 January
Exchange adjustments
Acquisitions
Deletions
At 31 December
Impairment losses
At 1 January
Deletions
At 31 December
Net book amount at 31 December
Net book amount at 1 January
Impairment review of goodwill
Goodwill at 31 December
Upstream
Downstream
Other businesses and corporate
2015
12,482
(237)
5
(14)
12,236
614
(5)
609
$ million
2014
12,851
(278)
73
(164)
12,482
670
(56)
614
11,627
11,868
11,868
12,181
2015
7,812
3,761
54
$ million
2014
7,819
3,968
81
11,627
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 and Other.
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.
Upstream
Goodwill
Excess of recoverable amount over carrying amount
2015
7,812
12,894
$ million
2014
7,819
26,077
The table above shows the carrying amount of goodwill for the segment and the excess of the recoverable amount, based upon a fair value less costs
of disposal calculation, over the carrying amount (the headroom).
The fair value less costs of disposal 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, because
they are not 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. The fair value
calculation is based primarily on level 3 inputs as defined by the IFRS 13 ‘Fair value measurement’ hierarchy. As the production profile and related cash
flows can be estimated from BP’s experience, management believes that the estimated cash flows expected to be generated over the life of each field
is the appropriate basis upon which to assess goodwill 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 the fields are
computed using appropriate individual economic models and key assumptions agreed by BP management. Capital expenditure, operating costs and
expected hydrocarbon production profiles are derived from the business segment plan adjusted for assumptions reflecting the price environment at the
time that the test was performed. Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis are
developed to be consistent with this. 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. Intangible assets are deemed to have a recoverable
amount equal to their carrying amount.
Consistent with prior years, the 2015 review for impairment was carried out during the fourth quarter. The key assumptions used in the fair value less
costs of disposal calculation are oil and natural gas prices, production volumes and the discount rate. Oil price assumptions for the first five years
reflect the forward market prices at the time that the calculation was prepared. The prices used were, on average, $6.50 per barrel higher than the
prices at the end of the year which are disclosed in Note 1. Gas price assumptions used for the first five years were, on average, the same as those
disclosed in Note 1. Long-term price assumptions and discount rate assumptions used were as disclosed in Note 1. The fair value less costs of
disposal calculations have 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, and future commodity prices may differ from the forecasts used in the calculations.
134
BP Annual Report and Form 20-F 2015
13. Goodwill and impairment review of goodwill – continued
The sensitivities to different variables have been estimated using certain simplifying assumptions. For example, lower oil and gas prices sensitivities do
not reflect the specific impacts for each contractual arrangement and will not capture fully any favourable impacts that may arise from cost deflation.
Therefore a detailed calculation at any given price or production profile may produce a different result.
It is estimated that if the oil price assumption for all future years (the first five years, and the long-term assumption from 2021 onwards) was
approximately $6.50 per barrel lower in each year, this 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 if the gas price assumption for all future years was approximately $0.60 per mmbtu lower in
each year, this would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment.
Estimated production volumes are based on detailed data for each field and take into account development plans agreed by management as part of the
long-term planning process. The average production for the purposes of goodwill impairment testing over the next 15 years is 911mmboe per year
(2014 847mmboe per year). It is estimated that if production volume were to be reduced by approximately 3% for this period, this would cause the
recoverable amount to be equal to the carrying amount of goodwill and related non-current assets of the segment.
It is estimated that if the post-tax discount rate was approximately 9% for the entire portfolio, an increase of 2% for all countries not classified as
‘higher risk’, this would cause the recoverable amount to be equal to the carrying amount of goodwill and related non-current assets of the segment.
Downstream
Goodwill
Lubricants
Other
2015
Total
Lubricants
3,109
652
3,761
3,264
$ million
2014
Total
3,968
Other
704
Cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of two 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 2013 were
used for the 2015 impairment test as the criteria in that standard were considered satisfied: the headroom was substantial in 2013; 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 at the time
was 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. The values assigned to these key assumptions reflect BP’s 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 two-year plan period were
extrapolated using a nominal 3% growth rate.
14. Intangible assets
Cost
At 1 January
Exchange adjustments
Acquisitions
Additions
Transfers
Reclassified as assets held for sale
Deletions
At 31 December
Amortization
At 1 January
Exchange adjustments
Charge for the year
Impairment losses
Transfers
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 7.
Exploration
and appraisal
expenditurea
Other
intangibles
Exploration
and appraisal
expenditurea
Other
intangibles
2015
Total
25,991
(187)
–
1,431
(1,039)
(18)
(2,267)
23,911
5,084
(75)
2,125
–
(21)
(15)
(1,847)
5,251
4,268
(187)
–
234
–
(18)
(242)
4,055
2,705
(75)
296
–
–
(15)
(230)
2,681
21,742
–
–
2,871
(993)
–
(1,897)
21,723
877
–
3,029
–
–
–
(1,527)
2,379
19,344
20,865
21,723
–
–
1,197
(1,039)
–
(2,025)
19,856
2,379
–
1,829
–
(21)
–
(1,617)
2,570
17,286
19,344
$ million
2014
Total
25,678
(175)
455
3,265
(993)
–
(2,239)
25,991
3,639
(72)
3,333
50
–
–
(1,866)
5,084
3,936
(175)
455
394
–
–
(342)
4,268
2,762
(72)
304
50
–
–
(339)
2,705
1,374
18,660
1,563
20,907
1,563
20,907
1,174
22,039
BP Annual Report and Form 20-F 2015
135
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
15. 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
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
Group investment in joint ventures
Group share of net assets (as above)
Loans made by group companies to joint ventures
$ million
2013
12,507
1,076
130
946
499
447
38
485
2015
9,588
785
188
597
625
(28)
(1)
(29)
11,163
2,515
13,678
1,855
3,500
5,355
8,323
8,323
89
8,412
2014
12,208
1,210
125
1,085
515
570
(15)
555
11,586
2,853
14,439
2,222
3,774
5,996
8,443
8,443
310
8,753
The loss for the year shown in the table above includes $711 million relating to BP’s share of impairment losses recognized by joint ventures, a
significant element of which relates to the Angola LNG plant.
Transactions between the group and its joint ventures are summarized below.
Sales to joint ventures
Product
LNG, crude oil and oil products, natural gas
Purchases from joint ventures
Sales
2,841
Product
Purchases
LNG, crude oil and oil products, natural gas, refinery operating
2015
Amount
receivable at
31 December
245
2015
Amount
payable at
31 December
2014
Amount
receivable at
31 December
300
2014
Amount
payable at
31 December
Sales
4,125
Purchases
Sales
3,148
Purchases
$ million
2013
Amount
receivable at
31 December
342
$ million
2013
Amount
payable at
31 December
costs, plant processing fees
861
104
907
129
503
51
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.
16. 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
2015
1,330
509
1,839
2014
2,101
701
2,802
2013
2,058
684
2,742
2015
5,797
3,625
9,422
2014
7,312
3,091
10,403
The associate that is material to the group at both 31 December 2015 and 2014 is Rosneft. In 2013, BP sold its 50% interest in TNK-BP to Rosneft and
increased its investment in Rosneft. The net cash inflow in 2013 relating to the transaction included in Net cash used in investing activities in the cash
flow statement was $11.8 billion. From 22 October 2012, the investment in TNK-BP was classified as an asset held for sale and, therefore, equity
accounting ceased. Profits of approximately $738 million were not recognized in 2013 as a result of the discontinuance of equity accounting.
136
BP Annual Report and Form 20-F 2015
16. Investments in associates – continued
Since 21 March 2013, BP has owned 19.75% of the voting shares of Rosneft. Rosneft shares are listed on the MICEX stock exchange in Moscow and
its global depository receipts are listed on the London Stock Exchange. The Russian federal government, through its investment company OJSC
Rosneftegaz, owned 69.5% of the voting shares of Rosneft at 31 December 2015.
BP classifies its investment in Rosneft as an associate because, in management’s judgement, BP has significant influence over Rosneft; see Note 1 –
Interests in other entities – Significant estimate or judgement: accounting for interests in other entities. The group’s investment in Rosneft is a foreign
operation whose functional currency is the Russian rouble. The reduction in the group’s equity-accounted investment balance for Rosneft at
31 December 2015 compared with 31 December 2014 was principally due to the weakening of the rouble compared to the US dollar, the effects of
which have been recognized in other comprehensive income.
The value of BP’s 19.75% shareholding in Rosneft based on the quoted market share price of $3.48 per share (2014 $3.51 per share) was
$7,283 million at 31 December 2015 (2014 $7,346 million).
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. These adjustments have increased the reported profit for 2015, as shown in the table below, compared with the equivalent amount in
Russian roubles that we expect Rosneft to report in its own financial statements under IFRS.
Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Non-controlling interests
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
$ million
Gross amount
2014
2013
142,856
122,866
14,106
1,337
12,769
2,137
213
10,419
(441)
9,978
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
2015
84,071
12,253
3,696
8,557
1,792
30
6,735
19,367
5,230
14,137
3,428
71
10,638
(4,111)
(13,038)
2,624
(2,400)
84,689
34,891
119,580
25,691
63,554
89,245
30,335
982
29,353
101,073
38,278
139,351
36,400
65,266
101,666
37,685
663
37,022
The group received dividends, net of withholding tax, of $271 million from Rosneft in 2015 (2014 dividends of $693 million and 2013 dividends of
$456 million).
BP Annual Report and Form 20-F 2015
137
16. Investments in associates – continued
Summarized financial information for the group’s share of associates is shown below.
Sales and other operating revenues
16,604
6,000
22,604
28,214
9,724
37,938
24,266
12,998
37,264
Rosnefta
Other
2015
Total
Rosnefta
Other
2014
Total
Rosneft
Other
$ million
BP share
2013
Total
Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Non-controlling interests
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 associates
Group share of net assets (as above)
Loans made by group companies to
associates
2,420
730
1,690
354
6
1,330
(812)
518
16,726
6,891
23,617
5,074
12,552
17,626
5,991
194
5,797
661
6
655
146
–
509
(2)
507
3,914
1,621
5,535
1,134
1,311
2,445
3,090
–
3,090
3,081
736
2,345
500
6
1,839
3,825
1,033
2,792
677
14
2,101
(814)
(2,575)
1,025
20,640
8,512
29,152
6,208
13,863
20,071
9,081
194
8,887
(474)
19,962
7,560
27,522
7,189
12,890
20,079
7,443
131
7,312
938
7
931
230
–
701
10
711
2,975
2,199
5,174
1,614
921
2,535
2,639
–
2,639
4,763
1,040
3,723
907
14
2,802
2,786
264
2,522
422
42
2,058
(2,565)
(87)
237
1,971
908
11
897
213
–
684
2
686
3,694
275
3,419
635
42
2,742
(85)
2,657
22,937
9,759
32,696
8,803
13,811
22,614
10,082
131
9,951
5,797
3,090
8,887
7,312
2,639
9,951
–
535
5,797
3,625
535
9,422
–
452
452
7,312
3,091
10,403
a From 1 October 2014, Rosneft adopted hedge accounting in relation to a portion of highly probable future export revenue denominated in US dollars over a five-year period. Foreign exchange gains and
losses arising on the retranslation of borrowings denominated in currencies other than the Russian rouble and designated as hedging instruments are recognized initially in other comprehensive
income, and are reclassified to the income statement as the hedged revenue is recognized.
Transactions between the group and its associates are summarized below.
Sales to associates
Product
LNG, crude oil and oil products, natural gas
Purchases from associates
Product
Crude oil and oil products, natural gas, transportation tariff
2015
Amount
receivable at
31 December
1,058
2015
Amount
payable at
31 December
2014
Amount
receivable at
31 December
1,258
2014
Amount
payable at
31 December
Sales
9,589
Purchases
Sales
5,170
Purchases
$ million
2013
Amount
receivable at
31 December
783
$ million
2013
Amount
payable at
31 December
2,026
22,703
2,307
21,205
3,470
Sales
5,302
Purchases
11,619
In addition to the transactions shown in the table above, in 2015 the group acquired a 20% participatory interest in Taas-Yuryakh Neftegazodobycha, a
Rosneft subsidiary.
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 the sales to and purchases from associates relate to crude oil and oil products transactions with Rosneft.
BP has commitments amounting to $11,446 million (2014 $6,946 million), primarily in relation to contracts with its associates for the purchase of
transportation capacity.
138
BP Annual Report and Form 20-F 2015
17. Other investments
Equity investmentsa
Other
a The majority of equity investments are unlisted.
2015
$ million
2014
Current
Non-current
Current
Non-current
–
219
219
397
605
1,002
–
329
329
420
808
1,228
Other non-current investments includes $605 million relating to life insurance policies (2014 $599 million) which have been designated as financial
assets at fair value through profit and loss and their valuation methodology is in level 3 of the fair value hierarchy.
18. Inventories
Crude oil
Natural gas
Refined petroleum and petrochemical products
Supplies
Trading inventories
2015
3,467
251
7,470
11,188
2,626
13,814
328
14,142
$ million
2014
5,614
285
8,975
14,874
3,051
17,925
448
18,373
Cost of inventories expensed in the income statement
164,790
281,907
The inventory valuation at 31 December 2015 is stated net of a provision of $1,295 million (2014 $2,879 million) to write inventories down to their net
realizable value. The net credit to the income statement in the year in respect of inventory net realizable value provisions was $1,507 million (2014
$2,625 million charge).
Trading inventories are valued using quoted benchmark bid prices adjusted as appropriate for location and quality differentials. As such they are
predominantly categorized within level 2 of the fair value hierarchy.
19. Trade and other receivables
2015
$ million
2014
Current
Non-current
Current
Non-current
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Financial assets
Trade receivables
Amounts receivable from joint ventures and associates
Other receivables
Non-financial assets
Gulf of Mexico oil spill trust fund reimbursement asseta
Other receivables
13,682
1,303
5,908
20,893
686
744
1,430
72
–
1,249
1,321
–
895
895
19,671
1,558
7,863
29,092
1,154
792
1,946
22,323
2,216
31,038
a See Note 2 for further information.
Trade and other receivables are predominantly non-interest bearing. See Note 28 for further information.
20. Valuation and qualifying accounts
2015
2014
166
–
1,293
1,459
2,701
627
3,328
4,787
$ million
2013
At 1 January
Charged to costs and expenses
Charged to other accountsa
Deductions
At 31 December
a Principally exchange adjustments.
Accounts
receivable
Fixed asset
investments
Accounts
receivable
Fixed asset
investments
Accounts
receivable
Fixed asset
investments
331
243
(23)
(104)
447
517
195
(4)
(273)
435
343
127
(24)
(115)
331
168
438
(2)
(87)
517
489
82
(4)
(224)
343
349
4
4
(189)
168
Valuation and qualifying accounts comprise impairment provisions for accounts receivable and fixed asset investments, and are deducted in the
balance sheet from the assets to which they apply.
For information on significant estimates and judgements made in relation to the recoverability of trade receivables see Impairment of loans and
receivables within Note 1.
BP Annual Report and Form 20-F 2015
139
–
–
2,985
2,985
602
3,587
$ million
Total
32,898
(502)
14,894
(373)
416
(333)
(4,521)
(1,287)
(78)
41,114
5,154
35,960
16,507
21. Trade and other payables
Financial liabilities
Trade payables
Amounts payable to joint ventures and associates
Other payables
Non-financial liabilities
Other payables
Trade and other payables are predominantly interest free. See Note 28 for further information.
2015
$ million
2014
Current
Non-current
Current
Non-current
16,838
2,130
10,775
29,743
2,206
31,949
–
–
2,351
2,351
559
2,910
23,074
2,436
11,832
37,342
2,776
40,118
22. Provisions
At 1 January 2015
Exchange adjustments
New or increased provisions
Write-back of unused provisions
Unwinding of discount
Change in discount ratea
Utilization
Reclassified to other payables
Deletions
At 31 December 2015
Of which – current
– non-current
Of which – Gulf of Mexico oil spillb
Decommissioning Environmental
Litigation and
claims
Clean Water
Act penalties
18,720
(356)
972
–
167
–
(37)
(500)
(20)
18,946
703
18,243
–
2,847
(18)
5,697
(75)
106
(149)
(392)
(459)
–
7,557
587
6,970
5,919
4,739
(9)
6,058
(24)
62
(74)
(3,494)
(124)
–
7,134
3,023
4,111
6,459
3,510
–
661
–
68
(110)
–
–
–
4,129
–
4,129
4,129
Other
3,082
(119)
1,506
(274)
13
–
(598)
(204)
(58)
3,348
841
2,507
–
a Provisions for the agreements to settle all federal and state claims in relation to the Gulf of Mexico oil spill are discounted using a discount rate equal to a current interest rate that the group could
obtain for a borrowing on similar terms.
b Further information on the financial impacts of the Gulf of Mexico oil spill is provided in Note 2.
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. Included within the other category at
31 December 2015 are provisions for deferred employee compensation of $484 million (2014 $553 million).
For information on significant estimates and judgements made in relation to provisions, including those for the Gulf of Mexico oil spill, see Provisions,
contingencies and reimbursement assets within Note 1.
23. 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 within 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, including 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 UK plan is closed to new
joiners but remains 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 employees who previously accrued pension benefits under a final salary plan now accrue benefits from 2015 onwards under a cash
balance formula instead. Benefits previously accrued under final salary formulas are legally protected. Retired 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 composed of six 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 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.
140
BP Annual Report and Form 20-F 2015
23. 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 set out in German tax law. Retired German employees take their pension benefit typically
in the form of an annuity. The German plan is 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 2015 the aggregate level of contributions was $1,066 million (2014 $1,252 million and 2013 $1,272 million). The aggregate level of contributions
in 2016 is expected to be approximately $1,050 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 the latest funding position is reviewed
and a schedule of contributions covering the next seven years is agreed. The funding agreement can be terminated unilaterally by either party with two
years’ notice. Contractually committed funding therefore represents nine years of future contributions, which amounted to $4,374 million at
31 December 2015, of which $1,437 million relates to past 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 220. 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.
Pension contributions in the US are determined by legislation and are supplemented by discretionary contributions. All of the contributions made into
the US pension plan in 2015 were discretionary and no statutory funding requirement is expected in the next 12 months.
There was no minimum funding requirement for the US plan, and no significant minimum funding requirements in other countries at 31 December
2015.
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 2015. 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 2014.
A valuation of the US plan is 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
2015
2014
3.9
4.4
3.0
3.0
3.0
2015
3.9
3.6
3.1
3.6
4.5
3.0
3.0
3.0
2014
4.8
4.6
3.4
UK
2013
4.6
5.1
3.3
3.3
3.3
UK
2013
4.4
4.4
3.1
2015
2014
4.0
3.9
–
–
1.5
2015
3.8
3.7
1.6
3.7
4.0
–
–
1.6
2014
4.6
4.3
2.1
US
2013
4.3
3.9
–
–
2.1
US
2013
3.3
3.3
2.4
2015
2014
2.4
3.2
1.6
0.6
1.8
2015
2.3
2.0
2.0
2.0
3.4
1.8
0.7
2.0
2014
3.9
3.6
2.0
%
Eurozone
2013
3.6
3.4
1.8
0.7
2.0
%
Eurozone
2013
3.5
3.5
2.0
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 one
of these approaches, 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 allowance for promotion-related salary growth, of up to 1.0% depending on country.
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 the latest available 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
2015
28.5
31.0
29.5
31.9
2014
28.3
30.9
29.4
31.8
UK
2013
27.8
30.7
29.5
32.2
2015
25.7
27.5
29.2
30.9
2014
25.6
27.4
29.1
30.9
US
2013
24.9
26.4
26.5
27.3
2015
24.9
27.5
28.8
31.2
2014
24.7
27.3
28.7
31.1
Years
Eurozone
2013
24.4
26.9
28.5
30.7
Pension plan assets are generally held in trusts. The primary objective of the trusts is to accumulate pools of assets sufficient to meet the obligations
of the various plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices
in portfolio management.
BP Annual Report and Form 20-F 2015
141
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
23. Pensions and other post-retirement benefits – continued
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.
For the primary UK pension plan there is an agreement with the trustee to reduce the proportion of plan assets held as equities and increase the
proportion held as bonds over time, with a view to better matching the asset portfolio with the pension liabilities. There is a similar agreement in place
in the US. During 2015, the UK and the US plans switched 8% and 5% respectively from equities to bonds.
In 2015, BP’s primary plan in the UK adopted a more formal liability driven investment (LDI) approach for part of the portfolio, a form of investing
designed to match the movement in pension plan assets with the impact of interest rate changes and inflation assumption changes on the projected
benefit obligation.
The current asset allocation policy for the major plans at 31 December 2015 was as follows:
Asset category
Total equity (including private equity)
Bonds/cash (including LDI)
Property/real estate
UK
%
62
31
7
US
%
55
45
–
The amounts invested under the LDI programme as at 31 December 2015 were $329 million of government-issued nominal bonds and $6,421 million
of index-linked bonds. This is partly funded by short-term sale and repurchase agreements, proceeds from which are shown separately in the table
below.
In addition, the primary UK plan entered into interest rate swaps in the year to offset the long-term fixed interest rate exposure for $2,651 million of the
corporate bond portfolio. The $17 million fair value of the swaps as at 31 December 2015 is included in other assets in the table below.
Some of the group’s pension plans in other countries also use derivative financial instruments as part of their asset mix to manage the level of risk.
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 143.
Fair value of pension plan assets
At 31 December 2015
Listed equities – developed markets
– emerging markets
Private equity
Government issued nominal bonds
Government issued index-linked bonds
Corporate bonds
Property
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments
At 31 December 2014
Listed equities – developed markets
– emerging markets
Private equity
Government issued nominal bonds
Government issued index-linked bonds
Corporate bonds
Property
Cash
Other
At 31 December 2013
Listed equities – developed markets
– emerging markets
Private equity
Government issued nominal bonds
Government issued index-linked bonds
Corporate bonds
Property
Cash
Other
UKa
USb
Eurozone
Other
13,474
2,305
2,933
393
6,425
4,357
2,453
564
110
(1,791)
31,223
16,190
2,719
2,983
642
892
4,687
2,403
1,145
112
31,773
17,341
2,290
2,907
549
787
4,427
2,200
855
160
31,516
2,329
226
1,522
1,527
–
1,717
6
116
67
–
7,510
3,026
293
1,571
1,535
–
1,726
7
134
63
8,355
3,260
308
1,432
1,259
–
1,323
6
135
55
7,778
423
49
1
685
5
551
48
10
102
–
1,874
415
45
2
753
9
541
51
85
72
1,973
414
32
2
717
12
597
57
120
64
2,015
371
50
4
492
–
367
58
139
50
–
1,531
420
47
26
604
–
340
69
191
38
1,735
499
52
4
541
57
385
77
158
49
1,822
$ million
Total
16,597
2,630
4,460
3,097
6,430
6,992
2,565
829
329
(1,791)
42,138
20,051
3,104
4,582
3,534
901
7,294
2,530
1,555
285
43,836
21,514
2,682
4,345
3,066
856
6,732
2,340
1,268
328
43,131
a Bonds held by the UK pension plans are all 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.
142
BP Annual Report and Form 20-F 2015
23. Pensions and other post-retirement benefits – continued
Analysis of the amount charged to profit (loss) before interest and taxation
Current service costa
Past service costb
Settlement
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 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
Acquisitions
Reclassified as assets held for sale
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
Contributions by plan participantsc
Contributions by employers (funded plans)
Benefit payments (funded plans)d
Acquisitions
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
485
12
–
497
31
528
(1,124)
1,146
22
315
2,054
–
336
2,705
32,416
(1,451)
497
1,146
32
(1,269)
(7)
–
–
(2,390)
28,974
31,773
(1,506)
1,124
32
754
(1,269)
–
315
31,223
2,249
2,516
(267)
2,249
2,506
(257)
2,249
371
(27)
–
344
205
549
(289)
423
134
(139)
607
60
(48)
480
11,875
–
344
423
–
(1,124)
(256)
–
–
(619)
10,643
8,355
–
289
–
129
(1,124)
–
(139)
7,510
(3,133)
66
(3,199)
(3,133)
49
(3,182)
(3,133)
96
47
(1)
142
8
150
(37)
151
114
25
592
15
47
679
8,327
(843)
142
151
2
(81)
(306)
–
(98)
(654)
6,640
1,973
(205)
37
2
123
(81)
–
25
1,874
(4,766)
25
(4,791)
(4,766)
(254)
(4,512)
(4,766)
96
(7)
(3)
86
41
127
(55)
91
36
33
213
–
29
275
2,638
(294)
86
91
5
(178)
(26)
9
–
(242)
2,089
1,735
(186)
55
5
60
(178)
7
33
1,531
(558)
40
(598)
(558)
(187)
(371)
(558)
$ million
2015
Total
1,048
25
(4)
1,069
285
1,354
(1,505)
1,811
306
234
3,466
75
364
4,139
55,256
(2,588)
1,069
1,811
39
(2,652)
(595)
9
(98)
(3,905)
48,346
43,836
(1,897)
1,505
39
1,066
(2,652)
7
234
42,138
(6,208)
2,647
(8,855)
(6,208)
2,114
(8,322)
(6,208)
(28,717)
(257)
(28,974)
(7,461)
(3,182)
(10,643)
(2,128)
(4,512)
(6,640)
(1,718)
(371)
(2,089)
(40,024)
(8,322)
(48,346)
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
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 have arisen from restructuring programmes and represent a combination of credits as a result of the curtailment in the pension arrangements of a number of employees mostly in the
US and Trinidad and charges for special termination benefits representing the increased liability arising as a result of early retirements mostly in the UK and Eurozone.
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 $3,128 million benefits and $57 million settlements, plus $62 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for the US is made up of $8,061 million for pension liabilities and $2,582 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical
liabilities). The benefit obligation for the Eurozone includes $4,151 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 142.
BP Annual Report and Form 20-F 2015
143
23. Pensions and other post-retirement benefits – continued
Analysis of the amount charged to profit (loss) before interest and taxation
Current service costa
Past service costb
Settlementc
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 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 participantsd
Benefit payments (funded plans)e
Benefit payments (unfunded plans)e
Acquisitions
Disposals
Remeasurements
Benefit obligation at 31 Decembera f
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 g
Contributions by plan participantsd
Contributions by employers (funded plans)
Benefit payments (funded plans)e
Acquisitions
Disposals
Remeasurementsg
Fair value of plan assets at 31 December
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
494
–
–
494
30
524
(1,425)
1,378
(47)
1,269
(3,188)
42
(41)
(1,918)
30,552
(1,993)
494
1,378
39
(1,231)
(10)
–
–
3,187
32,416
31,516
(1,958)
1,425
39
713
(1,231)
–
–
1,269
31,773
356
(33)
(66)
257
214
471
(317)
458
141
768
(1,004)
(264)
13
(487)
11,002
–
257
458
–
(865)
(238)
6
–
1,255
11,875
7,778
–
317
–
354
(865)
3
–
768
8,355
72
20
–
92
11
103
(70)
255
185
119
(1,845)
(20)
(86)
(1,832)
7,536
(1,040)
92
255
4
(83)
(370)
–
(18)
1,951
8,327
2,015
(257)
70
4
110
(83)
–
(5)
119
1,973
87
1
–
88
54
142
(80)
115
35
31
(350)
(9)
(25)
(353)
2,443
(256)
88
115
7
(119)
(24)
–
–
384
2,638
1,822
(161)
80
7
75
(119)
–
–
31
1,735
$ million
2014
Total
1,009
(12)
(66)
931
309
1,240
(1,892)
2,206
314
2,187
(6,387)
(251)
(139)
(4,590)
51,533
(3,289)
931
2,206
50
(2,298)
(642)
6
(18)
6,777
55,256
43,131
(2,376)
1,892
50
1,252
(2,298)
3
(5)
2,187
43,836
(643)
(3,520)
(6,354)
(903)
(11,420)
15
(658)
(643)
(310)
(333)
(643)
–
(3,520)
(3,520)
(19)
(3,501)
(3,520)
(32,083)
(333)
(32,416)
(8,374)
(3,501)
(11,875)
3
(6,357)
(6,354)
(663)
(5,691)
(6,354)
(2,636)
(5,691)
(8,327)
13
(916)
(903)
(384)
(519)
(903)
31
(11,451)
(11,420)
(1,376)
(10,044)
(11,420)
(2,119)
(519)
(2,638)
(45,212)
(10,044)
(55,256)
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 in the US include a credit of $21 million as the result of a curtailment in the pension arrangement of a number of employees following a business reorganization and a credit of
$12 million reflecting a plan amendment to a medical plan. A charge of $21 million for special termination benefits represents the increased liability arising as a result of early retirements occurring as
part of restructuring programmes mostly in the Eurozone.
c Settlements represent a gain of $66 million arising from an offer to a group of plan members in the US to settle annuity liabilities with lump sum payments.
d Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.
e The benefit payments amount shown above comprises $2,621 million benefits and $257 million settlements, plus $62 million of plan expenses incurred in the administration of the benefit.
f The benefit obligation for the US is made up of $9,033 million for pension liabilities and $2,842 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical
liabilities). The benefit obligation for the Eurozone includes $5,220 million for pension liabilities in Germany which is largely unfunded.
g 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.
144
BP Annual Report and Form 20-F 2015
23. Pensions and other post-retirement benefits – continued
Analysis of the amount charged to profit (loss) before interest and taxation
Current service costa
Past service cost
Settlement
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 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
UK
US
Eurozone
Other
497
(22)
–
475
24
499
(1,139)
1,223
84
2,671
68
–
43
2,782
407
(49)
–
358
223
581
(240)
406
166
730
1,160
14
(249)
1,655
81
26
–
107
9
116
(63)
254
191
15
62
–
2
79
96
1
(1)
96
44
140
(67)
106
39
99
213
(65)
1
248
$ million
2013
Total
1,081
(44)
(1)
1,036
300
1,336
(1,509)
1,989
480
3,515
1,503
(51)
(203)
4,764
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.
At 31 December 2015, reimbursement balances due from or to other companies in respect of pensions amounted to $377 million reimbursement
assets (2014 $426 million) and $13 million reimbursement liabilities (2014 $16 million). These balances are not included as part of the pension
surpluses and deficits, but are reflected within other receivables and other payables in the group balance sheet.
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 2015 for the group’s plans would have had the effects shown in the table below. The
effects shown for the expense in 2016 comprise the total of current service cost and net finance income or expense.
Discount ratea
Effect on pension and other post-retirement benefit expense in 2016
Effect on pension and other post-retirement benefit obligation at 31 December 2015
Inflation rateb
Effect on pension and other post-retirement benefit expense in 2016
Effect on pension and other post-retirement benefit obligation at 31 December 2015
Salary growth
Effect on pension and other post-retirement benefit expense in 2016
Effect on pension and other post-retirement benefit obligation at 31 December 2015
$ million
One percentage point
Decrease
Increase
(416)
(6,897)
408
6,996
112
1,135
387
8,911
(312)
(5,523)
(99)
(1,004)
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 2016 pension and other post-retirement benefit expense by
$60 million and the pension and other post-retirement benefit obligation at 31 December 2015 by $1,329 million.
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 2025 and the weighted
average duration of the defined benefit obligations at 31 December 2015 are as follows:
Estimated future benefit payments
2016
2017
2018
2019
2020
2021-2025
UK
1,061
1,098
1,150
1,188
1,210
6,575
US
Eurozone
Other
966
838
846
839
834
3,966
363
345
337
327
319
1,517
120
117
121
125
127
667
$ million
Total
2,510
2,398
2,454
2,479
2,490
12,725
years
Weighted average duration
18.2
9.4
14.0
14.0
F
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24. Cash and cash equivalents
Cash
Term bank deposits
Cash equivalents
2015
4,653
16,749
4,987
26,389
$ million
2014
5,112
18,392
6,259
29,763
Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; term deposits of three months or less with
banks and similar institutions; money market funds and commercial paper. The carrying amounts of cash 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 2015 includes $2,439 million (2014 $2,264 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 $4,329 million (2014 $3,852 million) of cash and cash equivalents outside the UK and it is not expected that any significant tax will
arise on repatriation.
25. Finance debt
Borrowings
Net obligations under finance leases
Current
6,898
46
6,944
Non-current
45,567
657
46,224
2015
Total
52,465
703
53,168
Current
6,831
46
6,877
Non-current
45,240
737
45,977
$ million
2014
Total
52,071
783
52,854
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
$5,942 million (2014 $6,343 million) and issued commercial paper of $869 million (2014 $444 million). Finance debt does not include accrued interest,
which is reported within other payables.
At 31 December 2015, $122 million (2014 $137 million) of finance debt was secured by the pledging of assets. The remainder of finance debt was
unsecured.
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
3
6
4
17
3
19
Weighted
average
interest
rate
%
1
1
1
1
Amount
$ million
10,442
826
11,268
14,285
871
15,156
Amount
$ million
40,623
1,277
41,900
36,275
1,423
37,698
Amount
$ million
2015
51,065
2,103
53,168
2014
50,560
2,294
52,854
The floating rate debt denominated in other currencies represents euro debt not swapped to US dollars, which is naturally hedged with respect to
foreign currency risk by holding equivalent euro cash and cash equivalent amounts.
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 2015, whereas in the balance
sheet the amount is reported within current finance debt.
The carrying amount of the group’s short-term borrowings, comprising mainly commercial paper, approximates their fair value. The fair values of the
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. The fair value of the group’s finance lease obligations is estimated using discounted cash flow analyses
based on the group’s current incremental borrowing rates for similar types and maturities of borrowing and are consequently categorized in level 2 of
the fair value hierarchy.
Short-term borrowings
Long-term borrowings
Net obligations under finance leases
Total finance debt
146
BP Annual Report and Form 20-F 2015
2015
Carrying
amount
956
51,509
703
53,168
Fair value
487
51,995
1,343
53,825
Fair value
956
51,404
1,178
53,538
$ million
2014
Carrying
amount
487
51,584
783
52,854
26. Capital disclosures and analysis of changes in net debt
The group defines capital as total equity. 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 the basis of the net debt ratio, that is, the ratio of net debt to net debt plus equity. Net debt is calculated as gross 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 net debt ratio are non-
GAAP measures. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross
debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity
from shareholders. 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.
We aim to maintain the net debt ratio, with some flexibility, at around 20%. We expect the net debt ratio to be above 20% while oil prices remain
weak. At 31 December 2015, the net debt ratio was 21.6% (2014 16.7%).
At 31 December
Gross debt
Less: fair value asset (liability) of hedges related to finance debta
Less: cash and cash equivalents
Net debt
Equity
Net debt ratio
2015
53,168
(379)
53,547
26,389
27,158
98,387
21.6%
$ million
2014
52,854
445
52,409
29,763
22,646
112,642
16.7%
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 $1,617 million
(2014 liability of $774 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments.
An analysis of changes in net debt is provided below.
Movement in net debt
At 1 January
Exchange adjustments
Net cash flow
Other movements
At 31 December
Finance
debta
(52,409)
1,065
(2,220)
17
(53,547)
Cash and
cash
equivalents
29,763
(672)
(2,702)
–
26,389
2015
Net debt
(22,646)
393
(4,922)
17
(27,158)
Finance
debta
(47,715)
1,160
(5,419)
(435)
(52,409)
Cash and
cash
equivalents
22,520
(671)
7,914
–
29,763
$ million
2014
Net debt
(25,195)
489
2,495
(435)
(22,646)
F
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t
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a Including the fair value of associated derivative financial instruments for which hedge accounting is applied.
27. Operating leases
The cost recognized in relation to minimum lease payments for the year was $6,008 million (2014 $6,324 million and 2013 $5,961 million).
The future minimum lease payments at 31 December 2015, before deducting related rental income from operating sub-leases of $166 million (2014
$234 million), are shown in the table below. This does not include future contingent rentals. Where the lease rentals are dependent on a variable factor,
the future minimum lease payments are based on the factor as at inception of the lease.
Future minimum lease payments
Payable within
1 year
2 to 5 years
Thereafter
2015
4,144
7,743
3,535
$ million
2014
5,401
9,916
3,468
15,422
18,785
In the case of an operating lease entered into by BP as the operator of a joint operation, the amounts included in the totals disclosed represent the net
operating lease expense and net future minimum lease payments. These net amounts are after deducting amounts reimbursed, or to be reimbursed,
by joint operators, whether the joint operators have co-signed the lease or not. Where BP is not the operator of a joint operation, BP’s share of the
lease expense and future minimum lease payments is included in the amounts shown, whether BP has co-signed the lease or not.
Typical durations of operating leases are up to forty years for leases of land and buildings, up to fifteen years for leases of ships and commercial
vehicles and up to ten years for leases of plant and machinery.
The group has entered into a number of structured operating leases for ships and in most cases the lease rental payments vary with market interest rates.
The variable portion of the lease payments above or below the amount based on the market interest rate prevailing at inception of the lease is treated as
contingent rental expense. The group also routinely enters into bareboat charters, time-charters and voyage-charters for ships on standard industry terms.
The most significant items of plant and machinery hired under operating leases are drilling rigs used in the Upstream segment. At 31 December 2015,
the future minimum lease payments relating to drilling rigs amounted to $4,783 million (2014 $8,180 million).
Commercial vehicles hired under operating leases are primarily railcars. Retail service station sites and office accommodation are the main items in the
land and buildings category.
The terms and conditions of these operating leases do not impose any significant financial restrictions on the group. Some of the leases of ships and
buildings allow for renewals at BP’s option, and some of the group’s operating leases contain escalation clauses.
BP Annual Report and Form 20-F 2015
147
28. Financial instruments and financial risk factors
The accounting classification of each category of financial instruments, and their carrying amounts, are set out below.
At 31 December 2015
Financial assets
Other investments – equity shares
– other
Loans
Trade and other receivables
Derivative financial instruments
Cash and cash equivalents
Financial liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
At 31 December 2014
Financial assets
Other investments – equity shares
– other
Loans
Trade and other receivables
Derivative financial instruments
Cash and cash equivalents
Financial liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Note
Loans and
receivables
Available-
for-sale financial
assets
Held-to-
maturity
investments
At fair value
through profit
or loss
Derivative
hedging
instruments
Financial
liabilities
measured at
amortized cost
$ million
Total carrying
amount
17
17
19
29
24
21
29
25
17
17
19
29
24
21
29
25
–
–
801
22,214
–
21,402
–
–
–
–
397
219
–
–
–
2,859
–
–
–
–
–
–
–
–
–
2,128
–
–
–
–
44,417
3,475
2,128
–
–
992
30,551
–
23,504
–
–
–
–
420
538
–
–
–
2,989
–
–
–
–
–
–
–
–
–
3,270
–
–
–
–
55,047
3,947
3,270
–
605
–
–
7,700
–
–
(6,139)
–
–
2,166
–
599
–
–
8,511
–
–
(6,100)
–
–
3,010
–
–
–
–
951
–
–
(1,383)
–
–
(432)
–
–
–
–
1,096
–
–
(788)
–
–
308
–
–
–
–
–
–
(32,094)
–
(7,151)
(53,168)
(92,413)
–
–
–
–
–
–
(40,327)
–
(7,963)
(52,854)
(101,144)
397
824
801
22,214
8,651
26,389
(32,094)
(7,522)
(7,151)
(53,168)
(40,659)
420
1,137
992
30,551
9,607
29,763
(40,327)
(6,888)
(7,963)
(52,854)
(35,562)
The fair value of finance debt is shown in Note 25. For all other financial instruments, the carrying amount is either the fair value, or approximates the
fair value.
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, while the
activities in the financial markets are managed by the treasury function, working under the compliance and control structure of the 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 monitors and validates limits and risk exposures, reviews incidents and validates risk-
related policies, methodologies and procedures. A commitments committee approves value-at-risk delegations, 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.
148
BP Annual Report and Form 20-F 2015
28. Financial instruments and financial risk factors – continued
(i) Commodity price risk
The group’s integrated supply and trading function uses conventional financial and commodity instruments and physical cargoes and pipeline positions
available in the related commodity markets. Oil and natural gas swaps, options and futures are used to mitigate price risk. Power trading is undertaken
using a combination of over-the-counter forward contracts and other derivative contracts, including options and futures. This activity is on both a
standalone basis and in conjunction with gas derivatives in relation to gas-generated power margin. In addition, NGLs are traded around certain US
inventory locations using over-the-counter forward contracts in conjunction with over-the-counter swaps, options and physical inventories.
The group measures market risk exposure arising from its trading positions in liquid periods using value-at-risk techniques. These techniques make a
statistical assessment of the market risk arising from possible future changes in market prices over a one-day holding period. The value-at-risk measure
is supplemented by stress testing. Trading activity occurring in liquid periods is subject to value-at-risk limits for each trading activity and for this trading
activity in total. The board has delegated a limit of $100 million value at risk in support of this trading activity. Alternative measures are used to monitor
exposures which are outside liquid periods and which cannot be actively risk-managed.
(ii) Foreign currency exchange risk
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 above.
Since BP has global operations, fluctuations in foreign currency exchange rates can have a significant effect on the group’s reported results. 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.
The group manages these 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.
The most significant exposures relate to capital expenditure commitments and other UK, Eurozone and Australian operational requirements, for which
hedging programmes are in place and hedge accounting is applied as outlined in Note 1.
For highly probable forecast capital expenditures the group locks in the US dollar cost of non-US dollar supplies by using currency forwards and futures.
The main exposures are sterling, euro, Australian dollar and South Korean won. At 31 December 2015 the most significant open contracts in place
were for $627 million sterling (2014 $321 million sterling).
For other UK, Eurozone and Australian operational requirements the group uses cylinders (purchased call and sold put options) to manage the
estimated exposures on a 12-month rolling basis. At 31 December 2015, the open positions relating to cylinders consisted of receive sterling, pay US
dollar cylinders for $2,479 million (2014 $2,787 million); receive euro, pay US dollar cylinders for $560 million (2014 $867 million); receive Australian
dollar, pay US dollar cylinders for $312 million (2014 $418 million).
In addition, most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2015, the total foreign
currency net borrowings not swapped into US dollars amounted to $826 million (2014 $871 million).
(iii) Interest rate risk
Where the group enters into money market contracts for entrepreneurial trading purposes the activity is controlled using value-at-risk techniques as
described above.
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 in a variety of currencies based on market opportunities, it uses derivatives to swap
the debt to a floating rate exposure, 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 2015 was 79% of total finance debt outstanding
(2014 71%). The weighted average interest rate on finance debt at 31 December 2015 was 2% (2014 2%) and the weighted average maturity of fixed
rate debt was five years (2014 four years).
The group’s earnings are sensitive to changes in interest rates on the floating rate element of the group’s finance debt. If the interest rates applicable
to floating rate instruments were to have increased by one percentage point on 1 January 2016, it is estimated that the group’s finance costs for 2016
would increase by approximately $419 million (2014 $377 million increase).
(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 2015 was $35 million (2014 $83 million) in
respect of liabilities of joint ventures and associates and $163 million (2014 $244 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.
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 2015, the group had in place credit enhancements designed to mitigate
approximately $10.9 billion of credit risk (2014 $10.8 billion). 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.
BP Annual Report and Form 20-F 2015
149
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28. Financial instruments and financial risk factors – continued
Management information used to monitor credit risk indicates that 81% (2014 82%) of total unmitigated credit exposure relates to counterparties of
investment-grade credit quality.
Trade and other receivables at 31 December
Neither impaired nor past due
Impaired (net of provision)
Not impaired and past due in the following periods
within 30 days
31 to 60 days
61 to 90 days
over 90 days
2015
21,064
22
414
75
118
521
$ million
2014
28,519
37
841
249
178
727
22,214
30,551
Movements in the impairment provision for trade receivables are shown in Note 20.
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 2015
Derivative assets
Derivative liabilities
Trade receivables
Trade payables
At 31 December 2014
Derivative assets
Derivative liabilities
Trade receivables
Trade payables
Gross
amounts of
recognized
financial
assets
(liabilities)
10,206
(9,280)
7,091
(5,720)
11,515
(8,971)
10,502
(9,062)
Amounts
set off
(1,859)
1,859
(3,689)
3,689
(2,383)
2,383
(6,080)
6,080
Related amounts not set off
in the balance sheet
Net amounts
presented on
the balance
sheet
Master
netting
arrangements
Cash
collateral
(received)
pledged
8,347
(7,421)
3,402
(2,031)
9,132
(6,588)
4,422
(2,982)
(1,109)
1,109
(322)
322
(1,164)
1,164
(485)
485
(297)
–
(161)
–
(458)
–
(145)
–
$ million
Net amount
6,941
(6,312)
2,919
(1,709)
7,510
(5,424)
3,792
(2,497)
(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 treasury, 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.
Standard & Poor’s Ratings long-term credit rating for BP is A negative (stable outlook) and Moody’s Investors Service rating is A2 (rating under review
from positive).
During 2015, $8 billion of long-term taxable bonds were issued with terms ranging from 1 to 11 years. 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 $26.4 billion at 31 December
2015 (2014 $29.8 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate and short notice. At
31 December 2015, the group had substantial amounts of undrawn borrowing facilities available, consisting of $7,375 million of standby facilities, of
which $6,975 million is available to draw and repay until the first half of 2018, and $400 million is available to draw and repay until April 2017. These
facilities were renegotiated during 2015 with 26 international banks, and borrowings under them would be at pre-agreed rates.
The group also has committed letter of credit (LC) facilities totalling $6,850 million with a number of banks, allowing LCs to be issued for a maximum
two-year duration. There were also uncommitted secured LC facilities in place at 31 December 2015 for $2,410 million, which are secured against
inventories or receivables when utilized. The facilities only terminate by either party giving a stipulated termination notice to the other.
150
BP Annual Report and Form 20-F 2015
28. Financial instruments and financial risk factors – continued
The amounts shown for finance debt in the table below include future minimum lease payments with respect to finance leases. The table also shows
the timing of cash outflows relating to trade and other payables and accruals.
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
Trade and
other
payables
29,743
971
1,231
56
17
38
38
32,094
Accruals
6,261
380
138
98
74
167
33
7,151
Finance
debt
6,944
5,796
6,208
6,103
6,354
17,651
4,112
53,168
2015
Interest
relating to
finance debt
928
812
704
592
478
1,068
402
4,984
Trade and
other
payables
37,342
708
757
1,446
23
24
27
40,327
Accruals
7,102
493
119
76
41
95
37
7,963
Finance
debt
6,877
6,311
5,652
5,226
6,056
19,504
3,228
52,854
$ million
2014
Interest
relating to
finance debt
892
776
672
578
479
1,111
521
5,029
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 29. Management does not currently anticipate any cash flows 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 for derivative financial instruments entered into for the purpose of managing interest rate and
foreign currency exchange risk associated with net debt, whether or not hedge accounting is applied, based upon contractual payment dates. 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. 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 $15,706 million at 31 December 2015 (2014 $14,615 million) to be received on the same day as
the related cash outflows. For further information on our derivative financial instruments, see Note 29.
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
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
2015
2,959
2,685
1,505
1,700
1,678
5,500
2,739
$ million
2014
293
2,959
2,690
1,505
1,700
5,764
1,325
18,766
16,236
29. 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 28. 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 application of hedge accounting and 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. 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 2015
151
29. 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
Commodity price contracts
Cash flow hedges
Currency forwards, futures and cylinders
Cross-currency interest rate swaps
Fair value hedges
Currency forwards, futures and swaps
Interest rate swaps
Of which – current
– non-current
Fair value
asset
2015
Fair value
liability
144
2,390
3,942
920
292
7,688
12
12
9
–
9
33
909
942
8,651
4,242
4,409
(1,811)
(1,257)
(2,536)
(434)
–
(6,038)
(101)
(101)
(71)
(147)
(218)
(1,108)
(57)
(1,165)
(7,522)
(3,239)
(4,283)
Fair value
asset
122
3,133
3,859
922
389
8,425
86
86
1
–
1
78
1,017
1,095
9,607
5,165
4,442
$ million
2014
Fair value
liability
(902)
(1,976)
(2,518)
(404)
–
(5,800)
(300)
(300)
(161)
(97)
(258)
(518)
(12)
(530)
(6,888)
(3,689)
(3,199)
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 28.
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.
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
Less than
1 year
132
1,729
1,707
459
182
4,209
Less than
1 year
120
2,434
1,991
488
70
5,103
1-2 years
2-3 years
3-4 years
4-5 years
10
432
639
164
110
1,355
1
130
390
103
–
624
1
58
283
79
–
421
–
37
202
47
–
286
1-2 years
2-3 years
3-4 years
4-5 years
–
416
644
203
97
1,360
2
185
261
87
161
696
–
63
202
50
61
376
–
31
160
39
–
230
$ million
2015
Total
144
2,390
3,942
920
292
7,688
$ million
2014
Total
122
3,133
3,859
922
389
8,425
Over
5 years
–
4
721
68
–
793
Over
5 years
–
4
601
55
–
660
At both 31 December 2015 and 2014 the group had contingent consideration receivable in respect of the disposal of the Texas City refinery. The sale
agreement contained an embedded derivative – the whole agreement has, consequently, been designated at fair value through profit or loss and
shown within other derivatives held for trading, and falls within level 3 of the fair value hierarchy. The valuation depends on refinery throughput and
future margins.
152
BP Annual Report and Form 20-F 2015
29. 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
(499)
(1,053)
(1,037)
(246)
(2,835)
Less than
1 year
(69)
(1,714)
(1,310)
(217)
(3,310)
1-2 years
2-3 years
3-4 years
4-5 years
(2)
(163)
(382)
(70)
(617)
(2)
(26)
(210)
(31)
(269)
(347)
(10)
(146)
(34)
(537)
(79)
(2)
(162)
(17)
(260)
1-2 years
2-3 years
3-4 years
4-5 years
(180)
(186)
(292)
(127)
(785)
(1)
(61)
(144)
(39)
(245)
(1)
(8)
(117)
(10)
(136)
(192)
(6)
(99)
(4)
(301)
$ million
2015
Total
(1,811)
(1,257)
(2,536)
(434)
(6,038)
$ million
2014
Total
(902)
(1,976)
(2,518)
(404)
(5,800)
Over
5 years
(882)
(3)
(599)
(36)
(1,520)
Over
5 years
(459)
(1)
(556)
(7)
(1,023)
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
109
4,946
684
5,739
(1,530)
4,209
(104)
(4,083)
(178)
(4,365)
1,530
(2,835)
1,374
Less than
1 year
170
6,388
483
7,041
(1,938)
5,103
(37)
(4,905)
(306)
(5,248)
1,938
(3,310)
1,793
1-2 years
2-3 years
3-4 years
4-5 years
–
1,137
449
1,586
(231)
1,355
–
(700)
(148)
(848)
231
(617)
738
–
402
271
673
(49)
624
–
(177)
(141)
(318)
49
(269)
355
–
213
240
453
(32)
421
–
(423)
(146)
(569)
32
(537)
(116)
–
68
230
298
(12)
286
–
(124)
(148)
(272)
12
(260)
26
1-2 years
2-3 years
3-4 years
4-5 years
–
1,353
374
1,727
(367)
1,360
–
(1,017)
(135)
(1,152)
367
(785)
575
–
354
409
763
(67)
696
–
(197)
(115)
(312)
67
(245)
451
–
130
255
385
(9)
376
–
(45)
(100)
(145)
9
(136)
240
–
71
159
230
–
230
–
(202)
(99)
(301)
–
(301)
(71)
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
$ million
2015
Total
109
6,816
2,622
9,547
(1,859)
7,688
(104)
(6,396)
(1,397)
(7,897)
1,859
(6,038)
1,650
$ million
2014
Total
170
8,316
2,322
10,808
(2,383)
8,425
(37)
(6,854)
(1,292)
(8,183)
2,383
(5,800)
2,625
Over
5 years
–
50
748
798
(5)
793
–
(889)
(636)
(1,525)
5
(1,520)
(727)
Over
5 years
–
20
642
662
(2)
660
–
(488)
(537)
(1,025)
2
(1,023)
(363)
BP Annual Report and Form 20-F 2015
153
29. 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.
Net fair value of contracts at 1 January 2015
Gains (losses) recognized in the income statement
Inception fair value of new contracts
Settlements
Transfers out of level 3
Net fair value of contracts at 31 December 2015
Net fair value of contracts at 1 January 2014
Gains recognized in the income statement
Inception fair value of new contracts
Settlements
Transfers out of level 3
Net fair value of contracts at 31 December 2014
Oil
price
246
(24)
126
(20)
–
328
Oil
price
(18)
270
80
(86)
–
246
Natural gas
price
Power
price
181
272
14
(40)
(107)
320
Natural gas
price
313
133
19
(56)
(228)
181
214
79
87
(72)
(23)
285
Power
price
86
79
62
(13)
–
214
$ million
Total
1,030
419
227
(321)
(130)
1,225
$ million
Total
856
576
161
(335)
(228)
1,030
Other
389
92
–
(189)
–
292
Other
475
94
–
(180)
–
389
The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2015 was a
$293 million gain (2014 $456 million gain related to derivatives still held at 31 December 2014).
Derivative gains and losses
Gains and losses relating to derivative contracts are included within sales and other operating revenues and within purchases in the income statement
depending upon the nature of the activity and type of contract involved. The contract types treated in this way include futures, options, swaps and
certain forward sales and forward purchases contracts, and relate 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. Also included within sales and other
operating revenues are gains and losses on inventory held for trading purposes. The total amount relating to all these items (excluding gains and losses
on realized physical derivative contracts that have been reflected gross in the income statement within sales and purchases) was a net gain of
$5,508 million (2014 $6,154 million net gain and 2013 $587 million net gain). This number does not include gains and losses on realized physical
derivative contracts that have been reflected gross in the income statement within sales and purchases or the change in value of transportation and
storage contracts which are not recognized under IFRS, but does include the associated financially settled contracts. The net amount for actual gains
and losses relating to derivative contracts and all related items therefore differs significantly from the amount disclosed above.
Embedded derivatives
The group has embedded derivatives relating to certain natural gas contracts. The fair value gain on commodity price embedded derivatives included
within distribution and administration expenses was $120 million (2014 gain of $430 million, 2013 gain of $459 million).
Cash flow hedges
At 31 December 2015, the group held currency forwards, futures contracts and cylinders and cross-currency interest rate swaps that were being used
to hedge the foreign currency risk of highly probable forecast transactions and floating rate finance debt. Note 28 outlines the group’s approach to
foreign currency exchange risk management. For cash flow hedges the group only claims hedge accounting for the intrinsic value on the currency with
any fair value attributable to time value taken immediately to the income statement. The amounts remaining in equity at 31 December 2015 in relation
to these cash flow hedges consist of deferred losses of $55 million maturing in 2016, deferred losses of $15 million maturing in 2017 and deferred
losses of $3 million maturing in 2018 and beyond.
Two of the contracts to acquire an 18.5% interest in Rosneft, which completed in March 2013, were designated as hedging instruments in a cash flow
hedge. A cumulative charge of $651 million has been recognized in other comprehensive income, of which a charge of $2,061 million arose in 2013.
This loss will only be reclassified to the income statement if the investment in Rosneft is either sold or impaired.
Fair value hedges
At 31 December 2015, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk on fixed
rate debt issued by the group. The loss on the hedging derivative instruments recognized in the income statement in 2015 was $788 million (2014
$14 million loss and 2013 $1,240 million loss) offset by a gain on the fair value of the finance debt of $833 million (2014 $8 million gain and 2013
$1,228 million gain).
The interest rate and cross-currency interest rate swaps mature within one to eleven years, and have the same maturity terms as the debt that they are
hedging. They are used to convert sterling, euro, Swiss franc, Australian dollar, Canadian dollar, Norwegian Krone and Hong Kong dollar denominated
fixed rate borrowings into floating rate debt. Note 28 outlines the group’s approach to interest rate and foreign currency exchange risk management.
154
BP Annual Report and Form 20-F 2015
30. 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 plansb
Repurchase of ordinary share capitalc
At 31 December
Shares
thousand
7,233
5,473
20,005,961
102,810
–
–
20,108,771
2015
$ million
12
9
21
Shares
thousand
7,233
5,473
5,002 20,426,632
165,644
25,598
(611,913)
26
–
–
5,028 20,005,961
5,049
2014
$ million
12
9
21
5,108
41
6
(153)
5,002
5,023
Shares
thousand
7,233
5,473
20,959,159
202,124
18,203
(752,854)
20,426,632
2013
$ million
12
9
21
5,240
51
5
(188)
5,108
5,129
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.
b Consideration received relating to the issue of new shares for employee share-based payment plans amounted to $207 million in 2014 and $116 million in 2013.
c There were no shares repurchased in 2015 (2014 shares were repurchased for a total consideration of $4,796 million, including transaction costs of $26 million and 2013 shares were repurchased for a
total consideration of $5,493 million, including transaction costs of $30 million). All shares purchased were for cancellation.
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.
Treasury sharesa
At 1 January
Purchases for settlement of employee share 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 BPb
2015
2014
2013
Shares
thousand
Nominal value
$ million
Shares
thousand
Nominal value
$ million
Shares
thousand
Nominal value
$ million
1,811,297
51,142
(106,112)
1,756,327
1,727,763
18,453
10,111
453
13
(27)
1,833,544
49,559
(71,806)
458
12
(17)
1,864,510
38,766
(69,732)
439
1,811,297
453
1,833,544
432
4
3
1,771,103
34,169
6,025
443
9
1
1,787,939
32,748
12,857
466
9
(17)
458
447
8
3
a See Note 31 for definition of treasury shares.
b Held by the group in the form of ADSs to meet the requirements of employee share-based payment plans in the US.
For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by BP during the year, representing
8.9% (2014 8.8% and 2013 8.7%) of the called-up ordinary share capital of the company.
During 2015, the movement in shares held in treasury by BP represented less than 0.2% (2014 less than 0.1% and 2013 less than 0.2%) of the
ordinary share capital of the company.
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
BP Annual Report and Form 20-F 2015
155
31. Capital and reserves
At 1 January 2015
Profit (loss) for the year
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)a
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
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
Share of items relating to equity-accounted entities, net of tax
Total comprehensive income
Dividends
Share-based payments, net of taxb
Share of equity-accounted entities’ changes in equity, net of tax
Transactions involving non-controlling interests
At 31 December 2015
At 1 January 2014
Profit (loss) for the year
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)a
Cash flow hedges (including recycling)
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
Share of items relating to equity-accounted entities, net of tax
Total comprehensive income
Dividends
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
At 31 December 2014
At 1 January 2013
Profit (loss) for the year
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
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
Share of items relating to equity-accounted entities, net of tax
Total comprehensive income
Dividends
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
At 31 December 2013
a Principally affected by a weakening of the Russian rouble compared to the US dollar.
b Includes new share issues and movements in treasury shares where these relate to employee share-based payment plans.
156
BP Annual Report and Form 20-F 2015
Share
capital
5,023
–
Share
premium
account
10,260
–
Capital
redemption
reserve
1,413
–
Total
share capital
and capital
reserves
43,902
–
Merger
reserve
27,206
–
–
–
–
–
–
–
–
–
26
–
–
–
5,049
Share
capital
5,129
–
–
–
–
–
–
–
–
41
(153)
6
–
–
5,023
Share
capital
5,261
–
–
–
–
–
–
–
–
–
51
(188)
5
–
–
5,129
–
–
–
–
–
–
–
–
(26)
–
–
–
10,234
–
–
–
–
–
–
–
–
–
–
–
–
1,413
Share
premium
account
10,061
–
Capital
redemption
reserve
1,260
–
–
–
–
–
–
–
–
(41)
–
240
–
–
10,260
–
–
–
–
–
–
–
–
153
–
–
–
1,413
Share
premium
account
9,974
–
Capital
redemption
reserve
1,072
–
–
–
–
–
–
–
–
–
(51)
–
138
–
–
10,061
–
–
–
–
–
–
–
–
–
188
–
–
–
1,260
–
–
–
–
–
–
–
–
–
–
–
–
27,206
Merger
reserve
27,206
–
–
–
–
–
–
–
–
–
–
–
–
–
27,206
Merger
reserve
27,206
–
–
–
–
–
–
–
–
–
–
–
–
–
–
27,206
–
–
–
–
–
–
–
–
–
–
–
–
43,902
Total
share capital
and capital
reserves
43,656
–
–
–
–
–
–
–
–
–
–
246
–
–
43,902
Total
share capital
and capital
reserves
43,513
–
–
–
–
–
–
–
–
–
–
–
143
–
–
43,656
Treasury
shares
(20,719)
–
–
–
–
–
–
–
–
–
–
755
–
–
(19,964)
Treasury
shares
(20,971)
–
–
–
–
–
–
–
–
–
–
252
–
–
(20,719)
Treasury
shares
(21,054)
–
–
–
–
–
–
–
–
–
–
–
83
–
–
(20,971)
Foreign
currency
translation
reserve
(3,409)
–
Available-
for-sale
investments
1
–
Cash flow
hedges
(898)
–
Total
fair value
reserves
(897)
–
Profit and
loss
account
92,564
(6,482)
BP
shareholders’
equity
111,441
(6,482)
Non-
controlling
interests
1,201
82
(3,858)
–
–
–
–
–
–
(3,858)
–
–
–
–
(7,267)
Foreign
currency
translation
reserve
3,525
–
(6,934)
–
–
–
–
–
(6,934)
–
–
–
–
–
(3,409)
Foreign
currency
translation
reserve
5,128
–
(1,603)
–
–
–
–
–
–
(1,603)
–
–
–
–
–
3,525
–
1
–
–
–
–
–
1
–
–
–
–
2
–
–
73
–
–
–
–
73
–
–
–
–
(825)
–
1
73
–
–
–
–
74
–
–
–
–
(823)
–
–
–
(814)
80
2,742
(1)
(4,475)
(6,659)
(99)
40
(3)
81,368
(3,858)
1
73
(814)
80
2,742
(1)
(8,259)
(6,659)
656
40
(3)
97,216
(41)
–
–
–
–
–
–
41
(91)
–
–
20
1,171
Available-
for-sale
investments
–
–
Cash flow
hedges
(695)
–
Total
fair value
reserves
(695)
–
Profit and
loss
account
103,787
3,780
BP
shareholders’
equity
129,302
3,780
Non-
controlling
interests
1,105
223
1
–
–
–
–
–
1
–
–
–
–
–
1
Available-
for-sale
investments
685
–
–
(685)
–
–
–
–
–
(685)
–
–
–
–
–
–
–
(203)
–
–
–
–
(203)
–
–
–
–
–
(898)
Cash flow
hedges
1,090
–
–
–
(1,785)
–
–
–
–
(1,785)
–
–
–
–
–
(695)
1
(203)
–
–
–
–
(202)
–
–
–
–
–
(897)
Total
fair value
reserves
1,775
–
–
(685)
(1,785)
–
–
–
–
(2,470)
–
–
–
–
–
(695)
–
–
(2,584)
289
(3,256)
4
(1,767)
(5,850)
(3,366)
(313)
73
–
92,564
(6,933)
(203)
(2,584)
289
(3,256)
4
(8,903)
(5,850)
(3,366)
185
73
–
111,441
(32)
–
–
–
–
–
191
(255)
–
–
–
160
1,201
Profit and
loss
account
89,184
23,451
BP
shareholders’
equity
118,546
23,451
Non-
controlling
interests
1,206
307
–
–
–
(24)
(25)
3,243
2
26,647
(5,441)
(6,923)
247
73
–
103,787
(1,603)
(685)
(1,785)
(24)
(25)
3,243
2
22,574
(5,441)
(6,923)
473
73
–
129,302
(15)
–
–
–
–
–
–
292
(469)
–
–
–
76
1,105
$ million
Total
equity
112,642
(6,400)
(3,899)
1
73
(814)
80
2,742
(1)
(8,218)
(6,750)
656
40
17
98,387
Total
equity
130,407
4,003
(6,965)
(203)
(2,584)
289
(3,256)
4
(8,712)
(6,105)
(3,366)
185
73
160
112,642
Total
equity
119,752
23,758
(1,618)
(685)
(1,785)
(24)
(25)
3,243
2
22,866
(5,910)
(6,923)
473
73
76
130,407
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
BP Annual Report and Form 20-F 2015
157
31. 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) 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 recycled to the income statement.
Available-for-sale investments
This reserve records the changes in fair value of available-for-sale investments except for impairment losses, foreign exchange gains or losses, or
changes arising from revised estimates of future cash flows. On disposal or impairment of the investments, the cumulative changes in fair value are
recycled to the income statement.
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. For
further information 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.
158
BP Annual Report and Form 20-F 2015
31. 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.
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
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
Share of items relating to equity-accounted entities, net of tax
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Cash flow hedges (including recycling)
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
Share of items relating to equity-accounted entities, net of tax
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
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
Share of items relating to equity-accounted entities, net of tax
Other comprehensive income
32. Contingent liabilities
$ million
2015
Pre-tax
Tax
Net of tax
(4,096)
1
93
(814)
–
4,139
(1)
(678)
197
–
(20)
–
80
(1,397)
–
(1,140)
(3,899)
1
73
(814)
80
2,742
(1)
(1,818)
$ million
2014
Pre-tax
Tax
Net of tax
(6,787)
(239)
(2,584)
–
(4,590)
4
(14,196)
(178)
36
–
289
1,334
–
1,481
(6,965)
(203)
(2,584)
289
(3,256)
4
(12,715)
$ million
2013
Pre-tax
Tax
Net of tax
(1,586)
(695)
(1,979)
(24)
–
4,764
2
482
(32)
10
194
–
(25)
(1,521)
–
(1,374)
(1,618)
(685)
(1,785)
(24)
(25)
3,243
2
(892)
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Contingent liabilities related to the Gulf of Mexico oil spill
Details of contingent liabilities related to the Gulf of Mexico oil spill are set out in Note 2.
Contingent liabilities not related to the Gulf of Mexico oil spill
There were contingent liabilities at 31 December 2015 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 is included in Note 28.
In the normal course of the group’s business, legal proceedings are pending or may be brought against BP group entities arising out of current and past
operations, including matters related to commercial disputes, product liability, antitrust, commodities trading, premises-liability claims, consumer
protection, general environmental claims and allegations of exposures of third parties to toxic substances, such as lead pigment in paint, asbestos and
other chemicals. BP believes that the impact of these legal proceedings on the group‘s results of operations, liquidity or financial position will not be
material.
With respect to lead pigment in paint in particular, 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. Although it is not possible to predict the outcome of the legal proceedings, Atlantic Richfield
believes it has valid defences that render the incurrence of a liability remote; however, the amounts claimed and the costs of implementing the
remedies sought in the various cases could be substantial. The majority of the lawsuits have been abandoned or dismissed against Atlantic Richfield.
No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgment in any proceeding. Atlantic
Richfield intends to defend such actions vigorously.
The group files tax returns in many jurisdictions throughout the world. Various tax authorities are currently examining the group’s tax returns. Tax
returns contain matters that could be subject to differing interpretations of applicable tax laws and regulations and the resolution of tax positions
through negotiations with relevant tax authorities, or through litigation, can take several years to complete. While it is difficult to predict the ultimate
outcome in some cases, the group does not anticipate that there will be any material impact upon the group‘s results of operations, financial position
or liquidity.
BP Annual Report and Form 20-F 2015
159
32. Contingent liabilities – continued
The group is subject to numerous national and local 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,
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 cost are inherently difficult to estimate. However, the estimated cost of known environmental obligations
has been provided in these accounts in accordance with the group‘s accounting policies. While the amounts of future costs that are not provided for
could be significant and could be 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 effect on the group’s 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. Furthermore, as described in
Provisions, contingencies and reimbursement assets within Note 1, decommissioning provisions associated with downstream and petrochemical
facilities are not generally recognized as the potential obligations cannot be measured given their indeterminate settlement dates.
The group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. Typically, losses will
therefore be borne as they arise rather than being spread over time through insurance premiums. Some risks are insured with third parties and
reinsured through group insurance companies. The position is reviewed periodically.
33. Remuneration of senior management and non-executive directors
Remuneration of directors
Total for all directors
Emoluments
Amounts awarded under incentive schemesa
Total
a Excludes amounts relating to past directors.
2015
2014
10
14
24
14
10
24
$ million
2013
16
2
18
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 2015 one executive director participated in a non-contributory defined benefit pension plan established for UK employees by a separate trust
fund to which contributions are made by BP based on actuarial advice. One executive director participated in 2015 in a US defined benefit pension plan
and retirement savings plans established for US employees.
Further information
Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 76.
Remuneration of directors and senior management
Total for senior management and non-executive directors
Short-term employee benefits
Pensions and other post-retirement benefits
Share-based payments
Total
2015
2014
33
4
36
73
34
3
34
71
$ million
2013
36
3
43
82
Senior management comprises members of the executive team, see pages 60-61 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. There was no
compensation for loss of office included in Short-term employee benefits in 2015 (2014 $1.5 million and 2013 $3 million).
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’.
160
BP Annual Report and Form 20-F 2015
34. Employee costs and numbers
Employee costs
Wages and salariesa
Social security costs
Share-based paymentsb
Pension and other post-retirement benefit costs
2015
9,556
879
833
1,660
12,928
2014
10,710
983
689
1,554
13,936
Average number of employeesc
Upstream
Downstreamd e
Other businesses and corporatee f g
US
Non-US
7,900
7,800
1,700
17,400
15,100
38,200
11,900
65,200
2015
Total
23,000
46,000
13,600
82,600
US
Non-US
9,100
8,200
1,800
19,100
15,600
39,900
10,100
65,600
2014
Total
24,700
48,100
11,900
84,700
US
Non-US
9,400
9,300
2,000
20,700
15,100
39,800
9,000
63,900
a Includes termination payments of $857 million (2014 $527 million and 2013 $212 million).
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 15,000 (2014 14,200 and 2013 14,100) service station staff.
e Around 2,000 employees from the global business services organization were reallocated from Downstream to Other businesses and corporate during 2015.
f Includes 5,600 (2014 5,100 and 2013 4,300) agricultural, operational and seasonal workers in Brazil.
g Includes employees of the Gulf Coast Restoration Organization.
$ million
2013
10,161
958
719
1,816
13,654
2013
Total
24,500
49,100
11,000
84,600
35. Auditor’s remuneration
Fees – Ernst & Young
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
Taxation compliance services
Taxation advisory services
Services relating to corporate finance transactions
Total non-audit and other assurance services
Total non-audit or non-audit-related assurance services
Services relating to BP pension plansc
2015
2014
$ million
2013
27
13
40
7
47
1
–
1
1
3
1
27
13
40
7
47
1
1
1
2
5
1
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
26
13
39
8
47
1
1
2
1
5
1
51
53
53
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 reporting on internal financial controls and non-statutory audit services.
c The pension plan services include tax compliance service of $0.4 million (2014 $0.4 million and 2013 $0.2 million)
2015 includes $2 million of additional fees for 2014 and 2014 includes $2 million of additional fees for 2013. Auditors’ remuneration is included in the
income statement within distribution and administration expenses.
The tax services relate to income tax and indirect tax compliance, employee tax services and tax advisory services.
The audit committee has established pre-approval policies and procedures for the engagement of Ernst & Young to render audit and certain assurance
and tax services. The audit fees payable to Ernst & Young are reviewed by the audit committee in the context of other global companies for cost-
effectiveness. Ernst & Young performed further assurance and tax services that were not prohibited by regulatory or other professional requirements
and were pre-approved by the Committee. Ernst & Young is engaged for these services when its expertise and experience of BP are important. Most
of this work is of an audit nature. Tax services were awarded either through a full competitive tender process or following an assessment of the
expertise of Ernst & Young compared with that of other potential service providers. These services are for a fixed term.
Under SEC regulations, the remuneration of the auditor of $51 million (2014 $53 million and 2013 $53 million) is required to be presented as follows:
audit $40 million (2014 $40 million and 2013 $39 million); other audit-related $7 million (2014 $7 million and 2013 $8 million); tax $1 million (2014
$2 million and 2013 $2 million); and all other fees $3 million (2014 $4 million and 2013 $4 million).
BP Annual Report and Form 20-F 2015
161
36. Subsidiaries, joint arrangements and associates
The more important subsidiaries and associates of the group at 31 December 2015 and the group percentage of ordinary share capital (to nearest
whole number) are set out below. There are no individually significant joint arrangements. Those 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 15 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
Algeria
%
100
100
100
100
100
100
Country of
incorporation
England & Wales
England & Wales
England & Wales
England & Wales
England & Wales
Scotland
Principal activities
Investment holding
Exploration and production
Investment holding
Integrated oil operations
Integrated oil operations
Lubricants
BP Amoco Exploration (In Amenas)
100
Scotland
Exploration and production
100
England & Wales
Exploration and production
100
100
100
100
Australia
Australia
Finance
Finance
England & Wales
England & Wales
Exploration and production
Exploration and production
100
England & Wales
Investment holding
100
England & Wales
Exploration and production
100
England & Wales
Refining and marketing
100
England & Wales
Exploration and production
70
US
Exploration and production
100
England & Wales
Finance
100
100
100
100
100
100
100
100
100
100
100
England & Wales
US
US
US
US
US
US
US
US
US
US
Country of
incorporation
%
Investment holding
Exploration and production, refining and marketing
pipelines and petrochemicals
Finance
Principal activities
20
Russia
Integrated oil operations
Angola
BP Exploration (Angola)
Australia
BP Australia Capital Markets
BP Finance Australia
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 Exploration & Production
BP Exploration (Alaska)
BP Products North America
Standard Oil Company
BP Capital Markets America
Associates
Russia
Rosneft
162
BP Annual Report and Form 20-F 2015
37. Condensed consolidating information on certain US subsidiaries
BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100%-owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe
Bay Royalty Trust. The following financial information for BP p.l.c., BP Exploration (Alaska) Inc. and all other subsidiaries on a condensed consolidating
basis is intended to provide investors with meaningful and comparable financial information about BP p.l.c. and its subsidiary issuers of registered
securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiary issuer of public debt
securities. Non-current assets for BP p.l.c. includes investments in subsidiaries recorded under the equity method for the purposes of the condensed
consolidating financial information. Equity-accounted income of subsidiaries is the group’s share of profit related to such investments. The eliminations
and reclassifications column includes the necessary amounts to eliminate the intercompany balances and transactions between BP p.l.c., BP
Exploration (Alaska) Inc. and other subsidiaries. The financial information presented in the following tables for BP Exploration (Alaska) Inc. incorporates
subsidiaries of BP Exploration (Alaska) Inc. using the equity method of accounting and excludes the BP group’s midstream operations in Alaska that are
reported through different legal entities and that are included within the ‘other subsidiaries’ column in these tables. BP p.l.c. also fully and
unconditionally guarantees securities issued by BP Capital Markets p.l.c. and BP Capital Markets America Inc. These companies are 100%-owned
finance subsidiaries of BP p.l.c.
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
Equity-accounted income of subsidiaries – 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 (income) 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
Statement of comprehensive income
For the year ended 31 December
Profit (loss) for the year
Other comprehensive income
Equity-accounted other comprehensive income of subsidiaries
Total comprehensive income
Attributable to
BP shareholders
Non-controlling interests
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
3,438
–
–
–
29
–
3,467
1,432
1,360
140
569
215
–
56
(305)
35
–
(340)
(146)
(194)
(194)
–
(194)
BP p.l.c.
–
–
–
(5,404)
185
31
(5,188)
–
–
–
–
–
–
1,125
(6,313)
36
20
(6,369)
82
(6,451)
(6,451)
–
(6,451)
Other
subsidiaries
Eliminations and
reclassifications
222,881
(28)
1,839
–
671
666
226,029
166,783
35,680
896
14,650
1,694
2,353
10,449
(6,476)
1,473
286
(8,235)
(3,107)
(5,128)
(5,210)
82
(5,128)
(3,425)
–
–
5,404
(274)
(31)
1,674
(3,425)
–
–
–
–
–
(77)
5,176
(197)
–
5,373
–
5,373
5,373
–
5,373
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
(194)
–
–
(194)
(194)
–
(194)
BP p.l.c.
(6,451)
1,863
(3,640)
(8,228)
(8,228)
–
(8,228)
Other
subsidiaries
Eliminations and
reclassifications
(5,128)
(3,681)
–
(8,809)
(8,850)
41
(8,809)
5,373
–
3,640
9,013
9,013
–
9,013
$ million
2015
BP group
222,894
(28)
1,839
–
611
666
225,982
164,790
37,040
1,036
15,219
1,909
2,353
11,553
(7,918)
1,347
306
(9,571)
(3,171)
(6,400)
(6,482)
82
(6,400)
$ million
2015
BP group
(6,400)
(1,818)
–
(8,218)
(8,259)
41
(8,218)
BP Annual Report and Form 20-F 2015
163
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
6,227
–
–
–
2
19
6,248
2,375
1,779
554
545
153
–
48
794
57
–
737
279
458
458
–
458
BP p.l.c.
–
–
–
4,531
193
–
4,724
–
–
–
–
–
–
929
3,795
23
(50)
3,822
42
3,780
3,780
–
3,780
Other
subsidiaries
Eliminations and
reclassifications
353,529
570
2,802
–
910
876
358,687
285,720
25,596
2,404
14,618
8,812
3,632
11,364
6,541
1,255
364
4,922
626
4,296
4,073
223
4,296
(6,188)
–
–
(4,531)
(262)
–
(10,981)
(6,188)
–
–
–
–
–
(75)
(4,718)
(187)
–
(4,531)
–
(4,531)
(4,531)
–
(4,531)
$ million
2014
BP group
353,568
570
2,802
–
843
895
358,678
281,907
27,375
2,958
15,163
8,965
3,632
12,266
6,412
1,148
314
4,950
947
4,003
3,780
223
4,003
$ million
2014
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
458
–
–
458
458
–
458
BP p.l.c.
3,780
Other
subsidiaries
Eliminations and
reclassifications
4,296
(4,531)
BP group
4,003
(1,840)
(10,875)
–
(12,715)
(10,843)
(8,903)
(8,903)
–
(8,903)
–
(6,579)
(6,770)
191
(6,579)
10,843
6,312
6,312
–
6,312
–
(8,712)
(8,903)
191
(8,712)
37. Condensed consolidating information on certain US subsidiaries – continued
Income statement continued
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
Equity-accounted income of subsidiaries – 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 (income) 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
Statement of comprehensive income continued
For the year ended 31 December
Profit (loss) for the year
Other comprehensive income
Equity-accounted other comprehensive income of subsidiaries
Total comprehensive income
Attributable to
BP shareholders
Non-controlling interests
164
BP Annual Report and Form 20-F 2015
37. Condensed consolidating information on certain US subsidiaries – continued
Income statement continued
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
Equity-accounted income of subsidiaries – 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 (income) 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
Statement of comprehensive income continued
For the year ended 31 December
Profit (loss) for the year
Other comprehensive income
Equity-accounted other comprehensive income of subsidiaries
Total comprehensive income
Attributable to
BP shareholders
Non-controlling interests
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
5,397
–
–
–
7
–
5,404
861
1,473
1,010
616
(68)
–
108
1,404
42
–
1,362
522
840
840
–
840
BP p.l.c.
–
–
–
24,693
118
–
24,811
–
–
–
–
–
–
1,234
23,577
43
81
23,453
2
23,451
23,451
–
23,451
Other
subsidiaries
Eliminations and
reclassifications
379,136
447
2,742
–
841
13,115
396,281
302,887
26,054
6,037
12,894
2,029
3,441
11,269
31,670
1,172
399
30,099
5,939
24,160
23,853
307
24,160
(5,397)
–
–
(24,693)
(189)
–
(30,279)
(5,397)
–
–
–
–
–
–
(24,882)
(189)
–
(24,693)
–
(24,693)
(24,693)
–
(24,693)
$ million
2013
BP group
379,136
447
2,742
–
777
13,115
396,217
298,351
27,527
7,047
13,510
1,961
3,441
12,611
31,769
1,068
480
30,221
6,463
23,758
23,451
307
23,758
$ million
2013
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
840
–
–
BP p.l.c.
23,451
2,819
(3,696)
Other
subsidiaries
Eliminations and
reclassifications
24,160
(3,711)
–
(24,693)
–
3,696
BP group
23,758
(892)
–
840
22,574
20,449
(20,997)
22,866
840
–
840
22,574
–
22,574
20,157
292
20,449
(20,997)
–
(20,997)
22,574
292
22,866
BP Annual Report and Form 20-F 2015
165
37. Condensed consolidating information on certain US subsidiaries – continued
Balance sheet
At 31 December
Non-current assets
Property, plant and equipment
Goodwill
Intangible assets
Investments in joint ventures
Investments in associates
Other investments
Subsidiaries – equity-accounted basis
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
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
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
166
BP Annual Report and Form 20-F 2015
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
BP p.l.c.
Other
subsidiaries
Eliminations and
reclassifications
$ million
2015
BP group
129,758
11,627
18,660
8,412
9,422
1,002
–
178,881
529
2,216
4,409
1,003
1,545
2,647
–
–
–
–
–
–
(128,234)
(128,234)
(6,719)
–
–
–
–
–
(134,953)
191,230
–
–
(10,850)
–
–
–
–
–
(10,850)
–
272
14,142
22,323
4,242
1,838
599
219
26,389
70,024
578
8,306
–
539
–
–
–
–
8,845
3
–
–
4
–
–
8,852
–
246
9,718
–
7
–
–
–
9,971
–
–
–
–
–
2
–
128,234
128,236
–
–
–
–
–
2,516
130,752
–
–
1,062
–
–
–
–
–
1,062
–
121,452
11,627
18,121
8,412
9,420
1,002
–
170,034
7,245
2,216
4,409
999
1,545
131
186,579
272
13,896
22,393
4,242
1,831
599
219
26,389
69,841
578
9,971
1,062
18,823
131,814
70,419
256,998
(10,850)
70,602
(145,803)
261,832
961
–
116
–
(21)
1
1,057
–
1,057
8
–
–
–
1,238
2,326
–
3,572
4,629
14,194
14,194
–
14,194
127
–
81
–
4
–
212
–
212
6,708
–
33
–
877
–
227
7,845
8,057
123,757
123,757
–
123,757
41,711
3,239
6,064
6,944
1,097
5,153
64,208
97
64,305
2,913
4,283
857
46,224
7,484
33,634
8,628
104,023
168,328
88,670
87,499
1,171
88,670
(10,850)
–
–
–
–
–
(10,850)
–
31,949
3,239
6,261
6,944
1,080
5,154
54,627
97
(10,850)
54,724
(6,719)
–
–
–
–
–
2,910
4,283
890
46,224
9,599
35,960
–
8,855
(6,719)
108,721
(17,569)
(128,234)
163,445
98,387
(128,234)
–
(128,234)
97,216
1,171
98,387
37. Condensed consolidating information on certain US subsidiaries – continued
Balance sheet continued
At 31 December
Non-current assets
Property, plant and equipment
Goodwill
Intangible assets
Investments in joint ventures
Investments in associates
Other investments
Subsidiaries – equity-accounted basis
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
Total assets
Current liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions
Non-current liabilities
Other payables
Derivative financial instruments
Accruals
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
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
BP p.l.c.a
Other
subsidiaries
Eliminations and
reclassifications
$ million
2014
BP group
130,692
11,868
20,907
8,753
10,403
1,228
–
183,851
659
4,787
4,442
964
2,309
31
–
–
–
–
–
–
(138,863)
(138,863)
(4,586)
–
–
–
–
–
(143,449)
197,043
–
–
(19,907)
–
–
–
–
–
(19,907)
333
18,373
31,038
5,165
1,424
837
329
29,763
87,262
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
–
–
–
–
2
–
138,863
138,865
–
–
–
–
–
15
138,880
–
–
7,159
–
–
–
–
31
7,190
122,905
11,868
20,434
8,753
10,401
1,228
–
175,589
5,238
4,787
4,442
954
2,309
16
193,335
333
18,035
33,463
5,165
1,393
837
329
29,732
89,287
146,070
282,622
(163,356)
284,305
168
–
391
–
–
–
559
6,871
–
90
–
–
–
599
7,560
8,119
56,644
3,689
6,577
6,877
1,683
3,817
79,287
3,594
3,199
771
45,977
12,661
27,105
10,852
104,159
183,446
99,176
97,975
1,201
99,176
(17,599)
–
–
–
–
–
(17,599)
(6,894)
–
–
–
–
–
–
(6,894)
40,118
3,689
7,102
6,877
2,011
3,818
63,615
3,587
3,199
861
45,977
13,893
29,080
11,451
108,048
(24,493)
171,663
(138,863)
112,642
(138,863)
–
111,441
1,201
(138,863)
112,642
14,378
137,951
14,378
–
14,378
137,951
–
137,951
7,787
–
473
–
–
–
–
8,260
7
–
–
10
–
–
8,277
–
338
10,323
–
31
–
–
–
10,692
18,969
905
–
134
–
328
1
1,368
16
–
–
–
1,232
1,975
–
3,223
4,591
a For 2014 BP p.l.c. comparative balances there has been a reclassification from amounts due within one year to amounts due after one year.
BP Annual Report and Form 20-F 2015
167
37. Condensed consolidating information on certain US subsidiaries – continued
Cash flow statement
For the year ended 31 December
Net cash provided by operating activities
Net cash provided by (used in) investing activities
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
For the year ended 31 December
Net cash provided by operating activities
Net cash provided by (used in) investing activities
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
For the year ended 31 December
Net cash provided by operating activities
Net cash provided by (used in) investing activities
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
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
925
(925)
–
–
–
–
–
BP p.l.c.
6,628
–
(6,659)
–
(31)
31
–
Other
subsidiaries
11,580
(16,375)
2,124
(672)
(3,343)
29,732
26,389
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
92
(92)
–
–
–
–
–
BP p.l.c.a
10,464
–
(10,439)
–
25
6
31
Other
subsidiaries
22,198
(19,482)
5,173
(671)
7,218
22,514
29,732
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
746
(746)
–
–
–
–
–
BP p.l.c.a
10,796
–
(10,799)
–
(3)
9
6
Other
subsidiaries
9,558
(7,109)
399
40
2,888
19,626
22,514
$ million
2015
BP group
19,133
(17,300)
(4,535)
(672)
(3,374)
29,763
26,389
$ million
2014
BP group
32,754
(19,574)
(5,266)
(671)
7,243
22,520
29,763
$ million
2013
BP group
21,100
(7,855)
(10,400)
40
2,885
19,635
22,520
a For 2014 and 2013 BP p.l.c. comparative information certain adjustments have been made to the amounts reported for operating, investing and financing activities, with no overall impact on net
cash flow.
168
BP Annual Report and Form 20-F 2015
Supplementary information on oil and natural gas (unaudited)a
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)
(ii)
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.
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)
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
(ii) 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 227-232.
a 2013 equity-accounted entities information includes BP’s share of TNK-BP from 1 January to 20 March, and Rosneft for the period 21 March to 31 December.
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
BP Annual Report and Form 20-F 2015
169
Oil and natural gas exploration and production activities
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
US
Russia
Rest of
Asia
$ million
2015
Total
28,474
2,740
31,214
15,967
15,247
5,177
933
6,110
2,677
3,433
215,566
19,856
235,422
126,401
109,021
Subsidiaries
Capitalized costs at 31 Decembera b
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
33,214
437
33,651
21,447
12,204
10,568
168
10,736
7,172
80,716
5,602
86,318
43,290
3,564
43,028
3,559
2,377
5,936
191
5,745
11,051
2,964
14,015
6,251
42,807
4,635
47,442
29,406
7,764
18,036
Costs incurred for the year ended 31 Decembera b
Acquisition of properties
Proved
Unproved
Exploration and appraisal costsc
Development
Total costs
17
–
17
178
1,784
1,979
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
496
1,149
1,645
115
879
(273)
(795)
949
(390)
485
1,160
(930)
2,090
–
–
–
11
73
84
209
718
927
8
313
–
92
544
131
56
187
651
3,662
4,500
651
7,427
8,078
960
2,777
215
2,460
3,671
–
–
–
75
324
399
14
2
16
108
77
–
48
13
17
974
(47)
159
340
10,423
(2,345)
(857)
(206)
(1,488)
–
246
(230)
(5)
(225)
–
(118)
(118)
114
1,299
1,295
1,594
33
1,627
51
703
214
140
673
101
259
8
267
533
2,749
3,549
1,829
4,005
5,834
1,001
1,521
–
358
3,412
846
1,882
7,138
(255)
(28)
(227)
(1,304)
694
(1,998)
–
–
–
–
–
–
–
–
5
–
5
–
–
–
5
–
–
27
–
–
32
–
–
–
102
3,439
3,541
800
4,028
4,828
53
1,083
834
76
2,420
105
4,571
(32)
(5)
(27)
257
(66)
323
–
–
–
125
128
253
407
(54)
353
1,794
13,458
15,605
1,450
340
1,790
52
166
46
215
322
140
941
849
472
377
7,043
17,702
24,745
2,353
7,519
1,036
2,621
12,004
1,159
26,692
(1,947)
(566)
(1,381)
Upstream and Rosneft segments replacement cost profit before interest and tax
Exploration and production activities –
subsidiaries (as above)
Midstream and other activities –
subsidiariesh
Equity-accounted entitiesi
Total replacement cost profit before
interest and tax
1,160
(47)
(2,345)
(230)
(255)
(1,304)
(32)
257
849
(1,947)
401
–
110
(7)
43
19
10
–
211
370
(39)
(16)
(552) 1,326
67
363
14
–
801
1,519
1,561
56
(2,283)
(220)
326
(1,895) 1,278
687
863
373
a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes our 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, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most
significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities
are located in Trinidad, Indonesia, Australia and Angola.
b Decommissioning assets 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 $120 million. The UK region includes a $832 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 $164 million which is included in finance costs in the group income statement.
g UK region includes the one-off deferred tax impact of the enactment of legislation to reduce the UK supplementary charge tax rate applicable to profits arising in the North Sea from 32% to 20%.
h Midstream and other activities excludes inventory holding gains and losses.
i BP’s share of the profits of equity-accounted entities are included after interest and tax reported by those entities.
170
BP Annual Report and Form 20-F 2015
Oil and natural gas exploration and production activities – continued
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
US
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
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
9,824
–
9,824
4,117
5,707
–
–
–
8
1,128
1,136
2,060
–
2,060
3
647
425
(381)
465
80
1,239
821
504
317
Russiaa
Rest of
Asia
12,728
437
13,165
2,788
10,377
3,486
26
3,512
3,458
54
16
26
42
123
1,702
1,867
–
8,592
8,592
52
1,083
3,911
284
992
–
6,322
2,270
449
1,821
–
–
–
1
443
444
1,022
19
1,041
–
168
388
–
484
35
1,075
(34)
1
(35)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
Upstream and Rosneft segments replacement cost profit 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 after
interest and tax
–
–
–
–
(7)
(7)
–
19
19
–
–
–
317
–
1,821
(35)
53
(552)
(495)
398
370
(552)
1,326
363
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
$ million
2015
Total
26,038
463
26,501
10,363
16,138
16
26
42
132
3,273
3,447
3,082
8,611
11,693
55
1,898
4,724
(97)
1,941
115
8,636
3,057
954
2,103
2,103
(584)
1,519
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
a Amounts reported for Russia 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 and transportation operations as well as downstream activities of Rosneft are excluded. The amounts reported for equity-accounted entities exclude the
corresponding amounts for their equity-accounted entities.
c Decommissioning assets 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 transportation costs and sales taxes.
g Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
BP Annual Report and Form 20-F 2015
171
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
Africa
Asia
Australasia
$ million
2014
Total
Russia
Rest of
Asia
Subsidiaries
Capitalized costs at 31 Decembera b
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
31,496
395
31,891
21,068
10,823
10,578
165
10,743
6,610
76,476
6,294
82,770
39,383
4,133
43,387
3,205
2,454
5,659
190
5,469
9,796
2,984
12,780
5,482
39,020
5,769
44,789
25,105
7,298
19,684
Costs incurred for the year ended 31 Decembera b
Acquisition of properties
Proved
Unproved
Exploration and appraisal costsc
Development
Total costs
42
–
42
279
2,067
2,388
–
–
–
16
293
309
6
346
352
888
4,792
6,032
Results of operations for the year ended 31 Decembera d
Sales and other operating revenuese
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)f
Depreciation, depletion and
amortization
Net impairments and (gains) losses on
sale of businesses and fixed assets
Profit (loss) before taxationg
Allocable taxes
Results of operations
529
1,069
1,598
94
979
(234)
(1,515)
77
1,662
1,739
47
436
–
77
1,218
14,894
16,112
1,294
3,492
690
3,260
506
676
3,805
2,537
2,367
(769)
(1,383)
614
2,278
3,514
(1,775)
(1,108)
(667)
(28)
12,513
3,599
1,269
2,330
–
–
–
109
706
815
4
15
19
63
34
–
55
4
–
156
(137)
15
(152)
–
75
75
325
983
1,383
2,802
450
3,252
502
783
175
284
–
57
57
899
2,881
3,837
2,536
6,289
8,825
860
1,542
–
120
678
3,343
11
2,433
819
865
(46)
1,128
6,993
1,832
1,216
616
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
57
–
–
57
(57)
3
(60)
24,177
2,773
26,950
13,501
13,449
5,061
888
5,949
2,215
3,734
199,809
21,722
221,531
113,554
107,977
557
–
557
194
3,205
3,956
1,135
6,951
8,086
712
1,289
2,234
(69)
2,461
391
7,018
1,068
67
1,001
–
–
–
201
169
370
2,574
624
3,198
60
232
93
343
605
478
1,083
2,911
15,096
19,090
10,875
31,954
42,829
3,632
8,787
2,958
2,612
255
11,728
–
6,317
983
36,034
2,215
1,161
1,054
6,795
2,105
4,690
Upstream and Rosneft segments replacement cost profit before interest and tax
Exploration and production activities –
subsidiaries (as above)
Midstream and other activities –
subsidiariesh
Equity-accounted entitiesi
Total replacement cost profit before
interest and tax
(769)
(1,775)
3,599
(137)
819
1,832
(57)
1,068
2,215
6,795
163
–
99
62
703
23
130
–
175
480
(170)
(33)
(26)
2,125
(63)
557
14
–
1,025
3,214
(606)
(1,614)
4,325
(7)
1,474
1,629
2,042
1,562
2,229
11,034
a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes our 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, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most
significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the
Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia, Australia and Angola.
b Decommissioning assets 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 Amendments have been made to previously published amounts for the Australasia region with no overall effect on total replacement cost profit before interest and tax.
e Presented net of transportation costs, purchases and sales taxes.
f Includes property taxes, other government take and the fair value gain on embedded derivatives of $430 million. The UK region includes a $1,016 million gain which is offset by corresponding charges,
primarily in the US region, relating to the group self-insurance programme.
g Excludes the unwinding of the discount on provisions and payables amounting to $207 million which is included in finance costs in the group income statement.
h Midstream and other activities excludes inventory holding gains and losses.
i BP’s share of the profits of equity-accounted entities are included after interest and tax reported by those entities.
172
BP Annual Report and Form 20-F 2015
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
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 c
Acquisition of propertiesd
Proved
Unproved
Exploration and appraisal costse
Developmentf
Total costs
–
–
–
–
–
–
Results of operations for the year ended 31 Decemberb
Sales and other operating revenuesg
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
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
8,719
5
8,724
3,652
5,072
–
–
–
5
1,026
1,031
2,472
–
2,472
4
567
721
4
370
25
1,691
781
402
379
Africa
Asia
Australasia
Russiaa
Rest of
Asia
12,971
376
13,347
2,031
11,316
3,073
25
3,098
2,986
112
(46)
87
41
128
1,913
2,082
–
–
–
4
326
330
–
10,972
10,972
1,257
19
1,276
62
1,318
5,214
302
1,509
–
8,405
2,567
637
1,930
1
152
692
–
371
–
1,216
60
29
31
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
Upstream and Rosneft segments replacement cost profit 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 after
interest and tax
–
–
–
–
62
62
–
23
23
–
–
–
379
101
480
–
1,930
31
(33)
195
526
(33)
2,125
557
$ million
2014
Total
24,763
406
25,169
8,669
16,500
(46)
87
41
137
3,265
3,443
3,729
10,991
14,720
67
2,037
6,627
306
2,250
25
11,312
3,408
1,068
2,340
2,340
874
3,214
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
a Amounts reported for Russia 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 and transportation operations as well as downstream activities of Rosneft are excluded. The amounts reported for equity-accounted entities exclude the
corresponding amounts for their equity-accounted entities.
c 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.
d Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
e 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.
f An amendment has been made to the amount previously disclosed for the Rest of Asia region.
g Presented net of transportation costs and sales taxes.
h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
BP Annual Report and Form 20-F 2015
173
Africa
Asia
Australasia
$ million
2013
Total
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
Subsidiaries
Capitalized costs at 31 Decembera b
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
29,314
316
29,630
18,707
10,923
10,040
195
10,235
3,650
75,313
6,816
82,129
38,236
6,585
43,893
2,501
2,408
4,909
193
4,716
8,809
3,366
12,175
5,063
35,720
5,079
40,799
20,082
7,112
20,717
Costs incurred for the year ended 31 Decembera b
Acquisition of properties
Proved
Unproved
Exploration and appraisal costsc
Development
Total costs
–
–
–
178
1,942
2,120
–
–
–
14
455
469
1
158
159
1,291
4,877
6,327
Results of operations for the year ended 31 Decemberd
Sales and other operating revenuese
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)f
Depreciation, depletion and
amortization
Net impairments and (gains) losses on
sale of businesses and fixed assets
Profit (loss) before taxationg
Allocable taxes
Results of operations
1,129
1,661
2,790
280
1,102
(35)
(1,731)
504
118
238
2,552
554
1,998
183
1,280
1,463
17
430
–
86
934
14,047
14,981
437
3,691
1,112
3,241
490
3,268
15
(80)
1,038
11,669
425
475
(50)
3,312
1,204
2,108
–
–
–
194
569
763
5
12
17
28
42
–
55
–
–
125
(108)
(26)
(82)
7
284
291
951
683
1,925
2,413
1,154
3,567
1,477
892
184
322
–
30
30
883
2,755
3,668
3,195
6,518
9,713
387
1,623
–
89
559
3,132
129
3,563
4
642
(638)
29
5,260
4,453
1,925
2,528
Russia
Rest of
Asia
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
65
–
–
65
(65)
(2)
(63)
20,726
2,756
23,482
10,069
13,413
–
7
7
1,090
2,082
3,179
1,005
11,432
12,437
768
1,091
5,660
84
2,174
(16)
9,761
2,676
682
1,994
4,681
805
5,486
1,962
3,524
187,104
21,741
208,845
97,962
110,883
–
–
–
210
189
399
2,466
639
3,105
47
187
126
394
8
479
487
4,811
13,552
18,850
11,330
36,743
48,073
3,441
9,058
7,047
2,605
207
10,334
230
1,191
1,914
845
1,069
425
32,910
15,163
6,299
8,864
Upstream, Rosneft and TNK-BP segments replacement cost profit before interest and taxd
Exploration and production activities –
subsidiaries (as above)
Midstream and other activities –
subsidiariesh
TNK-BP gain on sale
Equity-accounted entitiesi
Total replacement cost profit before
interest and tax
2,552
425
3,312
(108)
4
4,453
(65)
2,676
1,914
15,163
244
–
–
(40)
–
28
296
–
17
(14)
–
–
153
–
405
(154)
–
24
(4)
12,500
2,158
(29)
–
553
10
–
–
462
12,500
3,185
2,796
413
3,625
(122)
562
4,323
14,589
3,200
1,924
31,310
a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes our 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, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most
significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the
Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia, Australia and Angola.
b Decommissioning assets 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 Amendments have been made to previously published amounts for the Australasia region with no overall effect on total replacement cost before interest and tax.
e Presented net of transportation costs, purchases and sales taxes.
f Includes property taxes, other government take and the fair value gain on embedded derivatives of $459 million. The UK region includes a $1,055 million gain which is offset by corresponding charges,
primarily in the US region, relating to the group self-insurance programme.
g Excludes the unwinding of the discount on provisions and payables amounting to $141 million which is included in finance costs in the group income statement.
h Midstream and other activities excludes inventory holding gains and losses.
i BP’s share of the profits of equity-accounted entities are included after interest and tax reported by those entities.
174
BP Annual Report and Form 20-F 2015
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
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 c d
Acquisition of properties
Proved
Unproved
Exploration and appraisal costse
Developmentf
Total costs
–
–
–
–
–
–
Results of operations for the year ended 31 Decemberb f
Sales and other operating revenuesg
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
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
7,648
29
7,677
3,282
4,395
–
–
–
8
714
722
2,294
–
2,294
–
586
630
6
317
–
1,539
755
460
295
Africa
Asia
Australasia
Russiaa
Rest of
Asia
18,942
638
19,580
1,077
18,503
4,239
21
4,260
4,061
199
1,816
657
2,473
133
1,860
4,466
–
–
–
12
423
435
435
9,679
10,114
126
1,177
4,511
94
4,591
14
4,605
1
382
3,383
–
1,232
648
37
7,177
2,937
367
2,570
–
4,414
191
40
151
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
Upstream, Rosneft and TNK-BP segments replacement cost profit 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 after
interest and tax
–
–
–
–
28
28
–
17
17
–
–
–
295
110
405
–
2,570
151
24
(412)
402
24
2,158
553
$ million
2013
Total
30,829
688
31,517
8,420
23,097
1,816
657
2,473
153
2,997
5,623
7,320
9,693
17,013
127
2,145
8,524
100
2,197
37
13,130
3,883
867
3,016
3,016
169
3,185
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
a Amounts reported for Russia 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. They do not include amounts relating to assets held for sale. Amounts
relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations as well as downstream activities of TNK-BP and Rosneft are excluded.
The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities.
c Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
d 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.
e 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.
f Amendments have been made to previously published numbers for the Rest of Asia region. The amendments have no overall effect on results of operations.
g Presented net of transportation costs and sales taxes.
h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
BP Annual Report and Form 20-F 2015
175
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
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
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
Rest of
North
America
USc
Russia
Rest of
Asia
million barrels
2015
Total
159
329
488
(23)
–
1
–
(27)
(1)
(48)
141
298
440
–
–
–
–
–
–
–
–
–
–
–
–
–
95
22
117
1,030
664
1,694
9
163
172
2
–
–
–
(14)
–
(12)
86
19
(130)
15
–
3
(115)
–
(227)
890
577
106
1,467
39
–
–
42
(1)
–
80
46
205
252
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1
–
–
–
–
–
–
–
–
–
–
95
22
117
86
19
1,030
664
1,694
890
577
106
1,467
9
164
173
47
205
252
10
22
32
(2)
–
–
–
(5)
–
(6)
8
18
26
316
314
630
9
3
–
9
(28)
–
(8)
311
311
622
326
336
662
319
329
648
317
120
437
80
2
6
2
(98)
–
(8)
340
89
429
2
–
2
–
–
–
–
–
–
–
2
–
2
319
120
439
342
89
431
–
–
–
–
–
–
–
–
–
–
–
–
–
2,997
1,933
4,930
(23)
–
28
185
(295)
(1)
(105)
2,844
1,981
4,825
2,997
1,933
4,930
2,844
1,981
4,825
384
197
581
295
–
–
–
(87)
–
208
598
192
790
89
11
101
3
–
–
–
(35)
–
(32)
68
–
68
473
208
682
666
192
858
40
19
59
(2)
–
–
–
(6)
–
(8)
35
16
51
–
–
–
–
–
–
–
–
–
–
–
–
–
40
19
59
35
16
51
2,044
1,538
3,582
260
18
7
47
(353)
(1)
(21)
2,146
1,414
3,560
3,405
2,258
5,663
(11)
3
28
194
(358)
(1)
(146)
3,225
2,292
5,517
5,448
3,796
9,244
5,371
3,707
9,078
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
159
329
At 31 December
Developed
Undeveloped
488
141
298
440
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 23 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 8 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 70 million barrels of crude oil in respect of the 1.27% non-controlling interest in Rosneft, including 28 mmbbl held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha.
g Total proved crude oil reserves held as part of our equity interest in Rosneft is 4,823 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 26 million barrels in Venezuela and
4,797 million barrels in Russia.
176
BP Annual Report and Form 20-F 2015
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
Developed
Undeveloped
6
3
9
2
–
–
–
(2)
–
–
5
4
10
–
–
–
–
–
–
–
–
–
–
–
–
–
Europe
North
America
South
America
Africa
Asia
Australasia
million barrels
2015
Total
UK
Rest of
Europe
Rest of
North
America
Russia
Rest of
Asia
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
11
28
39
–
–
–
–
(4)
–
(4)
7
28
35
–
–
–
–
–
–
–
–
–
–
–
–
–
11
28
39
7
28
35
5
7
12
6
–
–
–
(3)
–
3
5
10
15
15
–
15
(3)
–
–
–
–
–
(3)
13
–
13
20
7
27
18
10
28
–
–
–
–
–
–
–
–
–
–
–
–
–
30
16
46
1
–
–
–
–
–
1
32
15
47
30
16
46
32
15
47
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
US
323
104
427
(80)
12
3
–
(23)
(1)
(88)
269
70
339
–
–
–
–
–
–
–
–
–
–
–
–
–
323
104
427
269
70
339
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
6
3
10
3
–
–
–
(1)
–
2
9
2
12
–
–
–
–
–
–
–
–
–
–
–
–
–
6
3
10
9
2
12
364
146
510
(69)
12
4
–
(34)
(1)
(88)
308
115
422
46
16
62
(2)
–
–
–
–
–
(2)
45
15
60
410
163
572
352
130
482
13
1
14
–
–
–
–
(2)
–
(2)
11
1
12
–
–
–
–
–
–
–
–
–
–
–
–
–
13
1
14
11
1
12
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
6
3
At 31 December
Developed
Undeveloped
9
5
4
10
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 4 thousand barrels per day for equity-accounted entities.
d Includes 11 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 Total proved NGL reserves held as part of our equity interest in Rosneft is 47 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 47 million barrels in Russia.
BP Annual Report and Form 20-F 2015
177
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
UK
Rest of
Europe
Rest of
North
America
USc
Russia
Rest of
Asia
million barrels
2015
Total
166
332
497
(20)
–
1
–
(29)
(1)
(48)
147
302
449
–
–
–
–
–
–
–
–
–
–
–
–
–
108
23
131
2
–
–
–
(16)
–
(14)
98
20
117
1,352
769
2,121
9
163
172
(210)
28
3
4
(138)
(1)
(315)
39
–
–
42
(1)
–
80
1,159
647
1,806
46
205
252
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1
–
–
–
–
–
–
(1)
–
–
–
108
23
131
98
20
117
1,352
769
2,121
1,159
647
1,806
9
164
173
47
205
252
21
50
71
(2)
–
–
–
(8)
–
(10)
15
46
61
316
314
630
9
3
–
9
(28)
–
(8)
311
312
622
337
364
701
326
357
684
322
127
449
86
2
6
2
(101)
–
(5)
346
99
444
17
–
17
(3)
–
–
–
–
–
(3)
14
–
14
339
127
466
360
99
459
–
–
–
–
–
–
–
–
–
–
–
–
–
3,028
1,949
4,976
(22)
–
28
185
(295)
(1)
(104)
2,876
1,996
4,872
3,028
1,949
4,976
2,876
1,996
4,872
384
197
581
295
–
–
–
(87)
–
208
598
192
790
89
11
101
3
–
–
–
(35)
–
(32)
68
–
68
473
208
682
666
192
858
46
22
68
1
–
–
–
(7)
–
(6)
45
18
63
–
–
–
–
–
–
–
–
–
–
–
–
–
46
22
68
45
18
63
2,407
1,684
4,092
191
30
11
48
(387)
(2)
(109)
2,453
1,529
3,982
3,451
2,274
5,725
(13)
3
28
194
(358)
(1)
(147)
3,270
2,307
5,577
5,858
3,958
9,817
5,723
3,836
9,560
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
166
332
At 31 December
Developed
Undeveloped
497
147
302
449
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 23 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 4 thousand barrels per day for equity-accounted entities.
e Also includes 19 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 70 million barrels in respect of the non-controlling interest in Rosneft, including 28 mmboe held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha.
h Total proved liquid reserves held as part of our equity interest in Rosneft is 4,871 million barrels, comprising less than 1 million barrels in Canada, 26 million barrels in Venezuela, less than 1 million
barrels in Vietnam and 4,844 million barrels in Russia.
178
BP Annual Report and Form 20-F 2015
Movements in estimated net proved reserves – continued
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
Rest of
North
America
US
Russia
Rest of
Asia
billion cubic feet
2015
Total
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
2,352
6,313
8,666
901
1,597
2,497
132
–
29
–
(709)
(58)
(605)
203
7
554
174
(248)
(35)
654
2,071
5,989
8,060
847
2,305
3,152
–
–
–
–
–
–
–
–
–
–
–
–
–
1,228
717
1,945
81
8
–
209
(182)
(1)
116
400
–
400
(14)
–
–
–
–
–
(14)
4,674
5,111
9,785
1,604
–
5
175
(430)
–
1,354
1,463
598
2,061
386
–
386
4,962
6,176
11,139
1,688
3,892
5,580
(165)
–
–
–
(157)
–
(322)
1,803
3,455
5,257
60
9
69
(2)
–
–
–
(19)
–
(21)
44
4
48
382
386
768
(12)
4
–
–
(65)
(5)
(77)
348
343
691
–
–
–
–
–
–
–
–
–
–
–
–
–
300
19
318
14
–
–
–
(44)
–
(30)
274
14
288
7,168
2,447
9,615
(1,120)
432
65
5
(628)
(6)
(1,252)
6,257
2,105
8,363
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
300
19
318
274
14
288
7,168
2,447
9,615
6,257
2,105
8,363
17
–
17
(13)
–
–
–
(4)
–
(17)
–
–
–
1
1
1
(1)
–
–
–
–
–
(1)
1
–
1
18
1
18
1
–
1
3,316
1,719
5,035
16,124
16,372
32,496
13
–
–
–
(297)
–
(284)
(948)
443
648
179
(2,151)
(104)
(1,933)
3,408
1,343
4,751
15,009
15,553
30,563
–
–
–
–
–
–
–
–
–
–
–
–
–
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
6,363
5,837
12,200
1,669
8
5
384
(632)
(1)
1,434
6,856
6,778
13,634
22,487
22,209
44,695
21,865
22,331
44,197
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
382
386
At 31 December
Developed
Undeveloped
768
348
343
691
3,581
7,030
10,610
3,534
6,587
10,121
1,301
1,597
2,897
1,233
2,305
3,538
4,674
5,111
9,785
4,962
6,176
11,139
1,748
3,901
5,648
1,847
3,459
5,305
3,316
1,719
5,035
3,408
1,343
4,751
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 175 billion cubic feet of natural gas consumed in operations, 146 billion cubic feet in subsidiaries, 29 billion cubic feet in equity-accounted entities.
d Includes 2,359 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 129 billion cubic feet of natural gas in respect of the 0.23% non-controlling interest in Rosneft including 5 billion cubic feet held through BP’s equity-accounted interest in Taas-Yuryakh
Neftegazodobycha.
g Total proved gas reserves held as part of our equity interest in Rosneft is 11,169 billion cubic feet, comprising 1 billion cubic feet in Canada, 13 billion cubic feet in Venezuela, 22 billion cubic feet in
Vietnam and 11,133 billion cubic feet in Russia.
BP Annual Report and Form 20-F 2015
179
Movements in estimated net proved reserves – continued
million barrels of oil equivalentc
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
Rest of
North
America
USd
Russia
Rest of
Asia
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
Productionf
Sales of reserves-in-place
At 31 Decemberi j
Developed
Undeveloped
232
398
630
(22)
1
1
–
(40)
(1)
(62)
207
362
568
–
–
–
–
–
–
–
–
–
–
–
–
–
160
26
186
4
–
–
–
(23)
–
(19)
145
22
167
2,588
1,191
3,779
12
163
175
426
1,139
1,565
(403)
102
15
4
(247)
(2)
(531)
36
–
–
42
(2)
–
77
21
–
5
–
(130)
(10)
(114)
2,238
1,010
3,248
46
205
252
373
1,078
1,451
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1
1
(1)
–
–
–
–
–
(1)
–
–
–
528
438
965
23
5
–
45
(60)
–
12
563
415
978
477
403
880
121
3
102
32
(144)
(6)
108
492
496
988
86
–
86
(5)
–
–
–
–
–
(5)
81
–
81
160
26
186
145
22
167
2,588
1,191
3,779
2,238
1,010
3,248
12
164
176
47
205
252
954
1,576
2,530
936
1,493
2,429
563
403
966
573
496
1,069
–
–
–
–
–
–
–
–
–
–
–
–
–
3,834
2,830
6,663
255
–
29
215
(369)
(1)
129
3,732
3,061
6,792
3,834
2,830
6,663
3,732
3,061
6,792
675
868
1,543
267
–
–
–
(114)
–
153
909
788
1,696
100
13
112
3
–
–
–
(39)
–
(36)
76
1
77
775
881
1,656
984
788
1,773
2015
Total
5,187
4,507
9,695
27
106
122
79
(758)
(19)
(443)
5,041
4,211
9,252
4,548
3,280
7,828
274
5
29
260
(467)
(1)
100
4,452
3,476
7,928
618
319
937
4
–
–
–
(58)
–
(55)
632
250
882
–
–
–
–
–
–
–
–
–
–
–
–
–
618
319
937
632
250
882
9,735
7,788
17,523
9,493
7,687
17,180
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
232
398
At 31 December
Developed
Undeveloped
630
207
362
568
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 23 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 4 thousand barrels per day for equity-accounted entities.
f Includes 30 million barrels of oil equivalent of natural gas consumed in operations, 25 million barrels of oil equivalent in subsidiaries, 5 million barrels of oil equivalent in equity-accounted entities.
g Includes 425 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 70 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 28 mmboe held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha.
j Total proved reserves held as part of our equity interest in Rosneft is 6,796 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 28 million barrels of oil
equivalent in Venezuela, 4 million barrels of oil equivalent in Vietnam and 6,764 million barrels of oil equivalent in Russia.
180
BP Annual Report and Form 20-F 2015
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
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
Developed
Undeveloped
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
USc
South
America
Africa
Asia
Australasia
million barrels
2014
Total
Russia
Rest of
Asia
160
374
534
(41)
2
5
5
(17)
–
(46)
159
329
488
–
–
–
–
–
–
–
–
–
–
–
–
–
147
53
200
(68)
–
–
–
(15)
–
(82)
95
22
117
1,007
752
1,760
87
16
–
–
(123)
(45)
(66)
1,030
664
1,694
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
188
188
(16)
–
–
–
–
–
(16)
9
163
172
–
1
1
–
–
–
–
–
–
–
–
–
1
147
53
200
95
22
117
1,007
752
1,760
1,030
664
1,694
–
189
189
9
164
173
15
17
31
9
1
–
1
(5)
(5)
1
10
22
32
316
314
630
4
12
–
10
(26)
–
–
316
314
630
331
331
661
326
336
662
316
180
495
20
3
–
–
(81)
–
(58)
317
120
437
2
2
4
(2)
–
–
–
–
–
(2)
2
–
2
317
182
499
319
120
439
–
–
–
–
–
–
–
–
–
–
–
–
–
2,970
1,858
4,828
213
–
–
187
(297)
–
103
2,997
1,933
4,930
2,970
1,858
4,828
2,997
1,933
4,930
320
202
522
96
–
12
8
(57)
–
59
384
197
581
120
7
127
9
–
–
–
(36)
–
(27)
89
11
101
440
209
649
473
208
682
49
19
69
(2)
–
–
–
(7)
–
(9)
40
19
59
–
–
–
–
–
–
–
–
–
–
–
–
–
49
19
69
40
19
59
2,013
1,785
3,798
85
23
17
13
(305)
(50)
(217)
2,044
1,538
3,581
3,407
2,182
5,590
224
12
–
197
(359)
–
74
3,405
2,258
5,663
5,421
3,965
9,388
5,448
3,796
9,244
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
160
374
At 31 December
Developed
Undeveloped
534
159
329
488
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 65 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 10 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 38 million barrels of crude oil in respect of the 0.15% non-controlling interest in Rosneft.
g Total proved crude oil reserves held as part of our equity interest in Rosneft is 4,961 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 30 million barrels in Venezuela and
4,930 million barrels in Russia.
BP Annual Report and Form 20-F 2015
181
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
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
million barrels
2014
Total
UK
9
6
15
(6)
–
–
–
(1)
–
(6)
6
3
9
–
–
–
–
–
–
–
–
–
–
–
–
–
Rest of
Europe
16
2
18
(2)
–
–
–
(2)
–
(4)
13
1
14
–
–
–
–
–
–
–
–
–
–
–
–
–
16
2
18
13
1
14
Rest of
North
America
Russia
Rest of
Asia
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
14
28
43
–
–
–
–
(4)
–
(4)
11
28
39
–
–
–
–
–
–
–
–
–
–
–
–
–
14
28
43
11
28
39
4
15
20
(6)
–
–
–
(2)
–
(8)
5
7
12
8
8
16
–
–
–
–
–
–
(1)
15
–
15
13
23
36
20
7
27
–
–
–
–
–
–
–
–
–
–
–
–
–
94
21
115
(69)
–
–
–
–
–
(69)
30
16
46
94
21
115
30
16
46
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
US
290
155
444
15
13
–
–
(27)
(18)
(17)
323
104
427
–
–
–
–
–
–
–
–
–
–
–
–
–
290
155
444
323
104
427
8
3
10
–
–
–
–
(1)
–
(1)
6
3
10
–
–
–
–
–
–
–
–
–
–
–
–
–
8
3
10
6
3
10
342
209
551
1
13
1
–
(36)
(18)
(40)
364
146
510
103
29
131
(69)
–
–
–
–
–
(69)
46
16
62
444
238
682
410
163
572
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
9
6
At 31 December
Developed
Undeveloped
15
6
3
9
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 7 thousand barrels per day for equity-accounted entities.
d Includes 12 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 Total proved NGL reserves held as part of our equity interest in Rosneft is 47 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 46 million barrels in Russia.
182
BP Annual Report and Form 20-F 2015
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
UK
Rest of
Europe
Rest of
North
America
USc
Russia
Rest of
Asia
169
380
549
(47)
2
5
5
(17)
–
(52)
166
332
497
–
–
–
–
–
–
–
–
–
–
–
–
–
163
55
217
1,297
907
2,204
(70)
–
–
–
(17)
–
(86)
101
28
–
–
(150)
(63)
(83)
108
23
131
1,352
769
2,121
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
188
188
(16)
–
–
–
–
–
(16)
9
163
172
–
1
1
–
–
–
–
–
–
–
–
–
1
163
55
217
108
23
131
1,297
907
2,204
1,352
769
2,121
–
188
189
9
164
173
29
46
74
9
1
–
1
(9)
(5)
(3)
21
50
71
316
314
630
4
12
–
10
(26)
–
–
316
314
630
345
359
704
337
364
701
320
195
515
14
3
–
–
(83)
–
(66)
322
127
449
–
–
–
–
–
–
–
–
–
–
–
–
–
10
10
20
3,063
1,879
4,943
(3)
–
–
–
–
–
(3)
144
–
–
187
(297)
–
34
17
–
17
3,028
1,949
4,976
331
205
535
339
127
466
3,063
1,879
4,943
3,028
1,949
4,976
320
202
523
96
–
12
8
(57)
–
59
384
197
581
120
7
127
9
–
–
–
(36)
–
(27)
89
11
101
440
209
650
473
208
682
57
22
78
(2)
–
–
–
(8)
–
(10)
46
22
68
–
–
–
–
–
–
–
–
–
–
–
–
–
57
22
78
46
22
68
million barrels
2014
Total
2,354
1,994
4,348
86
36
18
14
(341)
(68)
(257)
2,407
1,684
4,092
3,510
2,210
5,721
155
12
–
197
(359)
–
4
3,451
2,274
5,725
5,865
4,204
10,069
5,858
3,958
9,817
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
169
380
At 31 December
Developed
Undeveloped
549
166
332
497
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 65 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 7 thousand barrels per day for equity-accounted entities.
e Also includes 21 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 38 million barrels in respect of the non-controlling interest in Rosneft.
h Total proved liquid reserves held as part of our equity interest in Rosneft is 5,007 million barrels, comprising 1 million barrels in Canada, 30 million barrels in Venezuela, less than 1 million barrels in
Vietnam and 4,976 million barrels in Russia.
BP Annual Report and Form 20-F 2015
183
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
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
US
Russia
Rest of
Asia
billion cubic feet
2014
Total
643
314
957
(260)
7
1
94
(30)
–
(189)
382
386
768
–
–
–
–
–
–
–
–
–
–
–
–
–
364
39
403
7,122
2,825
9,947
(46)
–
–
–
(40)
–
(85)
(29)
582
5
2
(625)
(266)
(332)
300
19
318
7,168
2,447
9,615
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
364
39
403
300
19
318
7,122
2,825
9,947
7,168
2,447
9,615
10
–
10
11
–
–
–
(4)
–
7
17
–
17
–
1
1
1
–
–
–
–
–
–
1
1
1
10
1
11
18
1
18
3,109
6,116
9,225
961
1,807
2,768
(258)
220
–
271
(792)
–
(559)
(84)
28
–
4
(218)
–
(271)
2,352
6,313
8,666
901
1,597
2,497
–
–
–
–
–
–
–
–
–
–
–
–
–
1,519
3,671
5,190
(34)
–
322
267
(165)
–
389
1,688
3,892
5,580
1,364
747
2,111
230
135
365
4,171
5,054
9,225
(87)
23
–
69
(172)
–
(166)
38
–
–
–
(3)
–
35
767
–
–
183
(390)
–
560
1,228
717
1,945
400
–
400
4,674
5,111
9,785
72
14
86
1
–
–
–
(18)
–
(17)
60
9
69
3,932
1,755
5,687
(351)
–
–
–
(302)
–
(652)
3,316
1,719
5,035
–
–
–
–
–
–
–
–
–
–
–
–
–
4,473
6,863
11,336
3,581
7,030
10,610
1,191
1,942
3,133
1,301
1,597
2,897
4,171
5,054
9,225
4,674
5,111
9,785
1,591
3,685
5,276
1,748
3,901
5,648
3,932
1,755
5,687
3,316
1,719
5,035
17,660
16,527
34,187
(1,050)
838
328
637
(2,177)
(266)
(1,691)
16,124
16,372
32,496
5,837
5,951
11,788
720
23
–
252
(583)
–
412
6,363
5,837
12,200
23,497
22,478
45,975
22,487
22,209
44,695
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
643
314
At 31 December
Developed
Undeveloped
957
382
386
768
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, 151 billion cubic feet in subsidiaries, 29 billion cubic feet in equity-accounted entities.
d Includes 2,519 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 91 billion cubic feet of natural gas in respect of the 0.18% non-controlling interest in Rosneft.
g Total proved gas reserves held as part of our equity interest in Rosneft is 9,827 billion cubic feet, comprising 1 billion cubic feet in Canada, 14 billion cubic feet in Venezuela, 26 billion cubic feet in
Vietnam and 9,785 billion cubic feet in Russia.
184
BP Annual Report and Form 20-F 2015
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
Productionf
Sales of reserves-in-place
At 31 Decemberi j
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
Rest of
North
America
USd
Russia
Rest of
Asia
2014
Total
million barrels of oil equivalentc
280
434
714
(91)
3
6
21
(23)
–
(84)
232
398
630
–
–
–
–
–
–
–
–
–
–
–
–
–
225
62
287
2,525
1,394
3,919
(78)
–
–
–
(24)
–
(101)
96
129
1
1
(258)
(109)
(140)
160
26
186
2,588
1,191
3,779
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
2
188
190
(14)
–
–
–
(1)
–
(14)
12
163
175
–
1
1
–
–
–
–
–
–
–
–
1
1
564
1,100
1,664
(36)
39
–
47
(146)
(5)
(99)
426
1,139
1,565
552
442
994
(11)
16
–
22
(56)
–
(29)
528
438
965
486
507
993
(1)
8
–
1
(121)
–
(113)
477
403
880
–
–
–
–
–
–
–
–
–
–
–
–
–
50
33
83
3,782
2,751
6,533
4
–
–
–
(1)
–
3
276
–
–
219
(365)
–
130
86
–
86
3,834
2,830
6,663
582
835
1,417
90
–
68
54
(86)
–
126
675
868
1,543
133
9
142
9
–
–
–
(39)
–
(29)
100
13
112
735
324
5,399
4,844
1,059
10,243
(62)
–
–
–
(60)
–
(122)
618
319
937
–
–
–
–
–
–
–
–
–
–
–
–
–
(96)
180
74
123
(717)
(114)
(548)
5,187
4,507
9,694
4,517
3,236
7,753
278
16
–
241
(460)
–
75
4,548
3,280
7,828
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
280
434
At 31 December
Developed
Undeveloped
714
232
398
630
225
62
287
160
26
186
2,525
1,394
3,919
2,588
1,191
3,779
2
189
191
12
164
176
1,116
1,542
2,658
954
1,576
2,530
536
540
1,076
563
403
966
3,782
2,751
6,533
3,834
2,830
6,663
715
844
1,559
775
881
1,656
735
324
9,916
8,080
1,059
17,996
618
319
937
9,735
7,788
17,523
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 65 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 7 thousand barrels per day for equity-accounted entities.
f Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 26 million barrels of oil equivalent in subsidiaries, 5 million barrels of oil equivalent in equity-accounted entities.
g Includes 456 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 54 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft.
j Total proved reserves held as part of our equity interest in Rosneft is 6,702 million barrels of oil equivalent, comprising 1 million barrels of oil equivalent in Canada, 33 million barrels of oil equivalent in
Venezuela, 5 million barrels of oil equivalent in Vietnam and 6,663 million barrels of oil equivalent in Russia.
BP Annual Report and Form 20-F 2015
185
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
Developed
Undeveloped
Equity-accounted entities (BP share)e 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
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
USc
Russia
Rest of
Asia
million barrels
2013
Total
228
426
654
(79)
11
–
–
(21)
(31)
(120)
160
374
534
–
–
–
–
–
–
–
–
–
–
–
–
–
153
73
226
1,127
818
1,945
–
195
195
(15)
–
–
–
(11)
–
(26)
(111)
33
–
2
(108)
(1)
(185)
(7)
–
–
–
–
–
(7)
147
53
200
1,007
752
1,760
–
188
188
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1
–
–
–
–
–
1
–
1
1
153
73
226
147
53
200
1,127
818
1,945
1,007
752
1,760
–
195
195
–
189
189
16
20
36
1
1
–
–
(7)
–
(5)
15
17
31
336
347
683
(14)
27
34
12
(27)
(85)
(53)
316
314
630
352
367
719
331
331
661
306
236
542
30
2
–
–
(79)
–
(47)
316
180
495
3
2
5
(1)
–
–
–
–
–
(1)
2
2
4
309
239
547
317
182
499
–
–
–
–
–
–
–
–
–
–
–
–
–
2,433
1,943
4,376
295
–
4,550
228
(301)
(4,321)
451
2,970
1,858
4,828
2,433
1,943
4,376
2,970
1,858
4,828
268
137
405
65
65
–
39
(52)
–
117
320
202
522
198
13
211
1
–
–
–
(85)
–
(84)
120
7
127
466
150
616
440
209
649
45
34
79
(5)
–
–
3
(8)
–
(10)
49
19
69
–
–
–
–
–
–
–
–
–
–
–
–
–
45
34
79
49
19
69
2,143
1,938
4,081
(121)
112
–
44
(285)
(32)
(283)
2,013
1,785
3,798
2,970
2,305
5,275
281
27
4,584
240
(412)
(4,406)
314
3,407
2,182
5,590
5,113
4,243
9,357
5,421
3,965
9,388
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
228
426
At 31 December
Developed
Undeveloped
654
160
374
534
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 72 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 8 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 23 million barrels of crude oil in respect of the 0.47% non-controlling interest in Rosneft.
g Total proved crude oil reserves held as part of our equity interest in Rosneft is 4,860 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 32 million barrels in Venezuela and
4,827 million barrels in Russia.
186
BP Annual Report and Form 20-F 2015
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
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
million barrels
2013
Total
UK
14
5
19
1
1
–
–
(1)
(5)
(4)
9
6
15
–
–
–
–
–
–
–
–
–
–
–
–
–
Rest of
Europe
US
Rest of
North
America
Russia
Rest of
Asia
17
6
23
316
171
487
(4)
–
–
–
(1)
–
(5)
(30)
19
–
2
(24)
(10)
(43)
16
2
18
290
155
444
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
17
6
23
16
2
18
316
171
487
290
155
444
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
6
12
18
29
–
–
–
(4)
–
25
14
28
43
3
4
7
(7)
–
–
–
–
–
(7)
–
–
–
9
16
25
14
28
43
6
19
25
(4)
–
–
–
(1)
–
(5)
4
15
20
9
9
18
(2)
–
–
–
–
–
(2)
8
8
16
15
27
43
13
23
36
–
–
–
–
–
–
–
–
–
–
–
–
–
59
19
78
89
–
29
–
(2)
(78)
38
94
21
115
59
19
78
94
21
115
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
7
11
18
(7)
–
–
–
(1)
–
(8)
8
3
10
–
–
–
–
–
–
–
–
–
–
–
–
–
7
11
18
8
3
10
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
366
225
591
(15)
20
–
2
(33)
(15)
(40)
342
209
551
71
32
103
81
–
29
–
(3)
(78)
29
103
29
131
437
257
693
444
238
682
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
14
5
At 31 December
Developed
Undeveloped
19
9
6
15
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 5,500 barrels per day.
d Includes 13 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 Total proved NGL reserves held as part of our equity interest in Rosneft is 115 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 115 million barrels in Russia.
BP Annual Report and Form 20-F 2015
187
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
Rest of
Europe
UK
Rest of
North
America
USc
Russia
Rest of
Asia
242
431
673
(78)
12
–
–
(22)
(36)
(124)
169
380
549
–
–
–
–
–
–
–
–
–
–
–
–
–
170
79
249
1,444
989
2,433
–
195
195
(19)
–
–
–
(13)
–
(31)
(141)
52
–
3
(132)
(12)
(229)
(7)
–
–
–
–
–
(7)
163
55
217
1,297
907
2,204
–
188
188
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1
–
–
–
–
–
1
–
1
1
170
79
249
163
55
217
1,444
989
2,433
1,297
907
2,204
–
195
195
–
188
189
22
32
54
30
1
–
–
(11)
–
20
29
46
74
339
351
691
(21)
27
34
11
(27)
(85)
(61)
316
314
630
361
384
745
345
359
704
312
255
567
26
2
–
–
(80)
–
(52)
320
195
515
–
–
–
–
–
–
–
–
–
–
–
–
–
12
11
23
2,492
1,962
4,453
(3)
–
–
–
–
–
(3)
384
–
4,579
228
(302)
(4,399)
490
10
10
20
3,063
1,879
4,943
324
266
590
331
205
535
2,492
1,962
4,453
3,063
1,879
4,943
268
137
405
65
65
–
39
(52)
–
117
320
202
523
198
13
211
1
–
–
–
(85)
–
(84)
120
7
127
466
150
616
440
209
650
52
45
96
(12)
–
–
3
(9)
–
(18)
57
22
78
–
–
–
–
–
–
–
–
–
–
–
–
–
52
45
96
57
22
78
million barrels
2013
Total
2,509
2,164
4,673
(136)
132
–
45
(319)
(48)
(324)
2,354
1,994
4,348
3,041
2,337
5,378
362
27
4,613
239
(414)
(4,485)
343
3,510
2,210
5,721
5,550
4,501
10,051
5,865
4,204
10,069
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
242
431
At 31 December
Developed
Undeveloped
673
169
380
549
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 72 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 Excludes NGLs from processing plants in which an interest is held of 5,500 barrels per day.
e Also includes 21 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 23 million barrels in respect of the non-controlling interest in Rosneft.
h Total proved liquid reserves held as part of our equity interest in Rosneft is 4,975 million barrels, comprising 1 million barrels in Canada, 32 million barrels in Venezuela, less than 1 million barrels in
Vietnam and 4,943 million barrels in Russia.
188
BP Annual Report and Form 20-F 2015
Movements in estimated net proved reserves – continued
Africa
Asia
Australasia
billion cubic feet
2013
Total
Europe
Rest of
Europe
UK
North
America
Rest of
North
America
US
South
America
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
Russia
Rest of
Asia
–
–
–
–
–
–
–
–
–
–
–
–
–
926
413
1,339
2,148
94
–
1,875
(199)
(67)
3,851
1,519
3,671
5,190
3,588
6,250
9,838
1,139
1,923
3,062
62
144
–
–
(819)
–
(613)
(138)
28
–
55
(239)
–
(294)
3,109
6,116
9,225
961
1,807
2,768
1,276
904
2,180
175
164
339
2,617
1,759
4,376
128
18
146
3
64
14
51
(163)
(38)
(69)
29
–
–
–
(3)
–
26
685
–
8,871
254
(292)
(4,669)
4,849
1,364
747
2,111
230
135
365
4,171
5,054
9,225
1
3
33
–
(23)
(74)
(60)
72
14
86
3,282
2,323
5,605
(140)
–
–
511
(289)
–
82
3,932
1,755
5,687
–
–
–
–
–
–
–
–
–
–
–
–
–
1,038
666
1,704
340
141
481
8,245
2,986
11,231
(62)
49
9
–
(66)
(677)
(747)
643
314
957
(47)
–
–
–
(31)
–
(78)
(1,166)
630
–
39
(635)
(152)
(1,284)
364
39
403
7,122
2,825
9,947
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
4
–
4
10
–
–
–
(4)
–
6
10
–
10
–
–
–
1
–
–
–
–
–
1
–
1
1
4
–
4
10
1
11
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
18,562
14,702
33,264
667
945
9
2,480
(2,282)
(896)
923
17,660
16,527
34,187
4,196
2,845
7,041
719
67
8,918
305
(481)
(4,781)
4,747
5,837
5,951
11,788
22,758
17,547
40,305
23,497
22,478
45,975
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
1,038
666
At 31 December
Developed
Undeveloped
1,704
643
314
957
340
141
481
364
39
403
8,245
2,986
11,231
7,122
2,825
9,947
4,864
7,154
12,018
4,473
6,863
11,336
1,314
2,087
3,401
1,191
1,942
3,133
2,617
1,759
1,054
431
4,376
1,485
4,171
5,054
1,591
3,685
9,225
5,276
3,282
2,323
5,605
3,932
1,755
5,687
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 180 billion cubic feet of natural gas consumed in operations, 149 billion cubic feet in subsidiaries, 31 billion cubic feet in equity-accounted entities.
d Includes 2,685 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 41 billion cubic feet of natural gas in respect of the 0.44% non-controlling interest in Rosneft.
g Total proved gas reserves held as part of our equity interest in Rosneft is 9,271 billion cubic feet, comprising 1 billion cubic feet in Canada, 14 billion cubic feet in Venezuela, 31 billion cubic feet in
Vietnam and 9,225 billion cubic feet in Russia.
BP Annual Report and Form 20-F 2015
189
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
Productionf
Sales of reserves-in-place
At 31 Decemberi j
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
USd
Rest of
North
America
Russia
Rest of
Asia
2013
Total
million barrels of oil equivalentc
421
546
967
(89)
20
2
–
(34)
(152)
(253)
280
434
714
–
–
–
–
–
–
–
–
–
–
–
–
–
229
103
332
2,865
1,504
4,369
1
195
196
640
1,110
1,750
508
587
1,095
(27)
–
–
–
(18)
–
(45)
(342)
161
–
10
(241)
(38)
(450)
(5)
–
–
–
(1)
–
(6)
225
62
287
2,525
1,394
3,919
2
188
190
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1
–
–
–
–
–
1
–
1
1
229
103
332
225
62
287
2,865
1,504
4,369
2,525
1,394
3,919
1
195
196
2
189
191
41
25
–
–
(152)
–
(86)
564
1,100
1,664
559
508
1,067
(20)
38
36
20
(55)
(92)
(73)
552
442
994
1,199
1,618
2,817
1,116
1,542
2,658
3
7
–
9
(121)
–
(102)
486
507
993
43
39
82
2
–
–
–
(1)
–
1
50
33
83
551
626
1,177
536
540
1,076
–
–
–
–
–
–
–
–
–
–
–
–
–
427
209
636
435
81
–
363
(86)
(12)
781
618
445
5,709
4,699
1,063
10,408
(36)
–
–
91
(59)
–
(4)
(20)
294
2
473
(712)
(202)
(165)
582
835
1,417
735
324
5,399
4,844
1,059
10,243
2,943
2,265
5,208
502
–
6,108
272
(353)
(5,204)
1,325
3,782
2,751
6,533
2,943
2,265
5,208
3,782
2,751
6,533
220
15
235
1
1
6
–
(88)
(13)
(93)
133
9
142
647
224
871
–
–
–
–
–
–
–
–
–
–
–
–
–
3,765
2,827
6,592
486
39
6,150
292
(497)
(5,309)
1,161
4,517
3,236
7,753
618
445
9,474
7,526
1,063
17,000
715
844
1,559
735
324
9,916
8,080
1,059
17,996
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
421
546
At 31 December
Developed
Undeveloped
967
280
434
714
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 72 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 5,500 barrels of oil equivalent per day.
f Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 26 million barrels of oil equivalent in subsidiaries, 5 million barrels of oil equivalent in equity-accounted entities.
g Includes 484 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 30 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft.
j Total proved reserves held as part of our equity interest in Rosneft is 6,574 million barrels of oil equivalent, comprising 1 million barrels of oil equivalent in Canada, 34 million barrels of oil equivalent in
Venezuela, 5 million barrels of oil equivalent in Vietnam and 6,533 million barrels of oil equivalent in Russia.
190
BP Annual Report and Form 20-F 2015
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.
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
US
Russia
Rest of
Asia
$ million
2015
Total
At 31 December
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
27,500
15,700
4,700
2,900
4,200
1,900
7,800
5,300
700
800
1,000
300
98,100
56,300
18,800
3,100
19,900
7,400
7,200
4,200
1,700
–
1,300
900
20,100
8,600
7,000
1,700
2,800
900
32,800
12,000
8,100
3,300
9,400
4,300
Standardized measure of discounted
future net cash flowse
2,300
700
12,500
400
1,900
5,100
–
–
–
–
–
–
–
65,200
35,900
18,200
3,800
7,300
3,700
32,000
15,200
4,500
4,000
8,300
4,400
290,700
153,200
63,700
19,600
54,200
23,800
3,600
3,900
30,400
Equity-accounted entities (BP share)f
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 flowsg h
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
39,900
20,200
5,300
3,900
10,500
6,700
3,800
–
–
–
–
–
–
–
182,300
101,200
11,000
12,400
57,700
33,800
3,700
2,200
1,300
100
100
–
23,900
100
–
–
–
–
–
–
–
225,900
123,600
17,600
16,400
68,300
40,500
27,800
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
future net cash flows
2,300
700
12,500
400
5,700
5,100
23,900
3,700
3,900
58,200
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
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 yeari
Equity-accounted
entities (BP share)
$ million
Total subsidiaries and
equity-accounted
entities
(7,300)
4,500
700
(24,700)
500
2,300
(100)
300
4,700
(19,100)
(35,200)
19,500
1,300
(125,100)
14,000
40,900
3,100
(400)
12,700
(69,200)
Subsidiaries
(27,900)
15,000
600
(100,400)
13,500
38,600
3,200
(700)
8,000
(50,100)
a The marker prices used were Brent $54.17/bbl, Henry Hub $2.59/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.
c Taxation is computed using 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 Non-controlling interests in BP Trinidad and Tobago LLC amounted to $600 million.
f 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.
g Non-controlling interests in Rosneft amounted to $93 million in Russia.
h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i 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 to US dollars are
included within ‘Net changes in prices and production cost’.
BP Annual Report and Form 20-F 2015
191
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves – continued
Europe
Rest of
Europe
UK
South
America
North
America
Rest of
North
America
US
Africa
Asia
Australasia
$ million
2014
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
54,400
21,400
7,300
16,400
9,300
4,700
14,900
8,100
1,400
3,000
2,400
700
216,600
90,500
24,500
32,900
68,700
33,100
11,000
4,800
1,600
700
3,900
2,500
35,300
11,300
8,000
8,400
7,600
3,100
55,800
15,600
9,600
10,100
20,500
7,800
Standardized measure of discounted
future net cash flowse
4,600
1,700
35,600
1,400
4,500
12,700
–
–
–
–
–
–
–
90,300
41,500
23,000
5,100
20,700
11,000
54,800
17,600
5,700
9,400
22,100
11,800
533,100
210,800
81,100
86,000
155,200
74,700
9,700
10,300
80,500
Equity-accounted entities (BP share)f
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 flowsg h
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
47,300
22,300
5,700
6,700
12,600
8,000
4,600
–
–
–
–
–
–
–
349,200
200,000
17,400
24,200
107,600
65,500
10,200
7,800
2,100
100
200
–
42,100
200
–
–
–
–
–
–
–
406,700
230,100
25,200
31,000
120,400
73,500
46,900
future net cash flows
4,600
1,700
35,600
1,400
9,100
12,700
42,100
9,900
10,300
127,400
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
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 yeari
Subsidiaries
Equity-accounted
entities (BP share)
$ million
Total subsidiaries and
equity-accounted
entities
(30,500)
15,700
1,900
(17,000)
1,200
17,300
(4,500)
(700)
8,800
(7,800)
(6,900)
3,600
1,500
10,500
2,000
(4,900)
(400)
–
3,800
9,200
(37,400)
19,300
3,400
(6,500)
3,200
12,400
(4,900)
(700)
12,600
1,400
a The marker prices used were Brent $101.27/bbl, Henry Hub $4.31/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.
c Taxation is computed using 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 Non-controlling interests in BP Trinidad and Tobago LLC amounted to $1,400 million.
f 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.
g Non-controlling interests in Rosneft amounted to $100 million in Russia.
h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i 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 to US dollars are
included within ‘Net changes in prices and production cost’.
192
BP Annual Report and Form 20-F 2015
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves – continued
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
US
Russia
Rest of
Asia
$ million
2013
Total
66,200
21,900
6,500
23,900
13,900
6,800
26,300
11,200
2,000
8,000
5,100
2,200
234,500
99,000
27,700
37,000
70,800
34,300
9,400
4,600
2,000
400
2,400
1,900
40,000
11,600
7,600
11,100
9,700
4,200
67,500
17,800
10,900
14,300
24,500
9,300
7,100
2,900
36,500
500
5,500
15,200
–
–
–
–
–
–
–
89,000
35,000
23,700
6,200
24,100
13,300
57,600
20,000
6,900
8,100
22,600
12,800
590,500
221,100
87,300
109,000
173,100
84,800
10,800
9,800
88,300
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
45,800
22,500
6,000
5,900
11,400
6,900
4,500
–
–
–
–
–
–
–
255,600
139,000
19,700
15,200
81,700
48,700
14,300
11,800
2,100
100
300
100
33,000
200
–
–
–
–
–
–
–
315,700
173,300
27,800
21,200
93,400
55,700
37,700
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
Equity-accounted entities (BP share)f
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 flowsg h
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
future net cash flows
7,100
2,900
36,500
500
10,000
15,200
33,000
11,000
9,800
126,000
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
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 yeari
Subsidiaries
Equity-accounted
entities (BP share)
$ million
Total subsidiaries and
equity-accounted
entities
(30,600)
14,000
1,900
(1,800)
(3,100)
12,900
(4,100)
(3,500)
9,300
(5,000)
(7,900)
3,200
2,000
(100)
(400)
3,400
(2,100)
9,000
2,800
9,900
(38,500)
17,200
3,900
(1,900)
(3,500)
16,300
(6,200)
5,500
12,100
4,900
a The marker prices used were Brent $108.02/bbl, Henry Hub $3.66/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.
c Taxation is computed using 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 Non-controlling interests in BP Trinidad and Tobago LLC amounted to $1,700 million.
f 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.
g Non-controlling interests in Rosneft amounted to $200 million in Russia.
h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i Total change in the standardized measure during the year includes the effect of exchange rate movements.
BP Annual Report and Form 20-F 2015
193
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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 2015, 2014 and 2013.
Production for the yeara b
Europe
North
America
South
America
Africa
Asia
Australasia
Total
Subsidiaries
Crude oild
2015
2014
2013
Natural gas liquids
2015
2014
2013
Natural gase
2015
2014
2013
Equity-accounted entities (BP share)
Crude oild
2015
2014
2013
Natural gas liquids
2015
2014
2013
Natural gase
2015
2014
2013
UK
72
46
58
7
2
3
155
71
157
–
–
–
–
–
–
–
–
–
Rest of
Europe
38
41
31
5
5
4
US
323
347
305
56
63
58
111
102
80
1,528
1,519
1,539
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
Rest of
North
America
Russiac
Rest of
Asia
3
–
–
–
–
–
10
10
11
–
–
–
–
–
–
–
–
–
12
13
17
11
12
12
1,922
2,147
2,221
68
65
62
3
3
3
435
402
384
270
222
217
7
5
3
589
513
561
–
–
–
3
4
5
–
–
–
–
–
–
–
–
–
–
–
–
809
816
826
4
5
11
1,195
1,084
801
237
156
141
1
–
1
380
408
490
97
98
232
–
–
–
21
28
30
thousand barrels per day
17
19
21
971
844
789
thousand barrels per day
3
3
4
88
91
86
million cubic feet per day
801
814
784
5,495
5,585
5,845
thousand barrels per day
–
–
–
974
979
1,120
thousand barrels per day
–
–
–
10
12
19
million cubic feet per day
–
–
–
1,651
1,515
1,216
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 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 Crude oil includes condensate.
e Natural gas production excludes gas consumed in operations.
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 2015. 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.
Europe
Rest of
Europe
UK
North
America
Rest of
North
America
US
Number of productive wells at 31 December 2015
Oil wellsc
Gas wellsd
Undevelopede
Oil and natural gas acreage at 31 December 2015
Developed
– gross
– net
– gross
– net
– gross
– net
– gross
– net
121
77
63
27
128
74
1,500
1,056
65
26
5
1
40
17
1,501
571
2,428
830
22,760
9,492
6,226
3,366
6,662
4,855
143
33
309
153
237
111
9,712
5,566
South
America
4,848
2,680
821
303
1,386
417
22,046
6,619
Africa
Asia
Australasia
Totalb
Russiaa
45,134
8,914
791
156
659
457
144
62
655
255
32,692
21,210
4,828
908
378,688
73,971
Rest of
Asia
1,036
354
860
320
866
267
7,395
2,518
12
2
73
14
54,446
13,374
25,826
10,529
thousands of acres
194
36
15,661
9,743
14,558
5,452
475,856
126,108
a Based on information received from Rosneft as at 31 December 2015.
b Because of rounding some totals may not exactly agree with the sum of their component parts.
c Includes approximately 7,944 gross (1,582 net) multiple completion wells (more than one formation producing into the same well bore).
d Includes approximately 3,232 gross (1,534 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.
194
BP Annual Report and Form 20-F 2015
Operational and statistical information – continued
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.
Europe
North
America
South
America
Africa
Asia
Australasia
Totala
2015
Exploratory
Productive
Dry
Development
Productive
Dry
2014
Exploratory
Productive
Dry
Development
Productive
Dry
2013
Exploratory
Productive
Dry
Development
Productive
Dry
UK
–
–
1.6
–
2.9
0.5
3.1
–
1.0
–
1.0
–
Rest of
North
America
Russia
Rest of
Asia
Rest of
Europe
–
–
US
4.0
–
0.4
–
235.6
–
–
–
5.3
7.9
–
–
–
–
–
–
1.1
0.4
143.1
2.3
3.7
1.4
2.6
1.0
20.7
1.3
0.7
1.6
13.8
1.0
4.5
–
91.4
–
5.3
–
76.2
–
1.8
0.8
294.1
–
1.5
0.1
100.5
3.9
–
–
12.7
1.1
1.2
0.2
285.7
0.4
–
–
–
–
4.5
1.4
94.6
2.7
1.5
0.6
4.0
–
12.6
0.2
395.0
–
a Because of rounding, some totals may not exactly agree with the sum of their component parts.
–
–
51.2
–
0.6
1.4
46.3
0.4
3.5
0.9
58.0
0.7
–
0.2
0.9
–
–
0.2
–
0.4
–
0.5
0.2
0.4
12.2
1.6
544.7
3.5
18.5
13.0
537.3
6.6
27.2
4.5
848.3
4.6
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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 2015. Suspended development wells and long-term suspended exploratory wells are also included in the
table.
At 31 December 2015
Exploratory
Gross
Net
Development
Gross
Net
Europe
North
America
South
America
Africa
Asia
Australasia
Totala
Rest of
Europe
Rest of
North
America
US
Russia
Rest of
Asia
–
–
–
–
11.0
6.6
309.0
109.0
–
–
14.0
7.0
–
–
11.0
6.2
4.0
1.8
40.0
18.9
–
–
–
–
–
–
55.0
19.8
–
–
3.0
0.5
16.0
8.6
434.0
162.7
UK
1.0
0.3
2.0
1.3
a Because of rounding, some totals may not exactly agree with the sum of their component parts.
BP Annual Report and Form 20-F 2015
195
Parent company financial statements of BP p.l.c.
Company balance sheet
At 31 December
Fixed assets
Investments
Defined benefit pension plan surplus
Total fixed assets
Current assets
Debtors – amounts falling due within one year
Deferred tax asset
Cash at bank and in hand
Creditors – amounts falling due within one yeara
Net current assets
Total assets less current liabilities
Creditors – amounts falling due after more than one yeara
Defined benefit pension plan deficit
Deferred tax liability
Net assets
Capital and reserves
Called-up share capital
Share premium account
Capital redemption reserve
Merger reserve
Treasury shares
Foreign currency translation reserve
Profit and loss account
Note
2015
2014
$ million
2013
3
6
4
2
5
5
6
2
7
139,241
2,516
141,757
139,241
15
139,256
134,127
1,291
135,418
1,062
–
–
1,062
212
850
7,159
–
31
7,190
559
6,631
21,550
41
6
21,597
1,956
19,641
142,607
6,741
145,887
6,961
155,059
6,953
227
877
599
–
271
41
134,762
138,327
147,794
5,049
10,234
1,413
26,509
(19,964)
–
111,521
5,023
10,260
1,413
26,509
(20,719)
31
115,810
5,129
10,061
1,260
26,509
(20,971)
–
125,806
134,762
138,327
147,794
a For 2014 and 2013 comparative balances there has been a reclassification from amounts due within one year to amounts due after one year as set out in Note 5.
The financial statements on pages 196-213 were approved and signed by the BP group chief executive on 4 March 2016 having been duly authorized
to do so by the board of directors:
R W Dudley BP Group Chief Executive
The parent company financial statements of BP p.l.c. on pages 196-213 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
196
BP Annual Report and Form 20-F 2015
Company cash flow statement
For the year ended 31 December
Operating activities
Profit before taxation
Adjustments to reconcile profit before taxation to net cash provided by operating activities
Gain on sale of businesses and fixed assets
Interest receivable
Interest received
Finance cost
Net finance (income) 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
Decrease in debtors
Decrease in creditors
Income taxes paid
Net cash provided by operating activities
Financing activities
Net issue (repurchase) of shares
Dividends paid
Net cash used in financing activities
Increase (decrease) in cash
Cash at beginning of year
Cash at end of year
2015
$ million
2014
653
1,420
(31)
(108)
13
36
20
321
(263)
6,185
(197)
(1)
6,628
–
(118)
18
23
(50)
379
(227)
9,379
(359)
(1)
10,464
–
(6,659)
(4,589)
(5,850)
(6,659)
(10,439)
(31)
31
–
25
6
31
Company statement of changes in equitya
At 1 January 2015
Profit for the year
Currency translation differences
Actuarial gain on pensions (net of tax)
Total comprehensive income
Dividends
Share-based payments, net of tax
At 31 December 2015
Share
capital
5,023
–
–
–
5,023
26
–
5,049
Share
premium
account
10,260
–
–
–
10,260
(26)
–
10,234
Capital
redemption
reserve
Merger
reserve
Treasury
shares
1,413
26,509
(20,719)
–
–
–
1,413
–
–
1,413
–
–
–
–
–
–
26,509
–
–
26,509
(20,719)
–
755
(19,964)
At 1 January 2014
5,129
10,061
1,260
26,509
(20,971)
Profit for the year
Currency translation differences
Actuarial loss on pensions (net of tax)
Total comprehensive income
Dividends
Repurchases of ordinary share capital
Share-based payments, net of tax
At 31 December 2014
a See Note 8 for further information.
–
–
–
5,129
41
(153)
6
5,023
–
–
–
10,061
(41)
–
240
10,260
–
–
–
1,260
–
153
–
1,413
–
–
–
26,509
–
–
–
26,509
–
–
–
(20,971)
–
–
252
(20,719)
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Foreign
currency
translation
reserve
Profit
and loss
account
$ million
Total
equity
31
–
(31)
–
–
–
–
–
–
–
31
–
31
–
–
–
31
115,810
138,327
571
–
1,894
118,275
(6,659)
(95)
111,521
571
(31)
1,894
140,761
(6,659)
660
134,762
125,806
147,794
1,378
–
(1,871)
125,313
(5,850)
(3,366)
(287)
115,810
1,378
31
(1,871)
147,332
(5,850)
(3,366)
211
138,327
The parent company financial statements of BP p.l.c. on pages 196-213 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 2015
197
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 2015 were approved and signed by the BP group chief executive on 4 March
2016 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 (FRS 100) issued by the Financial Reporting Council. Accordingly, these financial statements were prepared in accordance with Financial
Reporting Standard 101 Reduced Disclosure Framework (FRS 101) and in accordance with the provisions of the Companies Act 2006.
There were no material measurement or recognition adjustments on the adoption of FRS 101. See Note 14 for further information.
Basis of preparation
These financial statements are 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 Section 408 of the Companies Act 2006, the profit and loss account 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).
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 could 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 on financial statements.
Investments
Investments in subsidiaries are recorded at cost. The company assesses investments for impairment whenever events or changes in circumstances
indicate that the carrying value of an investment 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.
Significant estimate or judgement: investments
The recoverable amount, which is often the fair value less costs to sell, may be based upon discounted future cash flows. The assumptions
underlying these calculations, such as the discount rate, future oil and gas prices, and other asset specific factors, are judgemental. Further
information on the assumptions that are used in such calculations are included in Note 1 to the consolidated financial statements.
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 rate of exchange ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign
currencies are retranslated into the functional currency at the rate of exchange ruling at the balance sheet date. Any resulting exchange differences are
included in the income statement.
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 taken directly to reserves and reported in other comprehensive income. Income statement transactions are translated into
US dollars using the average exchange rate for the reporting period.
Share-based payments
Equity-settled transactions
The cost of equity-settled transactions with employees of the company and other members of the BP group is measured by reference to the fair value
at the date at which equity instruments 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.
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 each balance sheet date until settlement, with changes in fair value
recognized in the income statement.
Pensions
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.
The parent company financial statements of BP p.l.c. on pages 196-213 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
198
BP Annual Report and Form 20-F 2015
1. Significant accounting policies, judgements, estimates and assumptions – continued
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 in the balance sheet comprises the total for each plan of the present value of the defined benefit
obligation (using a discount rate based on high quality corporate bonds), less 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.
Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.
Significant estimate or judgement: pensions and other post-retirement benefits
Accounting for pensions and other post-retirement benefits involves judgement about uncertain events, including estimated retirement dates, salary
levels at retirement, mortality rates, determination of discount rates for measuring plan obligations and net interest expense and assumptions for
inflation rates.
These assumptions are based on the environment in each country. The assumptions used may vary from year to year, which would affect future net
income and net assets. Any differences between these assumptions and the actual outcome also affect future net income and net assets.
Pension and other post-retirement benefit assumptions are reviewed by management at the end of each year. The assumptions used are provided in
Note 6.
Income taxes
Income tax expense represents the sum of current tax and deferred tax. Interest and penalties relating to income tax are also included in the income
tax expense.
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.
F
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a
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c
i
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s
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t
s
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.
Significant estimate or judgement: deferred tax
Management judgement is required to determine the amount of deferred tax assets that can be recognized, based upon the likely timing and level of
future taxable profits.
Financial assets
All financial assets held by the company are classified as loans and receivables. Financial assets include cash and cash equivalents, other receivables,
loans, and other investments. The company determines the classification of its financial assets at initial recognition. Financial assets are recognized
initially at fair value, normally being the transaction price plus directly attributable transaction costs.
Loans and receivables
Loans and receivables are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are
recognized in income when the loans and receivables are derecognized or impaired, as well as through the amortization process. This category of
financial assets includes other receivables. Cash and 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 have a maturity of three months or less from the date of acquisition.
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 most items of 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. For interest-bearing loans and borrowings this is 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 respectively in interest and other income and finance costs.
This category of financial liabilities includes other payables, financial guarantees and finance debt.
The parent company financial statements of BP p.l.c. on pages 196-213 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 2015
199
2. 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 and other post-retirement benefits
Other taxable temporary differences
Deferred tax
Deferred tax liability
Pensions and other post-retirement benefits
Net deferred tax liability
Analysis of movements during the year
At 1 January
Charge for the year on ordinary activities
Charge (credit) for the year in other comprehensive income
At 31 December
$ million
2015
2014
877
877
–
877
877
–
81
796
877
–
(41)
41
–
–
–
41
(41)
–
At 31 December 2015, deferred tax assets of $65 million relating to other temporary differences and $8 million relating to pensions and other post-
retirement benefits (2014 $95 million relating to other temporary differences and $25 million relating to pensions and other post-retirement benefits)
were not recognized as it is not considered more likely than not that suitable taxable profits will be available in the company from which the future
reversal of the underlying temporary differences can be deducted. It is anticipated that the reversal of these temporary differences will benefit other
group companies in the future.
3. Investments
Cost
At 1 January 2015
Additions
Disposals
At 31 December 2015
Amounts provided
At 1 January 2015
At 31 December 2015
Cost
At 1 January 2014
Additions
Disposals
At 31 December 2014
Amounts provided
At 1 January 2014
Disposals
At 31 December 2014
At 31 December 2015
At 31 December 2014
At 31 December 2013
Subsidiary
undertakings
Associated
undertakings
Shares
Shares
Loans
Total
$ million
139,313
2,800
(2,800)
139,313
74
74
134,199
5,114
–
139,313
74
–
74
139,239
139,239
134,125
2
–
–
2
–
–
2
–
–
2
–
–
–
2
2
2
–
–
–
–
–
–
2
–
(2)
–
2
(2)
–
–
–
–
139,315
2,800
(2,800)
139,315
74
74
134,203
5,114
(2)
139,315
76
(2)
74
139,241
139,241
134,127
The more important subsidiary undertakings of the company at 31 December 2015 and the percentage holding of ordinary share capital (to the nearest
whole number) are set out below. For a full list of significant holdings see Note 15.
Subsidiary undertakings
International
BP Corporate Holdings
BP Global Investments
BP International
Burmah Castrol
Canada
BP Holdings Canada
US
%
100
100
100
100
Country of
incorporation
England & Wales
England & Wales
England & Wales
Scotland
Principal activities
Investment holding
Investment holding
Integrated oil operations
Lubricants
100
England & Wales
Investment holding
BP Holdings North America
100
England & Wales
Investment holding
The carrying value of BP International Limited in the accounts of the company at 31 December 2015 was $70,425 million (2014 $67,625 million and
2013 $62,625 million).
The parent company financial statements of BP p.l.c. on pages 196-213 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
200
BP Annual Report and Form 20-F 2015
4. Debtors
Group undertakings
Other debtors
2015
Within
1 year
1,059
3
1,062
2014
Within
1 year
7,159
–
7,159
$ million
2013
Within
1 year
21,550
–
21,550
The company has a short-term receivable balance due from BP International Limited (2015 $757 million; 2014 $6,712 million) that arises primarily in
relation to internal trading partner arrangements utilized to fund BP p.l.c.’s external dividend obligations. This balance, together with the carrying value
of the guarantees as set out in Note 9, is included in the amounts due from group undertakings within one year.
BP p.l.c. received dividends of $1,618 million during the year (2014 $2,129 million), with the company also making dividend payments as set out in
Note 9 to the consolidated financial statements.
5. Creditors
Group undertakings
Accruals and deferred income
Other creditors
Within
1 year
100
81
31
212
2015
After
1 year
6,708
33
–
6,741
Within
1 year
140
391
28
559
2014
After
1 year
6,871
90
–
6,961
Within
1 year
184
1,540
232
1,956
$ million
2013
After
1 year
6,895
58
–
6,953
Included in amounts due to group undertakings after one year is an interest-bearing payable balance of $4,236 million (2014 $4,236 million, 2013
$4,236 million) with BP International Limited, with interest being charged at a 1 year USD LIBOR rate and a maturity date of December 2021. Also
included is an interest-bearing payable balance of $2,311 million with BP Finance plc, with interest being charged based on a 3 month USD LIBOR rate
plus 55 basis points and a maturity date of April 2020. The comparative balances for 2014 and 2013 ($2,308 million and $2,311 million respectively)
have been reclassified from amounts due within one year to amounts due after one year; this is in line with the underlying contractual terms and
ensures a consistent presentation.
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 Creditors – amounts falling due after more than one year.
Due within
1 to 2 years
2 to 5 years
More than 5 years
6. Pensions
2015
2014
75
85
6,581
6,741
154
184
6,623
6,961
$ million
2013
110
204
6,639
6,953
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, including 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 but remains open to ongoing accrual for current members. New joiners in the UK 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 2015 the aggregate level of contributions was $754 million (2014 $713 million and 2013 $ 597 million). The aggregate level of contributions in
2016 is expected to be approximately $463 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 the latest funding position is reviewed
and a schedule of contributions covering the next seven years is agreed. The funding agreement can be terminated unilaterally by either party with two
years’ notice. Contractually committed funding therefore represents nine years of future contributions, which amounted to $4,374 million at
31 December 2015, of which $1,437 million relates to past 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 2015. 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 2014.
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 and other post-retirement benefits at 31 December and pension
expense for the following year.
The parent company financial statements of BP p.l.c. on pages 196-213 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 2015
201
F
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6. Pensions – continued
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
2015
2014
2013
%
3.9
4.4
3.0
3.0
3.0
3.6
4.5
3.0
3.0
3.0
4.6
5.1
3.3
3.3
3.3
%
2015
2014
2013
3.9
3.6
3.1
4.8
4.6
3.4
4.4
4.4
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 includes an allowance for promotion-related salary growth.
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
2015
28.5
31.0
29.5
31.9
2014
28.3
30.9
29.4
31.8
Years
2013
27.8
30.7
29.5
32.2
The assets of the primary plan are held in a trust. The primary objective of the trust 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 significant 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.
For the primary UK pension plan there is an agreement with the trustee to reduce the proportion of plan assets held as equities and increase the
proportion held as bonds over time, with a view to better matching the asset portfolio with the pension liabilities. During 2015, the plan switched 8%
from equities to bonds.
In 2015, BP’s primary plan in the UK adopted a more formal liability driven investment (LDI) approach for part of the portfolio, a form of investing
designed to match the movement in pension plan assets with the impact of interest rate changes and inflation assumption changes on the projected
benefit obligation.
The company’s current asset allocation policy for the main plan is as follows:
Asset category
Total equity (including private equity)
Bonds/cash (including LDI)
Property/real estate
%
62
31
7
The amounts invested under the LDI programme as at 31 December 2015 were $329 million of government issued nominal bonds and $6,421 million
of index-linked bonds. This is partly funded by short-term sale and repurchase agreements, proceeds from which are shown separately in the table
below.
In addition, the primary UK plan entered into interest rate swaps in the year to offset the long-term fixed interest rate exposure for $2,651 million of the
corporate bond portfolio. The $17 million fair value of the swaps as at 31 December 2015 is included in other assets in the table below.
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 204.
The parent company financial statements of BP p.l.c. on pages 196-213 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
202
BP Annual Report and Form 20-F 2015
6. Pensions – continued
Fair value of pension plan assets
Listed equities – developed markets
– emerging markets
Private equity
Government issued nominal bondsa
Government issued index-linked bondsa
Corporate bondsa
Propertyb
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments
a Bonds held are denominated in sterling.
b Property held is all located in the United Kingdom.
Analysis of the amount charged to profit before interest and taxation
Current service costa
Past service costb
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 (expense)
Analysis of the amount recognized in other comprehensive income
Actual 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
2015
2014
13,474
2,305
2,933
393
6,425
4,357
2,453
564
110
(1,791)
31,223
2015
485
12
497
31
528
1,124
(1,144)
(20)
315
2,054
–
321
2,690
16,190
2,719
2,983
642
892
4,687
2,403
1,145
112
–
31,773
2014
494
–
494
30
524
1,425
(1,375)
50
1,269
(3,181)
42
(42)
(1,912)
$ million
2013
17,341
2,290
2,907
549
787
4,427
2,200
855
160
–
31,516
$ million
2013
497
(22)
475
24
499
1,139
(1,221)
(82)
2,671
60
–
41
2,772
F
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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 cost represents the increased liability arising as a result of early retirements occurring as part of 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.
The parent company financial statements of BP p.l.c. on pages 196-213 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 2015
203
6. Pensions – continued
Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustment
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 adjustment
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 (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
2015
$ million
2014
32,357
(1,446)
497
1,144
32
(1,269)
(6)
(2,375)
28,934
31,773
(1,506)
1,124
32
754
(1,269)
315
31,223
2,289
2,516
(227)
2,289
2,506
(217)
2,289
30,496
(1,989)
494
1,375
39
(1,231)
(8)
3,181
32,357
31,516
(1,958)
1,425
39
713
(1,231)
1,269
31,773
(584)
15
(599)
(584)
(310)
(274)
(584)
(28,717)
(217)
(28,934)
(32,083)
(274)
(32,357)
a Most of the contributions made by plan participants were made under salary sacrifice.
b The benefit payments amount shown above comprises $1,253 million benefits plus $22 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 $31,030 million of assets held in the BP Pension Fund (2014 $31,600 million) and $147million held in the BP Global Pension Trust (2014 $134 million), with $37 million representing the
company’s share of Merchant Navy Officers Pension Fund (2014 $39 million) and $9 million of Merchant Navy Ratings Pension Fund (2014 $nil).
e The fair value of plan assets includes borrowings related to the LDI programme as described on page 202.
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 2015 for the company’s plans would have had the effects shown in the table below.
The effects shown for the expense in 2016 comprise the total of current service cost and net finance income or expense.
Discount ratea
Effect on pension and other post-retirement benefit expense in 2016
Effect on pension and other post-retirement benefit obligation at 31 December 2015
Inflation rateb
Effect on pension and other post-retirement benefit expense in 2016
Effect on pension and other post-retirement benefit obligation at 31 December 2015
Salary growth
Effect on pension and other post-retirement benefit expense in 2016
Effect on pension and other post-retirement benefit obligation at 31 December 2015
$ million
One percentage point
Increase
Decrease
(328)
(4,651)
334
5,802
78
813
307
6,027
(253)
(4,543)
(68)
(729)
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 2016 pension and other post-retirement benefit expense by $40
million and the pension and other post-retirement benefit obligation at 31 December 2015 by $861 million.
The parent company financial statements of BP p.l.c. on pages 196-213 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
204
BP Annual Report and Form 20-F 2015
6. 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 2025 and the weighted
average duration of the defined benefit obligations at 31 December 2015 are as follows:
Estimated future benefit payments
2016
2017
2018
2019
2020
2021-2025
Weighted average duration
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 plansb
Repurchase of ordinary share capitalc
At 31 December
Shares
thousand
7,233
5,473
20,005,961
102,810
–
–
20,108,771
2015
$ million
12
9
21
Shares
(thousand)
7,233
5,473
5,002 20,426,632
165,644
25,598
(611,913)
26
–
–
5,028 20,005,961
5,049
2014
$ million
12
9
21
5,108
41
6
(153)
5,002
5,023
Shares
(thousand)
7,233
5,473
20,959,159
202,124
18,203
(752,854)
20,426,632
$ million
1,059
1,096
1,148
1,185
1,208
6,562
Years
18.2
2013
$ million
12
9
21
5,240
51
5
(188)
5,108
5,129
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.
b Consideration received relating to the issue of new shares for employee share-based payment plans amounted to $207 million in 2014 and $116 million in 2013.
c There were no shares repurchased in 2015 (2014 shares were repurchased for a total consideration of $4,796 million, including transaction costs of $26 million and 2013 shares were repurchased for a
total consideration of $5,493 million, including transaction costs of $30 million). All shares purchased were for cancellation.
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.
Treasury sharesa
At 1 January
Purchases for settlement of employee share 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 BPb
2015
2014
2013
Shares
thousand
Nominal value
$ million
Shares
thousand
Nominal value
$ million
Shares
thousand
Nominal value
$ million
1,811,297
51,142
(106,112)
1,756,327
1,727,763
18,453
10,111
453
13
(27)
1,833,544
49,559
(71,806)
458
12
(17)
1,864,510
38,766
(69,732)
439
1,811,297
453
1,833,544
432
4
3
1,771,103
34,169
6,025
443
9
1
1,787,939
32,748
12,857
466
9
(17)
458
447
8
3
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.
For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by BP during the year, representing
8.9% (2014 8.8% and 2013 8.7%) of the called-up ordinary share capital of the company.
During 2015, the movement in shares held in treasury by BP represented less than 0.2% (2014 less than 0.1% and 2013 less than 0.2%) of the
ordinary share capital of the company.
The parent company financial statements of BP p.l.c. on pages 196-213 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 2015
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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) 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 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 $24,107 million (2014 $24,107 million), the distribution of which is limited by statutory or other restrictions.
The accounts for the year ended 31 December 2015 do not reflect the dividend announced on 2 February 2016 and payable in March 2016; this will be
treated as an appropriation of profit in the year ended 31 December 2016.
9. Contingent liabilities
The company has issued guarantees under which the maximum aggregate liabilities at 31 December 2015 were $51,775 million (2014 $51,463
million), the majority of which relate to finance debt of subsidiaries. The carrying value of the guarantees at 31 December 2015 was $211 million (2014
$417 million). The guarantee fee income recognized within profit for the year ending 31 December 2015 was $94 million (2014 $100 million). The
company has also issued uncapped indemnities and guarantees, including a guarantee of subsidiaries’ liabilities under the Plaintiffs’ Steering
Committee settlement agreement relating to the Gulf of Mexico oil spill, and in relation to potential losses arising from environmental incidents
involving ships leased and operated by a subsidiary.
10. Capital management
The company defines capital as total equity (which is the company’s net asset value). The company maintains its financial framework to support the
pursuit of value growth for shareholders, while ensuring a secure financial base. The BP group aims to maintain the net debt ratio, that is, the ratio of
net debt to net debt plus equity, with some flexibility, at around 20%.
11. 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 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
Additional information on the company’s share-based payment plans is provided in Note 10 to the consolidated financial statements.
12. Auditor’s remuneration
Note 35 to the consolidated financial statements provides details of the remuneration of the company’s auditor on a BP group basis.
13. Directors’ remuneration
Remuneration of directors
Total for all directors
Emoluments
Amounts awarded under incentive schemesa
Total
a Excludes amounts relating to past directors.
$ million
2014
770
(81)
689
108
54
2015
759
(50)
709
32
–
$ million
2014
14
10
24
2015
10
14
24
The parent company financial statements of BP p.l.c. on pages 196-213 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
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13. Directors’ remuneration – continued
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. There was no compensation for loss of office in 2015 (2014 $nil).
14. Explanation of transition to FRS 101
For all periods up to and including the year ended 31 December 2014, the company prepared its financial statements in accordance with
United Kingdom generally accepted accounting practice (UK GAAP). These financial statements, for the year ended 31 December 2015, are the first
the company has prepared in accordance with FRS 101.
Comparative information included in these financial statements has also been prepared in accordance with FRS 101 and the significant accounting
policies described in Note 1.
On transition to FRS 101, the company has applied the requirements of paragraphs 6 – 33 of IFRS 1 ‘First-time adoption of International Financial
Reporting Standards’ (IFRS 1).
Exemptions applied
IFRS 1 allows first-time adopters certain exemptions from the general requirements to apply IFRS. The company has taken advantage of the following
exemptions:
(a) business combinations (paragraphs C1 – C5);
(b) share-based payment transactions (paragraphs D2 and D3);
(c) cumulative translation differences (paragraphs D12 and D13).
In preparing these financial statements, the company has started from an opening balance sheet as at 1 January 2014, the company’s date of transition
to FRS 101, and made those changes in accounting policies and other restatements required for the first time adoption of FRS 101.
Pensions
Under previous UK GAAP the interest cost was determined by applying the discount rate to the opening present value of the defined benefit obligation
and the changes in the defined benefit obligation during the year. The interest income on the expected return on plan assets was based on an
assessment made at the beginning of the year of the long-term market returns on plan assets. Under IAS 19 net interest is calculated by applying the
discount rate to the net defined liability or asset. As a result of transition to FRS 101, net interest for the year ended 31 December 2014 was
$722 million higher than had been recognized under previous UK GAAP (2013 $664 million), with a corresponding reduction in remeasurement gains
recognized in other comprehensive income.
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The parent company financial statements of BP p.l.c. on pages 196-213 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 2015
207
15. Related undertakings of the group
In accordance with Section 409 of the Companies Act 2006, a full list of related undertakings, the country of incorporation and the percentage of share
capital owned as at 31 December 2015 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.
Subsidiary undertakings are controlled by the group and their results are fully consolidated in the group’s financial statements.
The percentage of share capital owned by the group is 100% unless otherwise noted below.
Subsidiaries
200 PS Overseas Holdings Inc. (United States)
4321 North 800 West LLC (United States)
563916 Alberta Ltd. (Canada, 99.90%)
ACP (Malaysia), Inc. (United States)
Actomat B.V. (Netherlands)
Advance Petroleum Holdings Pty Ltd (Australia)
Advance Petroleum Pty Ltd (Australia)
AE Cedar Creek Holdings LLC (United States)
AE Goshen II Holdings LLC (United States)
AE Goshen II Wind Farm LLC (United States)
AE Power Services LLC (United States)
AE Wind PartsCo LLC (United States)
Air BP Albania SHA (Albania)
Air BP Brasil Ltda. (Brazil)
Air BP Canada LLC (United States)
Air BP Croatia d.o.o. (Croatia)
Air BP Denmark ApS (Denmark)
Air BP Finland Oy (Finland)
Air BP Limited (United Kingdom)
Air BP Norway AS (Norway)
Air BP Sales Romania S.R.L. (Romania)
Air BP Sweden AB (Sweden)
Air Refuel Pty Ltd (Australia)
Alexander Duckham & Co.,Limited (United Kingdom)
Alexis Wind Farm LLC (United States)
Allgreen Pty Ltd (Australia)
AM/PM International Inc. (United States)
American Oil Company (United States)
Amoco (Fiddich) Limited (United Kingdom)
Amoco (U.K.) Exploration Company, LLC (United States)
Amoco Angola B.V. (Netherlands)
Amoco Austria Petroleum Company (United States)
Amoco Bolivia Petroleum Company (United States)
Amoco Bolivia Services Company Inc. (Virgin Islands, British)
Amoco Brazil, Inc. (United States)
Amoco Canada International Holdings B.V. (Netherlands)
Amoco Capline Pipeline Company (United States)
Amoco Caspian Sea Petroleum Company (United States)
Amoco Chemical (Europe) S.A. (United States)
Amoco Chemical Holding B.V. (Netherlands)a
Amoco Chemical U.K. Limited (in liquidation) (United Kingdom)
Amoco Chemicals (FSC) B.V. (Netherlands)
Amoco CNG (Trinidad) Limited (Trinidad and Tobago)
Amoco Cypress Pipeline Company (United States)
Amoco Destin Pipeline Company (United States)
Amoco Endicott Pipeline Company (United States)
Amoco Environmental Services Company (United States)
Amoco Exploration Holdings B.V. (Netherlands)
Amoco Fabrics (U.K.) Limited (in liquidation) (United Kingdom)
Amoco Fabrics and Fibers Ltd. (Canada)
Amoco Guatemala Petroleum Company (United States)b
Amoco Inam Petroleum Company B.V. (Netherlands)
Amoco International Finance Corporation (United States)
Amoco International Petroleum Company (United States)
Amoco Kazakhstan (CPC) Inc. (United States)
Amoco Leasing Corporation (United States)
Amoco Louisiana Fractionator Company (United States)
Amoco Main Pass Gathering Company (United States)
Amoco Marketing Environmental Services Company (United States)
Amoco MB Fractionation Company (United States)
Amoco MBF Company (United States)
Amoco Netherlands Petroleum Company (United States)
Amoco Nigeria Exploration Company Limited (Nigeria)a
Amoco Nigeria Oil Company Limited (Nigeria)a
Amoco Nigeria Petroleum Company (United States)
Amoco Nigeria Petroleum Company Limited (Nigeria)
Amoco Norway Oil Company (United States)
Amoco Oil Holding Company (United States)
Amoco Olefins Corporation (United States)
Amoco Overseas Exploration Company (United States)
Amoco Pipeline Asset Company (United States)
Amoco Pipeline Holding Company (United States)
Amoco Properties Incorporated (United States)
Amoco Realty Company (United States)
Amoco Remediation Management Services Corporation (United States)
Amoco Research Operating Company (United States)
Amoco Rio Grande Pipeline Company (United States)
Amoco Somalia Petroleum Company (United States)
Amoco Sulfur Recovery Company (United States)
Amoco Tax Leasing X Corporation (United States)
Amoco Trinidad Gas B.V. (Netherlands)
Amoco Tri-States NGL Pipeline Company (United States)
Amoco U.K. Petroleum Limited (United Kingdom)
AmProp Finance Company (United States)
Amprop Illinois I Ltd. Partnership (United States)c
Amprop, Inc. (United States)
Anaconda Arizona, Inc. (United States)
Aral Aktiengesellschaft (Germany)
Aral Luxembourg S.A. (Luxembourg)
Aral Mineralölvertrieb GmbH (Germany)
Aral Services Luxembourg Sarl (Luxembourg)
Aral Tankstellen Services Sarl (Luxembourg)
Aral Vertrieb GmbH (Germany)
ARCO British International, Inc. (United States)
ARCO British Limited, LLC (United States)
ARCO Coal Australia Inc. (United States)
Arco do Brasil Ltda. (Brazil)
ARCO El-Djazair Holdings Inc. (United States)
ARCO El-Djazair LLC (United States)d
ARCO Environmental Remediation, L.L.C. (United States)
ARCO Exploration, Inc. (United States)
ARCO Gaviota Company (United States)
ARCO Ghadames Inc. (United States)
ARCO International Investments Inc. (United States)
ARCO International Services Inc. (United States)
ARCO Material Supply Company (United States)
ARCO Midcon LLC (United States)
ARCO Neftegaz Holdings, Inc. (United States)
ARCO Oil Company Nigeria Unlimited (Nigeria)d
ARCO Oman Inc. (Bahamas)
ARCO Products Company (United States)
ARCO Resources Limited (Australia)
ARCO Terminal Services Corporation (United States)
ARCO Trinidad Exploration and Production Company Limited (Bahamas)
ARCO Unimar Holdings LLC (United States)
Aspac Lubricants (Malaysia) Sdn. Bhd. (Malaysia, 63.03%)
Atlantic 2/3 UK Holdings Limited (United Kingdom)
Atlantic Richfield Company (United States)e
Auwahi Wind Energy Holdings LLC (United States)d
B.V. Petrotank (Netherlands)
Bahia de Bizkaia Electridad, S.L. (Spain, 75.00%)
Baltimore Ennis Land Company, Inc. (United States)
Barrington Amsterdam Terminal B.V (Netherlands)
Black Lake Pipe Line Company (United States)
BP - Castrol (Thailand) Limited (Thailand, 57.56%)
BP (Abu Dhabi) Limited (United Kingdom)
BP (Barbados) Holding SRL (Barbados)
BP (Barbican) Limited (United Kingdom)f
BP (China) Holdings Limited (China)
BP (China) Industrial Lubricants Limited (China)
BP (Gibraltar) Limited (United Kingdom)g
BP (Indian Agencies) Limited (United Kingdom)f
BP (Shanghai) Trading Limited (China)
BP Africa Limited (United Kingdom)f
BP Akaryakit Ortakligi (Turkey, 70.00%)c
BP Alaska LNG LLC (United States)
BP Alternative Energy Holdings Limited (United Kingdom)
BP Alternative Energy International Limited (United Kingdom)
BP Alternative Energy North America Inc. (United States)
BP America Chembel Holding LLC (United States)
BP America Chemicals Company (United States)
BP America Foreign Investments Inc. (United States)
BP America Inc. (United States)h
BP America Limited (United Kingdom)
BP America Production Company (United States)
BP AMI Leasing, Inc. (United States)
BP Amoco Chemical Company (United States)
BP Amoco Chemical Holding Company (United States)
BP Amoco Chemical Indonesia Limited (United States)
BP Amoco Chemical Malaysia Holding Company (United States)
BP Amoco Chemical Singapore Holding Company (United States)
BP Amoco Exploration (Faroes) Limited (United Kingdom)
The parent company financial statements of BP p.l.c. on pages 196-213 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
208
BP Annual Report and Form 20-F 2015
15. Related undertakings of the group – continued
BP Amoco Exploration (In Amenas) Limited (United Kingdom)
BP Amoco Neighborhood Development Corporation (United States)
BP Angola (Block 18) B.V. (Netherlands)
BP Argentina Exploration Company (United States)
BP Aromatics Holdings Limited (United Kingdom)
BP Aromatics Limited (United Kingdom)
BP Aromatics Limited N.V. (Belgium)
BP Asia Limited (Hong Kong)
BP Asia Pacific (Malaysia) Sdn. Bhd. (Malaysia)
BP Asia Pacific Holdings Limited (United Kingdom)
BP Asia Pacific Pte Ltd (Singapore)f
BP Australia Capital Markets Limited (Australia)
BP Australia Employee Share Plan Proprietary Limited (Australia)
BP Australia Group Pty Ltd (Australia)a
BP Australia Investments Pty Ltd (Australia)
BP Australia Nominees Proprietary Limited (Australia)
BP Australia Pty Ltd (Australia)
BP Australia Shipping Pty Ltd (Australia)i
BP Australia Swaps Management Limited (United Kingdom)
BP Aviation A/S (Denmark)
BP Benevolent Fund Trustees Limited (United Kingdom)f
BP Berau Ltd. (United States)
BP Biocombustíveis S.A. (Brazil, 99.99%)
BP Bioenergia Campina Verde Ltda. (Brazil, 99.99%)d
BP Bioenergia Ituiutaba Ltda. (Brazil, 99.99%)d
BP Bioenergia Itumbiara S.A. (Brazil, 99.99%)
BP Bioenergia Tropical S.A. (Brazil, 99.97%)
BP Biofuels Advanced Technology Inc. (United States)
BP Biofuels Brazil Investments Limited (United Kingdom)
BP Biofuels Louisiana LLC (United States)
BP Biofuels North America LLC (United States)
BP Biofuels Trading Comércio, Importação e Exportação Ltda. (Brazil, 99.99%)
BP Biofuels UK Limited (United Kingdom)
BP Bomberai Ltd. (United States)
BP Brasil Investimentos Ltda (Brazil)
BP Brasil Ltda. (Brazil)
BP Brazil Tracking L.L.C. (United States)
BP Bulwer Island Pty Ltd (Australia)
BP Business Service Centre Asia Sdn Bhd (Malaysia)
BP Business Service Centre KFT (Hungary)d
BP Canada Energy Group ULC (Canada)
BP Canada Energy Marketing Corp. (United States)
BP Canada International Holdings B.V. (Netherlands)
BP Canada Investments Inc. (United States)
BP Capellen Sarl (Luxembourg)
BP Capital Euro V.O.F. (Belgium)
BP Capital Markets America Inc. (United States)
BP Capital Markets p.l.c. (United Kingdom)
BP Caplux S.A. (Luxembourg)
BP Car Finance Limited (United Kingdom)f
BP Caribbean Company (United States)
BP Castrol KK (Japan, 65.65%)
BP Castrol Lubricants (Malaysia) Sdn. Bhd. (Malaysia, 63.03%)
BP Chembel N.V. (Belgium)
BP Chemical US Sales Company (United States)
BP Chemicals (Korea) Limited (United Kingdom)
BP Chemicals East China Investments Limited (United Kingdom)
BP Chemicals France Holding (France)
BP Chemicals Investments Limited (United Kingdom)
BP Chemicals Limited (United Kingdom)
BP Chemicals Trading Limited (United Kingdom)
BP Chile Petrolera Limitada (Chile)
BP China Exploration and Production Company (United States)
BP China Limited (United Kingdom)f
BP Company North America Inc. (United States)j
BP Containment Response Limited (United Kingdom)
BP Containment Response System Holdings LLC (United States)
BP Continental Holdings Limited (United Kingdom)
BP Corporate Holdings Limited (United Kingdom)f
BP Corporation North America Inc. (United States)
BP Danmark A/S (Denmark)
BP Developments Australia Pty. Ltd. (Australia)
BP Dogal Gaz Ticaret Anonim Sirketi (Turkey)
BP East Kalimantan CBM Limited (United Kingdom)
BP East Kalimantan Limited (Bahamas)
BP Eastern Mediterranean Limited (United Kingdom)f
BP Egypt Company (United States)
BP Egypt East Delta Marine Corporation (Virgin Islands, British)
BP Egypt East Tanka B.V. (Netherlands)
BP Egypt Production B.V. (Netherlands)
BP Egypt Ras El Barr B.V. (Netherlands)
BP Egypt West Mediterranean (Block B) B.V. (Netherlands)
BP Energy Asia Pte. Limited (Singapore)
BP Energy Colombia Limited (United Kingdom)
BP Energy Company (United States)
BP Energy do Brasil Ltda. (Brazil)
BP Energy Europe Limited (United Kingdom)
BP Espana, S.A. Unipersonal (Spain)
BP Europa SE (Germany)k, l
BP Exploracion de Venezuela S.A. (Venezuela, Bolivarian Republic of)
BP Exploration & Production Inc. (United States)m
BP Exploration (Alaska) Inc. (United States)
BP Exploration (Algeria) Limited (United Kingdom)
BP Exploration (Alpha) Limited (United Kingdom)
BP Exploration (Angola) Limited (United Kingdom)
BP Exploration (Azerbaijan) Limited (United Kingdom)
BP Exploration (Canada) Limited (United Kingdom)
BP Exploration (Caspian Sea) Limited (United Kingdom)
BP Exploration (Delta) Limited (United Kingdom)
BP Exploration (El Djazair) Limited (Bahamas)
BP Exploration (Epsilon) Limited (United Kingdom)
BP Exploration (Finance) Limited (United Kingdom)
BP Exploration (Greenland) Limited (United Kingdom)
BP Exploration (Morocco) Limited (United Kingdom)
BP Exploration (Namibia) Limited (United Kingdom)
BP Exploration (Nigeria Finance) Limited (United Kingdom)
BP Exploration (Nigeria) Limited (Nigeria)
BP Exploration (Shafag-Asiman) Limited (United Kingdom)
BP Exploration (Shah Deniz) Limited (United Kingdom)
BP Exploration (South Atlantic) Limited (United Kingdom)
BP Exploration (Vietnam) Limited (United Kingdom)
BP Exploration (Xazar) PTE. LTD. (Singapore)
BP Exploration Angola (Kwanza Benguela) Limited (United Kingdom)
BP Exploration Australia Pty Ltd (Australia)
BP Exploration Beta Limited (United Kingdom)
BP Exploration China Limited (United Kingdom)
BP Exploration Company (Middle East) Limited (United Kingdom)
BP Exploration Company Limited (United Kingdom)
BP Exploration do Brasil Ltda (Brazil)
BP Exploration Indonesia Limited (United Kingdom)
BP Exploration Libya Limited (United Kingdom)
BP Exploration Mexico Limited (United Kingdom)
BP Exploration Mexico, S.A. de C.V. (Mexico)
BP Exploration North Africa Limited (United Kingdom)
BP Exploration Operating Company Limited (United Kingdom)
BP Exploration Orinoco Limited (United Kingdom)
BP Exploration Personnel Company Limited (United Kingdom)
BP Exploration Services Limited (In Liquidation) (United Kingdom)
BP Exploration Venezuela Limited (In Liquidation) (United Kingdom)
BP Express Shopping Limited (United Kingdom)
BP Finance Australia Pty Ltd (Australia)
BP Finance p.l.c. (United Kingdom)
BP Foundation Incorporated (United States)
BP France (France)
BP Fuels & Lubricants AS (Norway)
BP Fuels Deutschland GmbH (Germany)
BP Gas Europe, S.A.U. (Spain)
BP Gas Marketing Limited (United Kingdom)
BP Gas Supply (Angola) LLC (United States)
BP Gaz Anonim Sirketi (Turkey)
BP Gelsenkirchen GmbH (Germany)
BP Ghana Limited (Ghana)
BP Global Investments Limited (United Kingdom)f
BP Global Investments Salalah & Co LLC (Oman)d
BP Global West Africa Limited (Nigeria)
BP Greece Limited (United Kingdom)
BP Guangdong Limited (China, 90.00%)
BP High Density Polyethylene France - BP HDPE (France)
BP Holdings (Thailand) Limited (Thailand, 81.01%)
BP Holdings B.V. (Netherlands)
BP Holdings Canada Limited (United Kingdom)f
BP Holdings International B.V. (Netherlands)
BP Holdings North America Limited (United Kingdom)f
BP Hong Kong Limited (Hong Kong)
BP India Services Private Limited (India)
BP Indonesia Investment Limited (United Kingdom)
BP International Limited (United Kingdom)f
BP International Services Company (United States)
BP Investment Management Limited (United Kingdom)
BP Investments Asia Limited (United Kingdom)
BP Iran Limited (United Kingdom)
BP Iraq N.V. (Belgium)
BP Italia SpA (Italy)
BP Japan K.K. (Japan)
BP Kapuas I Limited (United Kingdom)
BP Kapuas II Limited (United Kingdom)
BP Kapuas III Limited (United Kingdom)
BP Korea Limited (Korea, Republic of)
BP Kuwait Limited (United Kingdom)
BP Latin America LLC (United States)
BP Lesotho (Pty) Limited (Lesotho)f
BP Lingen GmbH (Germany)
BP LNG Shipping Limited (Bermuda)
BP Lubes Marketing GmbH (Germany)
BP Lubricants KK (Japan, 65.65%)
BP Lubricants USA Inc. (United States)
BP Luxembourg S.A. (Luxembourg)
BP Malaysia Holdings Sdn. Bhd. (Malaysia, 70.00%)
BP Malta Limited (Malta)f
BP Management International B.V. (Netherlands)
The parent company financial statements of BP p.l.c. on pages 196-213 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 2015
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15. Related undertakings of the group – continued
BP Management Netherlands B.V. (Netherlands)
BP Marine Limited (United Kingdom)
BP Maritime Services (Isle of Man) Limited (Isle of Man)
BP Maritime Services (Singapore) Pte. Limited (Singapore)
BP Marketing Egypt LLC (Egypt)
BP Mauritius Limited (Mauritius)
BP Middle East Enterprises Corporation (Virgin Islands, British)
BP Middle East Limited (United Kingdom)f
BP Middle East LLC (United Arab Emirates)
BP Mocambique Limitada (Mozambique)
BP Mocambique Limited (United Kingdom)
BP Muturi Holdings B.V. (Netherlands)
BP Nederland Holdings BV (Netherlands)
BP Netherlands Exploration Holding B.V. (Netherlands)
BP New Zealand Holdings Limited (New Zealand)
BP New Zealand Share Scheme Limited (New Zealand)
BP Norge AS (Norway)
BP Nutrition Inc. (United States)
BP Offshore Gathering Systems Inc. (United States)
BP Offshore Pipelines Inc. (United States)
BP Offshore Response Company LLC (United States)
BP Oil (Thailand) Limited (Thailand)n
BP Oil and Chemicals International Philippines Inc. (Philippines)
BP Oil Australia Pty Ltd (Australia)
BP Oil Espana, S.A. Unipersonal (Spain)
BP Oil Hellenic S.A. (Greece)
BP Oil International Limited (United Kingdom)
BP Oil Kent Refinery Limited (in liquidation) (United Kingdom)
BP Oil Llandarcy Refinery Limited (United Kingdom)
BP Oil Logistics UK Limited (United Kingdom)
BP Oil Marketing GmbH (Germany)
BP Oil New Zealand Limited (New Zealand)
BP Oil Pipeline Company (United States)
BP Oil Shipping Company, USA (United States)
BP Oil UK Limited (United Kingdom)
BP Oil Venezuela Limited (United Kingdom)
BP Oil Vietnam Limited (United Kingdom)
BP Oil Yemen Limited (United Kingdom)
BP Olex Fanal Mineralol GmbH (Germany)
BP Pacific Investments Ltd (New Zealand)
BP Pakistan (Badin) Inc. (United States)
BP Pakistan Exploration and Production, Inc. (United States)
BP Pension Trustees Limited (United Kingdom)f
BP Pensions (Overseas) Limited (Guernsey)f
BP Pensions Limited (United Kingdom)f
BP Petrochemicals India Investments Limited (United Kingdom)
BP Petroleo y Gas, S.A. (Venezuela, Bolivarian Republic of)
BP Petrolleri Anonim Sirketi (Turkey)o
BP Pipelines (Alaska) Inc. (United States)
BP Pipelines (BTC) Limited (United Kingdom)
BP Pipelines (North America) Inc. (United States)
BP Pipelines (SCP) Limited (United Kingdom)
BP Pipelines (TANAP) Limited (United Kingdom)
BP Polska Services Sp. z o.o. (Poland)
BP Portugal-Comercio de Combustiveis e Lubrificantes SA (Portugal)
BP Poseidon Limited (United Kingdom)
BP Products North America Inc. (United States)
BP Properties Limited (United Kingdom)f
BP Raffinaderij Rotterdam B.V. (Netherlands)
BP Refinery (Kwinana) Proprietary Limited (Australia)
BP Refining & Petrochemicals GmbH (Germany)
BP Regional Australasia Holdings Pty Ltd (Australia)
BP Russian Investments Limited (United Kingdom)
BP Services International Limited (United Kingdom)
BP Shafag-Asiman Limited (United Kingdom)
BP Sharjah Limited (In Liquidation) (United Kingdom)
BP Shipping Limited (United Kingdom)
BP Singapore Pte. Limited (Singapore)
BP Solar Energy North America LLC (United States)
BP Solar Espana, S.A. Unipersonal (Spain)
BP Solar International Inc. (United States)
BP Solar Pty Ltd (Australia)
BP South East Asia Limited (United Kingdom)f
BP Southern Africa Proprietary Limited (South Africa, 75.00%)
BP Southern Cone Company (United States)
BP Subsea Well Response (Brazil) Limited (United Kingdom)
BP Subsea Well Response Limited (United Kingdom)
BP Sutton Limited (In Liquidation) (United Kingdom)
BP Taiwan Marketing Limited (Taiwan)
BP Tanjung IV Limited (United Kingdom)
BP Technology Ventures Inc. (United States)
BP Toplivnaya Kompanya LLC (Russian Federation)
BP Trade and Supply (Germany) GmbH,Hamburg (Germany)
BP Trading Limited (United Kingdom)f
BP Train 2/3 Holding SRL (Barbados)
BP Transportation (Alaska) Inc. (United States)
BP Trinidad and Tobago LLC (United States, 70.00%)
BP Trinidad Processing Limited (Trinidad and Tobago)
BP Turkey Refining Limited (United Kingdom)f
BP Venezuela Investments B.V. (Netherlands)
BP West Aru I Limited (United Kingdom)
BP West Aru II Limited (United Kingdom)
BP West Coast Products LLC (United States)
BP West Papua I Limited (United Kingdom)
BP West Papua III Limited (United Kingdom)
BP Wind Energy North America Inc. (United States)
BP Wiriagar Ltd. (United States)
BP World-Wide Technical Services Limited (United Kingdom)
BP Zhuhai Chemical Company Limited (China, 85.00%)
BP+Amoco International Limited (United Kingdom)f
BPA Investment Holding Company (United States)
BPNE International B.V. (Netherlands)
BPRY Caribbean Ventures LLC (United States, 70.00%)
Brian Jasper Nominees Pty Ltd (Australia)
Britannic Energy Trading Limited (United Kingdom)
Britannic Investments Iraq Limited (United Kingdom)
Britannic Strategies Limited (United Kingdom)
Britannic Trading Limited (United Kingdom)
British Pipeline Agency Limited (United Kingdom, 50.00%)p q
Britoil Limited (United Kingdom)
BTC Pipeline Holding Company Limited (United Kingdom)
Burmah Castrol Australia Pty Ltd (Australia)r
Burmah Castrol Holdings Inc. (United States)
Burmah Castrol PLC (United Kingdom)f
Burmah Castrol South Africa (Pty) Limited (South Africa)
Burmah Chile S.A. (Chile)
Burmah Fuels Australia Pty Ltd (Australia)
BXL Plastics Limited (United Kingdom)
Cadman DBP Limited (United Kingdom)
Cape Vincent Wind Power, LLC (United States)
Casitas Pipeline Company (United States)
Castrol (China) Limited (Hong Kong)
Castrol (Ireland) Limited (Ireland)
Castrol (Shenzhen) Company Limited (China)
Castrol (Switzerland) AG (Switzerland)
Castrol (U.K.) Limited (United Kingdom)
Castrol Australia Pty. Limited (Australia)
CASTROL Austria GmbH (Austria)
Castrol B.V. (Netherlands)
Castrol BP Petco Limited Liability Company (Vietnam, 65.00%)
Castrol Brasil Ltda. (Brazil)
Castrol Caribbean & Central America Inc. (United States)
Castrol Colombia Limitada (Colombia)
Castrol Del Peru S.A. (Peru, 99.49%)
Castrol Hungária Trading Co. Ltd. (Castrol Hungária Kereskedelmi Kft) (Hungary)d
Castrol India Limited (India, 71.03%)
Castrol Industrial North America Inc. (United States)
Castrol Industrie und Service GmbH (Germany)
Castrol KK (Japan, 65.65%)
Castrol Limited (United Kingdom)
Castrol Lubricants (CR), s.r.o. (Czech Republic)
Castrol Lubricants RO S.R.L (Romania)
Castrol Mexico, S.A. de C.V. (Mexico)
Castrol Offshore Limited (United Kingdom)
Castrol Pakistan (Private) Limited (Pakistan)
Castrol Philippines, Inc. (Philippines)
Castrol Servicos Ltda. (Brazil)
Castrol Slovensko, s.r.o. (Slovakia)
Castrol South Africa Proprietary Limited (South Africa)
Castrol Ukraine LLC (Ukraine)d
Castrol Zimbabwe (Private) Limited (Zimbabwe)
Centrel Pty Ltd (Australia)
CH-Twenty Holdings LLC (United States)
CH-Twenty, Inc. (United States)
Clarisse Holdings Pty Ltd (Australia)
Coastwise Trading Company, Inc. (United States)
Consolidada de Energia y Lubricantes, (CENERLUB) C.A. (Venezuela, Bolivarian
Republic of)
Conti Cross Keys Inn, Inc. (United States)
Coro Trading NZ Limited (New Zealand)
Cuyama Pipeline Company (United States)
Delta Housing Inc. (United States)
Dermody Developments Pty Ltd (Australia)
Dermody Holdings Pty Ltd (Australia)
Dermody Investments Pty Ltd (Australia)
Dermody Petroleum Pty. Ltd. (Australia)
Dolvik Utvikling AS (Norway)
Dome Beaufort Petroleum Limited (Canada)
Dome Beaufort Petroleum Limited (March 1980) Limited Partnership (Canada)c
Dome Beaufort Petroleum Limited 1979 Partnership No. 1 (Canada)c
Dome Wallis (1980) Limited Partnership (Canada, 92.50%)c
Dradnats, Inc. (United States)
Duckhams Oils (Thailand) Company Limited (Thailand, 50.42%)
ECM Markets SA (Pty) Ltd (South Africa, 75.00%)
Edom Hills Project 1, LLC (United States)
Elite Customer Solutions Pty Ltd (Australia)
Elm Holdings Inc. (United States)
Energy Caspian Corporation (Virgin Islands, British)a
Energy Global Investments (USA) Inc. (United States)
Enstar LLC (United States)
The parent company financial statements of BP p.l.c. on pages 196-213 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
210
BP Annual Report and Form 20-F 2015
PT Cakrawala Tata Sentosa (Indonesia, 68.03%)
PT Castrol Indonesia (Indonesia, 68.30%)
PT Jasatama Petroindo (Indonesia)
RB Raffinerie GmbH (Germany)
Reading Investment (Nominee) Limited (United Kingdom)
Reax Industria e Comercio Ltda. (Brazil)
Remediation Management Services Company (United States)
Richfield Oil Corporation (United States)
Rolling Thunder I Power Partners, LLC (United States)
Ropemaker Deansgate Limited (United Kingdom)
Ropemaker Properties Limited (United Kingdom)
Ruehl Gesellschaft m.b.H. & Co KG. (Austria)c
Rural Fuel Limited (New Zealand)
Saturn Insurance Inc. (United States)
Setra Lubricants (Russian Federation)
Setra Lubricants Kazakhstan LLP (Kazakhstan)c
Sherbino I Holdings LLC (United States)
Sherbino II Wind Farm LLC (United States)
Sherbino Mesa I Land Investments LLC (United States)
Shine Top International Investment Limited (Hong Kong)
Silver Star I Power Partners, LLC (United States)
Sociedade de Promocao Imobiliaria Quinta do Loureiro, SA (Portugal)
Société de Gestion de Dépots d’Hydrocarbures - GDH (France)
SOFAST Limited (Thailand)t
Southeast Texas Biofuels LLC (United States)
Southern Ridge Pipeline Holding Company (United States)
Southern Ridge Pipeline LP LLC (United States)
SRHP (France, 99.99%)
Standard Oil Company, Inc. (United States)
Taradadis Pty. Ltd. (Australia)
TEA Comercio E Participacoes Ltda. (Brazil)
Telcom General Corporation (United States, 99.96%)
Terrapin Creek Wind Energy LLC (United States)
Terre de Grace Partnership (Canada, 75.00%)
The Anaconda Company (United States)
The BP Share Plans Trustees Limited (United Kingdom)f
The Burmah Oil Company (Pakistan Trading) Limited (United Kingdom)
The Standard Oil Company (United States)
TJKK (Japan)
TOC-Rocky Mountains Inc. (United States)
Toledo Refinery Holding Company LLC (United States)
Trinity Hills Wind Farm LLC (United States)
TSG Polska Spolka z ograniczona odpowiedzialnocia (Poland)
TSG Tankstellen Support GmbH (Germany)
Union Texas International Corporation (United States)
UT Petroleum Services, LLC (United States)
Vastar Energy, Inc. (United States)
Vastar Gas Marketing, Inc. (United States)
Vastar Holdings, Inc. (United States)
Vastar Pipeline, LLC (United States)
Vastar Power Marketing, Inc. (United States)
Verano Collateral Holdings LLC (United States)
Viceroy Investments Limited (United Kingdom)
VTA Verfahrenstechnik und Automatisierung GmbH (Germany)
Warrenville Development Ltd. Partnership (United States)c
Water Way Trading and Petroleum Services LLC (Iraq)
Welchem, Inc. (United States)
West Kimberley Fuels Pty Ltd (Australia)
Westlake Houston Development, LLC (United States)
Whiting Clean Energy, Inc. (United States)
Windpark Energy Nederland B.V. (Netherlands)
ZAO Baltic Petroleum (Russian Federation)
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15. Related undertakings of the group – continued
ESJ US Holdings LLC (United States)
Europa Oil NZ Limited (New Zealand)
Exomet, Inc. (United States)
Expandite Contract Services Limited (United Kingdom)
Exploration (Luderitz Basin) Limited (United Kingdom)
Exploration Service Company Limited (United Kingdom)
F&H Pipeline Company (United States)
Flat Ridge 2 Holdings LLC (United States)
Flat Ridge Wind Energy, LLC (United States)
Foseco Chile Ltda. (Chile)
Foseco Holding International B.V. (Netherlands)
Foseco Holding, Inc. (United States)
Foseco, Inc. (United States)
Fosroc Expandite Limited (United Kingdom)
Fosven, CA (Venezuela, Bolivarian Republic of)
Fowler Ridge Holdings LLC (United States)
Fowler Ridge I Land Investments LLC (United States)
Fowler Ridge II Holdings LLC (United States)
Fowler Ridge III Wind Farm LLC (United States)
FreeBees B.V. (Netherlands)
Fuel & Retail Aviation Sweden AB (Sweden)
Fuelplane-Sociedade Abastecedora de Aeronaves, Unipessoal, Lda (Portugal)
Gardena Holdings Inc. (United States)
Gasolin GmbH (Germany)
Gasolinera Industrial S.L. (Spain)
GOAM 1 S A S (Colombia)
GOMH Holdings, Inc. (United States)
Grampian Aviation Fuelling Services Limited (United Kingdom)
Grangemouth Holdings Limited (United Kingdom)
Grangemouth Properties Limited (United Kingdom)
Guangdong Investments Limited (United Kingdom)
HAM Fuel & Retail Aviation Deutschland GmbH (Germany)
Highlands Ethanol, LLC (United States)
Hydrogen Energy International Limited (United Kingdom)
IGI Resources, Inc. (United States)
International Card Centre Limited (United Kingdom)
Iraq Petroleum Company Limited (United Kingdom)
J & A Petrochemical Sdn. Bhd. (Malaysia)
Jupiter Insurance Limited (Guernsey)
Kabulonga Properties Limited (Zambia)
Ken-Chas Reserve Company (United States)
Kenilworth Oil Company Limited (United Kingdom)f
Korea Energy Investment Holdings B.V. (Netherlands)
Latin Energy Argentina S.A. (Argentina)
Lebanese Aviation Technical Services S.A.L. (Lebanon, 99.70%)
Lubricants UK Limited (United Kingdom)
Mardi Gras Endymion Oil Pipeline Company, LLC (United States)
Mardi Gras Transportation System Inc. (United States)
Markoil, S.A. Unipersonal (Spain)
Masana Petroleum Solutions (Pty) Ltd (South Africa)q s
Mayaro Initiative for Private Enterprise Development (Trinidad and Tobago, 70.00%)d
Mehoopany Holdings LLC (United States)
Mes Tecnologia en Servicios y Energia, S.A. de C.V. (Mexico)
Minza Pty. Ltd. (Australia)
Mountain City Remediation, LLC (United States)
No. 1 Riverside Quay Proprietary Limited (Australia)
Nordic Lubricants A/S (Denmark)
Nordic Lubricants AB (Sweden)
Nordic Lubricants Oy (Finland)
North America Funding Company (United States)
Oelwerke Julius Schindler GmbH (Germany)
OMD87, Inc. (United States)
Omega Oil Company (United States)
Orion Delaware Mountain Wind Farm LP (United States)c
Orion Energy Holdings, LLC (United States)
Orion Energy L.L.C. (United States)
Orion Post Land Investments, LLC (United States)
Pacroy (Thailand) Co., Ltd. (Thailand, 39.00%)q
Pan American Petroleum Company of California (United States)
Pan American Petroleum Corporation (United States)
Peaks America Inc. (United States)
Pearl River Delta Investments Limited (United Kingdom)
Phoenix Petroleum Services, Limited Liability Company (Iraq)
PHP Construction Holdings, Inc. (United States)
PHP Trading Holdings, Inc. (United States)
Products Cogeneration Company (United States)
Produits Métallurgie Doittau SA - PROMEDO (France)
ProGas Limited (Canada)
ProGas U.S.A., Inc. (United States)
Prospect International, C.A. (Venezuela, Bolivarian Republic of, 99.90%)
PT BP Petrochemicals Indonesia (Indonesia)
The parent company financial statements of BP p.l.c. on pages 196-213 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 2015
211
15. Related undertakings of the group – continued
Related undertakings other than subsidiaries
A Flygbranslehantering AB (AFAB) (Sweden, 50.00%)
ABG Autobahn-Betriebe GmbH (Austria, 32.58%)
Abu Dhabi Marine Areas Limited (United Kingdom, 33.33%)p
Abu Dhabi Petroleum Company Limited (United Kingdom, 23.75%)
AFCO AB (Sweden, 33.33%)
AGES International GmbH & Co. KG, Langenfeld (Germany, 24.70%)c
AGES Maut System GmbH & Co. KG, Langenfeld (Germany, 24.70%)c
Air BP Copec S.A. (Chile, 51.00%)
Air BP Italia Spa (Italy, 50.00%)
Air BP Petrobahia Ltda. (Brazil, 50.00%)
Aircraft Fuel Supply B.V. (Netherlands, 28.57%)
Aircraft Refuelling Company GmbH (Austria, 33.33%)
Airport Fuel Services Pty. Limited (Australia, 20.00%)
Alaska Tanker Company, LLC (United States, 25.00%)
Alyeska Pipeline Service Company (United States, 48.44%)
Ambarli Depolama Hizmetleri Limited Sirketi (Turkey, 50.00%)
Ammenn GmbH (Germany, 50.00%)
Amoco Bolivia Oil and Gas Aktiebolag (Sweden, 60.00%)
Arabian Production and Marketing Lubricants Company (Saudi Arabia, 50.00%)
ARCO Solar Nigeria Ltd. (Nigeria, 40.00%)
Asian Acetyls Co., Ltd (Korea, Republic of, 34.00%)
ATAS Anadolu Tasfiyehanesi Anonim Sirketi (Turkey, 68.00%)
Atlantic 1 Holdings LLC (United States, 34.00%)
Atlantic 2/3 Holdings LLC (United States, 42.50%)
Atlantic 4 Holdings LLC (United States, 37.78%)
Atlantic LNG 2/3 Company of Trinidad and Tobago Unlimited (Trinidad and Tobago,
42.50%)
Atlantic LNG 4 Company of Trinidad and Tobago Unlimited (Trinidad and Tobago, 37.78%)
Atlantic LNG Company of Trinidad and Tobago (Trinidad and Tobago, 34.00%)
Atlas Methanol Company Unlimited (Trinidad and Tobago, 36.90%)
Australasian Lubricants Manufacturing Company Pty Ltd (Australia, 50.00%)
Australian Terminal Operations Management Pty Ltd (Australia, 50.00%)
Auwahi Holdings, LLC (United States, 50.00%)d
Aviation Fuel Services Limited (United Kingdom, 25.00%)
Azerbaijan Gas Supply Company Limited (Cayman Islands, 23.06%)p
Azerbaijan International Operating Company (Cayman Islands, 40.50%)u
Baku-Tbilisi-Ceyhan Pipeline Finance B.V. (Netherlands, 30.10%)
Baku-Tbilisi-Ceyhan Pipeline Holding B.V. (Netherlands, 30.10%)
Bayernoil Raffineriegesellschaft mbH (Germany, 22.50%)
Beer GmbH (Germany, 50.00%)
Beer GmbH & Co. Mineralol-Vertriebs-KG (Germany, 50.00%)c
BGFH Betankungs-Gesellschaft Frankfurt-Hahn GbR (Germany, 50.00%)c
Black Hill Industrial Estate Limited (United Kingdom, 49.00%)
Blendcor (Pty) Limited (South Africa, 37.50%)
BP Dhofar LLC (Oman, 49.00%)
BP Guangzhou Development Oil Product Co., Ltd (China, 40.00%)
BP India Limited (India, 51.00%)
BP PetroChina Petroleum Co., Ltd (China, 49.00%)
BP Petronas Acetyls Sdn. Bhd. (Malaysia, 70.00%)
BP Sinopec (ZheJiang) Petroleum Co., Ltd (China, 40.00%)
BP Sinopec Marine Fuels Pte. Ltd. (Singapore, 50.00%)
BP YPC Acetyls Company (Nanjing) Limited (China, 50.00%)
BP-Husky Refining LLC (United States, 50.00%)
BP-Japan Oil Development Company Limited (United Kingdom, 50.00%)
Braendstoflageret Kobenhavns Lufthavn I/S (Denmark, 33.33%)c
BTC International Investment Co. (Cayman Islands)v
Butamax™ Advanced Biofuels LLC (United States, 50.00%)
Caesar Oil Pipeline Company, LLC (United States, 56.00%)
Cairns Airport Refuelling Service Pty Ltd (Australia, 25.00%)
Cantera K-3 Limited Partnership (United States, 39.00%)c
Castrol Cuba S.A. (Cuba, 50.00%)
Castrol DongFeng Lubricant Co., Ltd (China, 50.00%)
CCWE Holdings LLC (United States, 33.33%)
Cedar Creek II Holdings LLC (United States, 50.00%)
Cedar Creek II, LLC (United States, 50.00%)
Cedar Creek Wind Energy, LLC (United States, 33.33%)
Cekisan Depolama Hizmetleri Limited Sirketi (Turkey, 35.00%)
Central African Petroleum Refineries (Pvt) Ltd (Zimbabwe, 20.75%)
Chicap Pipe Line Company (United States, 56.17%)
China American Petrochemical Company, Ltd. (CAPCO) (Taiwan, 61.36%)
China Aviation Oil (Singapore) Corporation Ltd (Singapore, 20.03%)
Cleopatra Gas Gathering Company, LLC (United States, 54.00%)
Coastal Oil Logistics Limited (New Zealand, 25.00%)
Combined Refuelling Service VOF (Netherlands, 25.00%)
Compania de Inversiones El Condor Limitada (Chile, 99.00%)
Concessionaria Stalvedro SA (Switzerland, 50.00%)
CSG Convenience Service GmbH (Germany, 24.80%)
Cypress Pipeline Company, L.L.C. (United States, 50.00%)
Danish Refuelling Service I/S (Denmark, 33.33%)c
Danish Tankage Services I/S (Denmark, 50.00%)c
Destin Pipeline Company, L.L.C. (United States, 66.67%)
DHC Solvent Chemie GmbH (Germany, 50.00%)
Dinarel S.A. (Uruguay, 24.00%)
Direct Fuels Limited (New Zealand, 30.07%)
Dusseldorf Fuelling Services GbR (Germany, 33.00%)c
Dusseldorf Tank Services GbR (Germany, 33.00%)c
East Tanka Petroleum Company “ETAPCO” (Egypt, 50.00%)
Ekma Oil Company “EKMA” (Egypt, 50.00%)
El Temsah Petroleum Company “PETROTEMSAH” (Egypt, 25.00%)
EMDAD Aviation Fuel Storage FZCO (United Arab Emirates, 33.00%)
Emoil Storage Company FZCO (United Arab Emirates, 20.00%)
Endymion Oil Pipeline Company, LLC (United States, 75.00%)
Energenomics LLC (United States, 50.00%)
Energy Emerging Investments, LLC (United States, 60.00%)
Entrepot petrolier de Chambery (France, 32.00%)
Entrepoˆ t Pe´ trolier de Puget sur Argens-EPPA (France, 58.25%)
Erdol-Lagergesellschaft m.b.H. (Austria, 23.00%)
Eroil Mineraloel GmbH-Diehl (Germany, 50.00%)
Esma Petroleum Company “ESMA” (Egypt, 50.00%)
Estonian Aviation Fuelling Services (Estonia, 49.00%)
Etzel-Kavernenbetriebsgesellschaft mbH & Co. KG (Germany, 33.00%)c
Etzel-Kavernenbetriebs-Verwaltungsgesellschaft mbH (Germany, 33.33%)c
FFS Frankfurt Fuelling Services (GmbH & Co.) OHG (Germany, 33.00%)c
Fibil SA (Switzerland, 50.00%)
Fip Verwaltungs GmbH (Germany, 50.00%)
Flat Ridge 2 Wind Energy LLC (United States, 50.00%)
Flat Ridge 2 Wind Holdings LLC (United States, 50.00%)
Flughafen Hannover Pipeline Verwaltungsgesellschaft mbH (Germany, 50.00%)
Flughafen Hannover Pipelinegesellschaft mbH & Co. KG (Germany, 50.00%)
Flytanking AS (Norway, 50.00%)
Foreseer Ltd (United Kingdom, 25.00%)
Formosa BP Chemicals Corporation (Taiwan, 50.00%)
Fowler I Holdings LLC (United States, 50.00%)
Fowler II Holdings LLC (United States, 50.00%)
Fowler Ridge II Wind Farm LLC (United States, 50.00%)
Fowler Ridge Wind Farm LLC (United States, 50.00%)
Fuelling Aviation Service-FAS (France, 50.00%)d
Fundacio´ n para la Eficiencia Energe´ tica de la Comunidad Valenciana (Spain,
33.33%)d
Gardermeon Fuelling Services AS (Norway, 33.33%)
Georg Reitberger Mineralole GmbH & Co. KG (Germany, 50.00%)c
Georg Reitberger Mineralo¨ le Verwaltungs GmbH (Germany, 50.00%)c
Georgian Pipeline Company (Cayman Islands, 40.50%)u
Gezamenlijke Tankdienst Schiphol B.V. (Netherlands, 50.00%)
GISSCO S.A. (Greece, 50.00%)
GlobeFuel Systems & Services GmbH (Germany, 33.00%)
Goshen Phase II LLC (United States, 50.00%)
Gothenburgh Fuelling Company AB (GFC) (Sweden, 33.33%)
Gravcap, Inc. (United States, 25.00%)
Groupement Pe´ trolier de Saint Pierre des Corps-GPSPC (France, 20.00%)
Groupement Pe´ trolier de Strasbourg (France, 33.33%)
Groupement pour l’Avitaillement de Lyon Saint-Exupe´ ry-GALYS (France, 39.93%)d
Guangdong Dapeng LNG Company Limited (China, 30.00%)
Gulf Of Suez Petroleum Company “GUPCO” (Egypt, 50.00%)
GVO¨ Gebinde-Verwertungsgesellschaft der Mineralo¨ lwirtschaft mbH (Germany,
21.00%)
H & G Contracting Services Limited (United Kingdom, 33.50%)
Hamburg Tank Service (HTS) GbR (Germany, 33.00%)c
Havacilik Yakit Ikmali Operasyon Ortakligi (Turkey, 25.00%)c
Heinrich Fip GmbH & Co. KG (Germany, 50.00%)c
Heliex Power Limited (United Kingdom, 32.40%)m
HFS Hamburg Fuelling Services GbR (Germany, 25.00%)c
Hiergeist Heizolhandel GmbH & Co. KG (Germany, 50.00%)c
Hiergeist Verwaltung GmbH (Germany, 50.00%)
Hydrogen Energy International LLC (United States, 50.00%)
In Salah Gas Ltd (Jersey, 25.50%)
In Salah Gas Services Ltd (Jersey, 25.50%)
Independent Petroleum Laboratory Limited (New Zealand, 41.52%)
India Gas Solutions Private Limited (India, 50.00%)
Iraq Petroleum Company, Limited (In Liquidation) (United Kingdom, 23.75%)
Jamaica Aircraft Refuelling Services Limited (Jamaica, 51.00%)
Kingston Research Limited (United Kingdom, 50.00%)
Klaus Ko¨ hn GmbH (Germany, 50.00%)
Ko¨ hn & Plambeck GmbH & Co. KG (Germany, 50.00%)
Kurt Ammenn GmbH & Co. KG (Germany, 50.00%)c
LFS Langenhagen Fuelling Services GbR (Germany, 50.00%)c
Lotos-Air BP Polska Spo´ łka z ograniczon a˛ odpowiedzialno s´ cia˛ (Poland, 50.00%)
Maatschap Europoort Terminal (Netherlands, 25.00%)
Mach Monument Aviation Fuelling Co. Ltd. (Iraq, 70.00%)
Malmo Fuelling Services AB (Sweden, 33.33%)
Manchester Airport Storage and Hydrant Company Limited (United Kingdom,
25.00%)
Mars Oil Pipeline Company (United States, 28.50%)
MATELUB S.A.R.L. (Baldersheim/Frankreich) (France, 80.00%)
McFall Fuel Limited (New Zealand, 30.07%)
Mediteranean Gas Co. “MEDGAS” (Egypt, 25.00%)
Mehoopany Wind Energy LLC (United States, 50.00%)
Mehoopany Wind Holdings LLC (United States, 50.00%)
Middle East Lubricants Company LLC (United Arab Emirates, 29.33%)
Milne Point Pipeline, LLC (United States, 50.00%)
Mineralol-Handels-Gesellschaft mbH, Celle (Germany, 50.00%)
Mobene GmbH & Co. KG (Germany, 50.00%)c
Mobene Verwaltungs-GmbH (Germany, 50.00%)
N.V. Rotterdam-Rijn-Pijpleiding Maatschappij (RRP) (Netherlands, 33.33%)
The parent company financial statements of BP p.l.c. on pages 196-213 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
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Shell and BP South African Petroleum Refineries (Pty) Ltd (South Africa, 37.50%)
Shell Mex and B.P. Limited (United Kingdom, 40.00%)
Shell-Statoil Refuelling (Billund) I/S (Denmark, 50.00%)
Shenzhen Cheng Yuan Aviation Oil Company Limited (China, 25.00%)
Shenzhen Dapeng LNG Marketing Company Limited (China, 30.00%)
Sherbino I Wind Farm LLC (United States, 50.00%)
SKA Energy Holdings Limited (United Arab Emirates, 50.00%)
Socie´ te´ d’Avitaillement et de Stockage de Carburants Aviation “SASCA” (France,
40.00%)
Socie´ te´ de Gestion de Produits Pe´ troliers-SOGEPP (France, 37.00%)
Socie´ te´ de Participations dans l’Industrie et le Transport du Pe´ troles S.P.I.T.P.
(France, 23.69%)
South Caucasus Pipeline Company Limited (Cayman Islands, 28.83%)
South Caucasus Pipeline Holding Company Limited (Cayman Islands, 28.83%)
South Caucasus Pipeline Option Gas Company Limited (Cayman Islands, 28.83%)
South China Bluesky Aviation Oil Company Limited (China, 24.50%)
ST-Airport Services Pte Ltd (Singapore, 33.00%)
Stansted Intoplane Company Limited (United Kingdom, 20.00%)
STDG Strassentransport Dispositions Gesellschaft mbH (Germany, 50.00%)
Stonewall Resources Ltd. (Virgin Islands, British, 60.00%)
Sunderland Oil Storage Limited (United Kingdom, 50.00%)
Sunrise Oil Sands Partnership (Canada, 50.00%)c
Tankanlage AG Mellingen (Switzerland, 33.30%)
TAR-Tankanlage Ruemlang AG (Switzerland, 27.30%)
TAU Tanklager Auhafen AG (Switzerland, 50.00%)
Team Terminal B.V. (Netherlands, 22.80%)
Tecklenburg GmbH (Germany, 50.00%)
Tecklenburg GmbH & Co. Energiebedarf KG (Germany, 50.00%)c
Terminales Canarios, S.L. (Spain, 50.00%)
Terminales Maritimas Patagonicas SA (TERMAP S.A.) (Argentina, 60.00%)
TFSS Turbo Fuel Services Sachsen GbR (Germany, 20.00%)c
TGFH Tanklager-Gesellschaft Frankfurt-Hahn GbR (Germany, 50.00%)
TGH Tankdienst-Gesellschaft Hamburg GbR (Germany, 33.33%)c
TGHL Tanklager-Gesellschaft Hannover-Langenhagen GbR (Germany, 50.00%)c
TGK Tanklagergesellschaft Koln-Bonn (Germany, 20.00%)c
The Baku-Tbilisi-Ceyhan Pipeline Company (Cayman Islands, 30.10%)
The Consolidated Petroleum Company Limited (United Kingdom, 50.00%)
The Consolidated Petroleum Supply Company Limited (United Kingdom, 50.00%)
The New Zealand Refining Company Limited (New Zealand, 21.19%)
The Sullom Voe Association Limited (United Kingdom, 33.33%)
TLM Tanklager Management GmbH (Austria, 49.00%)
TLS Tanklager Stuttgart GmbH (Germany, 45.00%)
Torsina Oil Company “TORSINA” (Egypt, 37.50%)
Trafineo GmbH & Co. KG (Germany, 75.00%)c
Trafineo Verwaltungs-GmbH (Germany, 75.00%)c
Trans Adriatic Pipeline AG (Switzerland, 20.00%)
TransTank GmbH (Germany, 50.00%)
Unimar LLC (United States, 50.00%)d
United Gas Derivatives Company “UGDC” (Egypt, 33.33%)
United Kingdom Oil Pipelines Limited (United Kingdom, 33.50%)
Ursa Oil Pipeline Company LLC (United States, 22.69%)
VIC CBM Limited (United Kingdom, 50.00%)
Virginia Indonesia Co. CBM Limited (United Kingdom, 50.00%)
Virginia Indonesia Co., LLC (United States, 50.00%)
Virginia International Co., LLC (United States, 50.00%)
Walton-Gatwick Pipeline Company Limited (United Kingdom, 42.33%)
West London Pipeline and Storage Limited (United Kingdom, 30.50%)
West Morgan Petroleum Company (PETROMORGAN) (Egypt, 50.00%)
Wilprise Pipeline Company, L.L.C. (United States, 25.30%)
Wiri Oil Services Limited (New Zealand, 27.78%)
Xact Downhole Telementry Inc (Canada, 25.70%)m
Yangtze River Acetyls Co., Ltd (China, 51.00%)
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15. Related undertakings of the group – continued
Natural Gas Vehicles Company “NGVC” (Egypt, 40.00%)
New Zealand Oil Services Limited (New Zealand, 50.00%)
NFX Combustl´veis Marl´timos Ltda. (Brazil, 50.00%)
Nigermed Petroleum S.A. (Panama, 50.00%)
Nord-West Oelleitung GmbH (Germany, 42.49%)
North Ghara Petroleum Company (NOGHCO) (Egypt, 30.00%)
North October Petroleum Company “NOPCO” (Egypt, 50.00%)
Oak Hill Venture Fund Limited Partnership (United States, 50.00%)c
Ocwen Energy Pty Ltd (Australia, 49.50%)
OJSC Oil Company Rosneft (Russian Federation, 19.75%)
Okeanos Gas Gathering Company, LLC (United States, 66.67%)
Oleoductos Canarios, S.A. (Spain, 20.00%)
OptoAtmospherics Inc (United States, 27.20%)m
Oslo Lufthaven Tankanlegg AS (Norway, 33.33%)
PAE E & P Bolivia Limited (Bahamas, 60.00%)
PAE Oil & Gas Bolivia Ltda. (Bolivia, 60.00%)
Pan American Energy Chile Limitada (Chile, 60.00%)
Pan American Energy do Brasil Ltda. (Brazil, 60.00%)
Pan American Energy Holdings Ltd. (Virgin Islands, British, 60.00%)
Pan American Energy Iberica S.L. (Spain, 60.00%)
Pan American Energy Investments Ltd. (Virgin Islands, British, 60.00%)
Pan American Energy LLC (United States, 60.00%)
Pan American Energy Uruguay S.A. (Uruguay, 60.00%)
Pan American Fueguina S.A. (Argentina, 60.00%)
Pan American Sur S.A. (Argentina, 60.00%)
Paul Harling Mineralole GmbH & Co. KG (Germany, 50.00%)c
Peninsular Aviation Services Company Limited (Saudi Arabia, 25.00%)
Pentland Aviation Fuelling Services Limited (United Kingdom, 25.00%)p
Petro Shadwan Petroleum Company “PETRO SHADWAN” (Egypt, 25.00%)
Petrostock SA (Switzerland, 50.00%)
Pharaonic Petroleum Company “PhPC” (Egypt, 25.00%)
Phu My 3 BOT Power Company Limited (Vietnam, 33.33%)
Prince William Sound Oil Spill Response Corporation (United States, 25.00%)
Proteus Oil Pipeline Company, LLC (United States, 75.00%)
PT Petro Storindo Energi (Indonesia, 30.00%)
PTE Pipeline LLC (United States, 32.00%)
Raffinerie de Strasbourg (France, 33.33%)
Rahamat Petroleum Company (PETRORAHAMAT) (Egypt, 50.00%)
Raimund Mineraloel GmbH (Germany, 50.00%)
RAPISA (Greece, 62.50%)
Raststaette Glarnerland AG, Niederurnen (Switzerland, 20.00%)
RD Petroleum Limited (New Zealand, 49.00%)
Resolution Partners LLP (United States, 68.00%)
Rhein-Main-Rohrleitungstransportgesellschaft mbH (Germany, 35.00%)
Rio Grande Pipeline Company (United States, 30.00%)c
RocketRoute Limited (United Kingdom, 22.50%)m
Romanian Fuelling Services S.R.L. (Romania, 50.00%)
Routex B.V. (Netherlands, 25.00%)
Rudeis Oil Company “RUDOCO” (Egypt, 50.00%)
Ruhr Oel GmbH (ROG) (Germany, 50.00%)
Rundel Mineraloelvertrieb GmbH (Germany, 50.00%)
S&JD Robertson North Air Limited (United Kingdom, 49.00%)
SABA-Sociedade Abastecedora de Aeronaves, Lda (Portugal, 25.00%)
SAFCO SA (Greece, 33.00%)
Salzburg Fuelling GmbH (Austria, 33.00%)
Samsung-BP Chemicals Co., Ltd (Korea, Republic of, 51.00%)
Saraco SA (Switzerland, 20.00%)
SBB Dortmund GmbH (Germany, 25.00%)
Servicios Logl´sticos de Combustibles de Aviacio´ n, S.L (Spain, 50.00%)
Shanghai SECCO Petrochemical Company Limited (China, 50.00%)
Sharjah Aviation Services Co. LLC (United Arab Emirates, 49.00%)
Sharjah Pipeline Company LLC (United Arab Emirates, 24.01%)w
a Ordinary shares and preference shares
b Common stock and preference shares
c Partnership interest
d Member interest
e Preferred series B shares
f Interest held directly by BP p.l.c.
g 99% held by BP p.l.c.
h A and B shares
i 1% held by BP p.l.c.
j Common stock, preferred stock class A and preferred stock class B
k 0.008% held by BP p.l.c.
l Bearer shares
mPreference shares
n 93.56% ordinary shares and 81.00% preference shares
o 19.32% held by BP p.l.c.
p A shares
q Subsidiary in which the group does not hold a majority of the voting rights but exercises control over it
r Ordinary shares and redeemable preference shares
s 33.75% ordinary shares and 75% cumulative redeemable preference shares
t 100.00% ordinary shares and 58.63% preference shares
u Unlimited redeemable shares
v 0.52% A class and 29.58% B class
w B shares
The parent company financial statements of BP p.l.c. on pages 196-213 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 2015
213
THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY
214
BP Annual Report and Form 20-F 2015
Additional
disclosures
216 Selected financial information
219 Liquidity and capital resources
221 Upstream analysis by region
225 Downstream plant capacity
227 Oil and gas disclosures for the group
233 Environmental expenditure
233 Regulation of the group’s business
237 Legal proceedings
242 International trade sanctions
243 Material contracts
243 Property, plant and equipment
243 Related-party transactions
244 Corporate governance practices
244 Code of ethics
244 Controls and procedures
245 Principal accountants’ fees and services
245 Directors’ report information
246 Disclosures required under Listing Rule 9.8.4R
246 Cautionary statement
BP Annual Report and Form 20-F 2015
215
Selected financial information
This information, insofar as it relates to 2015, has been extracted or derived from the audited consolidated financial statements of the BP group
presented on page 95. 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 elsewhere herein.
Income statement data
Sales and other operating revenues
Underlying replacement cost (RC) profit before interest and taxation*
Net favourable (unfavourable) impact of non-operating items* and fair value
accounting effects*
RC profit (loss) before interest and taxation*
Inventory holding gains (losses)*
Profit (loss) before interest and taxation
Finance costs and net finance expense relating to pensions and other
post-retirement benefits
Taxation
Profit (loss) for the year
Profit (loss) for the year attributable to BP shareholders
Inventory holding (gains) losses, net of taxation
RC profit (loss) for the year attributable to BP shareholders
Non-operating items and fair value accounting effects, net of taxation
Underlying RC profit for the year attributable to BP shareholders
Per ordinary share – cents
Profit (loss) for the year attributable to BP shareholders
Basic
Diluted
RC profit (loss) for the year attributable to BP shareholders
Underlying RC profit for the year attributable to BP shareholders
Dividends paid per share – cents
– pence
Capital expenditure and acquisitions, on an accruals basis
Acquisitions and asset exchanges, on an accruals basis
Other inorganic capital expenditure, on an accruals basis
Organic capital expenditure*, on an accruals basis
Balance sheet data (at 31 December)
Total assets
Net assets
Share capital
BP shareholders’ equity
Finance debt due after more than one year
Net debt to net debt plus equity*
Ordinary share dataa
Basic weighted average number of shares
Diluted weighted average number of shares
a The number of ordinary shares shown has been used to calculate the per share amounts.
2015
2014
2013
2012
2011
$ million except per share amounts
222,894
8,791
353,568
20,818
379,136
22,776
375,765
26,454
375,713
33,601
(14,820)
(6,029)
(1,889)
(7,918)
(1,653)
3,171
(6,400)
(6,482)
1,320
(5,162)
11,067
5,905
(35.39)
(35.39)
(28.18)
32.22
40.00
26.383
19,531
49
734
18,748
(8,196)
12,622
(6,210)
6,412
(1,462)
(947)
4,003
3,780
4,293
8,073
4,063
12,136
20.55
20.42
43.90
66.00
39.00
23.850
23,781
420
469
22,892
9,283
32,059
(290)
31,769
(1,548)
(6,463)
23,758
23,451
230
23,681
(10,253)
13,428
123.87
123.12
125.08
70.92
36.50
23.399
36,612
71
11,941
24,600
(6,091)
20,363
(594)
19,769
(1,638)
(6,880)
11,251
11,017
411
11,428
5,643
17,071
57.89
57.50
60.05
89.70
33.00
20.852
25,204
200
1,054
23,950
3,580
37,181
2,634
39,815
(1,587)
(12,619)
25,609
25,212
(1,800)
23,412
(2,242)
21,170
133.35
131.74
123.83
111.97
28.00
17.404
31,959
11,283
1,096
19,580
261,832
98,387
5,049
97,216
46,224
21.6%
284,305
112,642
5,023
111,441
45,977
16.7%
305,690
130,407
5,129
129,302
40,811
16.2%
300,466
119,752
5,261
118,546
38,767
18.7%
18,324
18,324
18,385
18,497
18,931
19,046
19,028
19,158
292,907
112,585
5,224
111,568
35,169
20.4%
Shares million
18,905
19,136
216
BP Annual Report and Form 20-F 2015
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
Impairment and gain (loss) on sale of businesses and fixed assetsa
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Otherb c
Downstream
Impairment and gain (loss) on sale of businesses and fixed assetsa
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Other
TNK-BP
Impairment and gain (loss) on sale of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Other
Rosneft
Impairment and gain (loss) on sale of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Other
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assetsa
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Otherc
Gulf of Mexico oil spill response
Total before interest and taxation
Finance costsd
Taxation credite (charge)
Total after taxation
$ million
2013
(802)
(20)
–
459
(1,001)
(1,364)
(348)
(134)
(15)
–
(38)
(535)
12,500
–
–
–
–
12,500
(35)
(10)
–
–
–
(45)
(196)
(241)
(3)
–
19
(421)
(430)
2015
2014
(1,204)
(24)
(410)
120
(717)
(2,235)
131
(108)
(607)
–
(6)
(590)
(6,576)
(60)
(100)
430
8
(6,298)
(1,190)
(133)
(165)
–
(82)
(1,570)
–
–
–
–
–
–
225
–
–
–
–
225
(304)
(180)
(176)
–
(10)
(670)
(781)
–
–
–
–
–
–
–
–
–
–
–
–
(170)
(151)
(71)
–
(155)
(547)
(11,709)
(15,081)
(247)
4,056
(11,272)
A
d
d
i
t
i
o
n
a
l
d
i
s
c
l
o
s
u
r
e
s
(9,094)
(38)
4,512
(4,620)
9,705
(39)
867
10,533
a See Financial statements – Note 4 for further information on impairments.
b 2014 included a $395-million write-off relating to Block KG D6 in India. 2013 included $845 million relating to the value ascribed to block BM-CAL-13 offshore Brazil, following the acquisition of
upstream assets from Devon Energy in 2011, which was written off as a result of the Pitanga exploration well not encountering commercial quantities of oil or gas.
c 2015 principally relates to BP’s share of impairment losses recognized by equity-accounted entities.
d Finance costs relate to the Gulf of Mexico oil spill. See Financial statements – Note 2 for further details.
e From 2014, tax is based on statutory rates except for non-deductible or non-taxable items. For 2013, tax for the Gulf of Mexico oil spill and certain impairment losses, disposal gains and fair value gains
and losses on embedded derivatives, is based on statutory rates, except for non-deductible items; for other items reported for consolidated subsidiaries, tax is calculated using the group’s discrete
quarterly effective tax rate (adjusted for the items noted above, equity-accounted earnings and certain deferred tax adjustments relating to changes in UK taxation).
* Defined on page 256.
BP Annual Report and Form 20-F 2015
217
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 256.
Upstream
Unrecognized gains (losses) brought forward from previous period
Unrecognized (gains) losses carried forward
Favourable (unfavourable) impact relative to management’s measure of performance
Downstreama
Unrecognized gains (losses) brought forward from previous period
Unrecognized (gains) losses carried forward
Favourable (unfavourable) impact relative to management’s measure of performance
Taxation credit (charge) b
By region
Upstream
US
Non-US
Downstreama
US
Non-US
2015
2014
$ million
2013
(191)
296
105
(188)
344
156
261
(56)
205
(66)
171
105
102
54
156
(160)
191
31
679
188
867
898
(341)
557
23
8
31
914
(47)
867
(404)
160
(244)
501
(679)
(178)
(422)
142
(280)
(269)
25
(244)
(211)
33
(178)
a Fair value accounting effects arise solely in the fuels business.
b From 2014, tax is calculated using statutory rates. For 2013 tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for certain non-operating items, equity-accounted earnings
and certain deferred tax adjustments relating to changes in UK taxation).
Reconciliation of non-GAAP information
Upstream
RC profit (loss) before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
RC profit (loss) before interest and tax
Downstream
RC profit before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
RC profit before interest and tax
Total group
Profit (loss) before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
Profit (loss) before interest and tax
Operating capital employed*
Upstream
Downstream
Rosneft
Other businesses and corporate
Gulf of Mexico oil spill response
Consolidation adjustment – UPII*
Total operating capital employed
Liabilities for current and deferred taxation
Goodwill
Finance debt
Net assets
218
BP Annual Report and Form 20-F 2015
2015
2014
(1,042)
105
(937)
6,955
156
7,111
(8,179)
261
(7,918)
8,903
31
8,934
2,871
867
3,738
5,514
898
6,412
$ million
2013
16,901
(244)
16,657
3,097
(178)
2,919
32,191
(422)
31,769
$ million
2015
107,197
34,935
5,797
19,399
(18,797)
(68)
148,463
(8,535)
11,627
(53,168)
98,387
Liquidity and capital resources
Financial framework
We maintain our financial framework to support the pursuit of value
growth for shareholders, while ensuring a secure financial base. BP’s
objective over time is to grow sustainable free cash flow* through a
combination of material growth in underlying operating cash flow* and
a strong focus on capital discipline, providing a sound platform to grow
shareholder distributions. The priority is to grow dividend per share
progressively in accordance with the growth in sustainable operating
cash flow from our businesses over time. Any surplus cash over and
above that required for capital investment and dividend payments will
be biased towards further shareholder distributions through buybacks or
other mechanisms.
In the near term, and reflecting the weaker oil price environment, the
focus is to manage the business through a period of low oil prices and
support the dividend, which remains a priority. Our principal objective
over the medium term is to re-establish a balance in our financial
framework, where operating cash flow (excluding payments related to
the Gulf of Mexico oil spill) covers capital expenditure and the dividend
at an assumed medium-term price of $60 per barrel. We aim to do this
while maintaining safe and reliable operations, preserving core growth
activities and sustaining the dividend. We responded quickly to the
lower environment, resetting both the capital and cash cost base of the
Group. We expect organic capital expenditure in 2016 to be at the lower
end of the range of $17-19 billion. In 2016 we expect to announce a
further $3-5 billion of divestments and from 2017 we expect
divestments to average the historical norm of around $2-3 billion
per annum.
We aim to manage gearing* with some flexibility around the 20% level
while volatile market conditions remain and maintain a significant
liquidity buffer. We expect the net debt ratio to be above 20% while oil
prices remain weak. As well as uncertainties relating to current lower oil
prices, the group also continues to face uncertainties relating to the Gulf
of Mexico oil spill as explained in Financing the group’s activities below.
We will keep our financial framework under review as we monitor oil
and gas prices and their impact on industry costs as we move through
2016 and beyond.
Dividends and other distributions to shareholders
Since resuming dividend payments with a quarterly dividend of 7 cents
per share paid in 2011, it has increased by 43% to 10 cents per share
paid in the fourth quarter of 2015. The dividend level is regularly
reviewed by the board.
The total dividend paid in cash to BP shareholders in 2015 was
$6.7 billion (2014 $5.9 billion) with shareholders also having the option
to receive a scrip dividend. The dividend is determined in US dollars, the
economic currency of BP.
Details of share repurchases to satisfy the requirements of certain
employee share-based payment plans are set out on page 253. There
were no other buyback programmes during 2015.
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 is issued in other currencies, including euros, it is
generally swapped back to US dollars using derivative contracts, or else
hedged by maintaining offsetting cash positions in the same currency.
The 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 borrowings. Also see Risk factors on page 53
for further information on risks associated with prices and markets and
Financial statements – Note 28.
The group’s gross debt at 31 December 2015 amounted to $53.2 billion
(2014 $52.9 billion). Of the total gross debt, $6.9 billion is classified as
short term at the end of 2015 (2014 $6.9 billion). See Financial
statements – Note 25 for more information on the short-term balance.
Standard & Poor’s Ratings long-term credit rating for BP is A- and
assigned a stable outlook and Moody’s Investors Service rating is A2
(rating under review).
Net debt was $27.2 billion at the end of 2015 an increase of $4.6 billion from
the 2014 year-end position of $22.6 billion. The ratio of net debt to net debt
plus equity* was 21.6% at the end of 2015 (2014 16.7%). See Financial
statements – Note 26 for gross debt, which is the nearest equivalent
measure on an IFRS basis, and for further information on net debt.
Cash and cash equivalents of $26.4 billion at 31 December 2015 (2014
$29.8 billion) are included in net debt. We manage our cash position to
ensure the group has adequate cover to respond to potential short-term
market illiquidity, and expect to maintain a robust cash position.
The group also has undrawn committed bank facilities of $7.4 billion
(see Financial statements – Note 28 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 the ongoing ability
to generate cash.
The group’s sources of funding, its access to capital markets and
maintaining a strong cash position are described in Financial statements
– Note 24 and Note 28. 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 25 and Note 28.
In relation to the Gulf of Mexico oil spill, during 2015, BP signed
agreements in principle to settle all federal and state claims, subject to
court approval, and to settle claims made by more than 400 local
government entities. These agreements significantly reduce the
uncertainties faced by BP following the Gulf of Mexico oil spill in 2010.
There continues to be uncertainty regarding the outcome or resolution
of current or future litigation and the extent and timing of costs relating
to the incident not covered by these agreements. See Risk factors on
page 53 and Financial statements – Note 2 for further information.
Off-balance sheet arrangements
At 31 December 2015, the group’s share of third-party finance debt of
equity-accounted entities was $11.8 billion (2014 $14.7 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 2015 were $35 million (2014 $83 million) in respect of
liabilities of joint ventures* and associates* and $163 million (2014
$244 million) in respect of liabilities of other third parties. Of these
amounts, $22 million (2014 $64 million) of the joint ventures and
associates guarantees relate to borrowings and for other third-party
guarantees, $119 million (2014 $126 million) relate to guarantees of
borrowings. Details of operating lease commitments, which are not
recognized on the balance sheet, are shown in the table below and
provided in Financial statements – Note 27.
A
d
d
i
t
i
o
n
a
l
d
i
s
c
l
o
s
u
r
e
s
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 246 and Risk factors on page 53, 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.
* Defined on page 256.
BP Annual Report and Form 20-F 2015
219
Contractual obligations
The following table summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2015 and the
proportion of that expenditure for which contracts have been placed.
Capital expenditure
Committed
of which is contracted
Total
2016
36,972
10,379
15,408
6,224
2017
8,009
2,031
2018
7,248
1,317
2019
4,490
645
2020
855
75
2021 and
thereafter
962
87
$ million
Payments due by period
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 2015, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to
$4,229 million. Contracts were in place for $2,933 million of this total.
The following table summarizes the group’s principal contractual obligations at 31 December 2015, 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 25 and more information on operating leases is given in Financial statements – Note 27.
$ million
Payments due by period
Expected payments by period under contractual obligations
Total
2016
2017
2018
2019
2020
Balance sheet obligations
Borrowingsa
Finance lease future minimum lease paymentsb
Decommissioning liabilitiesc
Environmental liabilitiesc
Pensions and other post-retirement benefitsd
Off-balance sheet obligations
Operating lease future minimum lease paymentse
Unconditional purchase obligationsf
56,692
1,460
21,762
10,012
23,399
7,764
108
796
586
1,656
113,325
10,910
6,502
106
600
822
1,805
9,835
6,815
97
596
480
1,791
9,779
15,422
120,286
135,708
4,144
47,859
52,003
2,904
12,489
15,393
1,933
8,743
10,676
6,600
95
383
669
1,785
9,532
1,615
7,540
9,155
6,741
91
643
664
1,278
9,417
1,291
5,594
6,885
2021 and
thereafter
22,270
963
18,744
6,791
15,084
63,852
3,535
38,061
41,596
Total
249,033
62,913
25,228
20,455
18,687
16,302
105,448
a Expected payments include interest totalling $4,227 million ($866 million in 2016, $754 million in 2017, $649 million in 2018, $541 million in 2019, $432 million in 2020 and $985 million thereafter).
b Expected payments include interest totalling $757 million ($62 million in 2016, $58 million in 2017, $55 million in 2018, $51 million in 2019, $46 million in 2020 and $485 million thereafter).
c The amounts are undiscounted. Environmental liabilities include those relating to the Gulf of Mexico oil spill.
d 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.
e The future minimum lease payments are before deducting related rental income from operating sub-leases. In the case of an operating lease entered into solely by BP as the operator of a joint
operation, the amounts shown in the table represent the net future minimum lease payments, after deducting amounts reimbursed, or to be reimbursed, by joint operation partners. Where BP is not
the operator of a joint operation, BP’s share of the future minimum lease payments are included in the amounts shown, whether BP has co-signed the lease or not. Where operating lease costs are
incurred in relation to the hire of equipment used in connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project.
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 2016 include purchase commitments existing at 31 December 2015 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 28.
The following table summarizes the nature of the group’s unconditional purchase obligations.
$ million
Payments due by period
Total
2016
47,466
21,322
6,464
4,918
630
21,138
18,348
28,715
11,639
2,210
2,558
197
1,190
1,350
2017
4,534
3,791
1,215
1,031
174
1,008
736
2018
3,127
2,221
1,295
478
115
971
536
2019
2,308
1,480
1,340
292
64
960
1,096
2020
2,008
767
264
121
20
1,291
1,123
2021 and
thereafter
6,774
1,424
140
438
60
15,718
13,507
120,286
47,859
12,489
8,743
7,540
5,594
38,061
Unconditional purchase obligations
Crude oil and oil products
Natural gas
Chemicals and other refinery feedstocks
Power
Utilities
Transportation
Use of facilities and services
Total
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Upstream analysis by region
Our upstream operations are set out below by geographical area, with
associated significant events for 2015. 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 reserves and production.
In addition to exploration, development and production activities, our
upstream business also includes midstream and 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)
extraction business.
Our LNG supply activities are located in Abu Dhabi, Angola, Australia,
Indonesia and Trinidad. We market around 20% of our LNG production
using BP LNG shipping and contractual rights to access import terminal
capacity in the liquid markets of the US (via Cove Point), the UK (via the
Isle of Grain), Spain (in Bilbao) and Italy (in Rovigo), with the remainder
marketed directly to customers. LNG is supplied to customers in markets
including Japan, South Korea, China, the Dominican Republic, Argentina,
Brazil and Mexico.
Europe
BP is active in the North Sea and the Norwegian Sea. Our activities focus
on maximizing recovery from existing producing fields and selected new
field developments. BP’s production is generated from three key areas:
the Shetland area, comprising Magnus, Clair, Foinaven and Schiehallion
fields; the central area, comprising Bruce, Andrew and ETAP fields; and
Norway, comprising Valhall, Ula and Skarv fields.
• BP and its partners, ConocoPhillips, Chevron and Shell, announced
their decision to proceed with a two-year appraisal programme to
evaluate a potential third phase of the Clair field (BP 28.6%), west of
the Shetland Islands in March 2013. In March we completed the sixth
and final well of the programme. The Clair field partners will review the
significant amount of data collected to determine the potential for
development.
• The Quad 204 project, a major redevelopment to extend the life of the
Schiehallion and Loyal fields to the west of Shetland, continued in
2015. After successfully completing sea trials, Glen Lyon, the
replacement floating production, storage and offload vessel (FPSO),
departed South Korea in December at the start of its journey to the
Shetlands. We also ran a major offshore campaign focusing on the pre-
installation of risers and ancillary equipment in preparation for its arrival.
As well as the new FPSO, the redevelopment includes extension of
the existing subsea infrastructure and drilling new wells. In April, on
behalf of its co-venturers, BP announced the start of a seven-year
drilling campaign on the Loyal field by the new-build, semi-submersible
drilling rig, Deepsea Aberdeen.
• In June BP and its partners announced that the Clair Ridge platform’s
topside modules for accommodation and utilities had been installed.
The next major milestone will be the installation of the production and
drilling platform topside modules, scheduled for summer 2016, with
production expected to commence in late 2017.
• In July we were awarded five new blocks across two licences in the
North Sea as part of the second tranche of the 28th licensing round by
the UK Oil and Gas Authority, bringing the total blocks awarded to BP
to 12 to date in this licensing round.
• Maersk Oil announced the UK Oil and Gas Authority’s approval of
development plans for the Culzean field in the UK North Sea in August.
Culzean is operated by Maersk Oil on behalf of its partners, JX Nippon
and BP (16%).
• We completed the Magnus life extension project in July enabling
Magnus to continue safe and compliant operations. This was the first
project in our North Sea renewals programme, designed to extend the
productive life of mature assets. Production for Magnus has been
extended by five years to 2023. Additional accommodation has been
constructed to enable maintenance of this ageing facility and a return
to drilling in 2017.
• The ETAP life extension and additional living-quarters project began in
2015 and is scheduled to run through 2016. These activities aim to
delay cessation of production for the ETAP fields to 2030 by executing
maintenance scope and installing additional living quarters on the
central processing facility. Total investment on these projects is
currently estimated at $360 million gross.
• Operations at the Rhum gas field continued under a temporary
management scheme announced by the UK government in 2013.
Production was suspended between November 2010 and October
2014 following the imposition of EU sanctions on Iran. The field is
owned by BP (50%) and the Iranian Oil Company (IOC) under a joint
operating agreement. See International trade sanctions on page 242.
• In December, a number of North Sea assets were subject to
impairment charges totalling $830 million, primarily as a result of the
lower price environment. These were however more than offset by
impairment reversals of $945 million in relation to other assets in the
region arising as a result of decreases in cost estimates and a
reduction in the discount rate applied.
In the UK North Sea, BP operates the Forties Pipeline System (FPS)
(BP 100%), an integrated oil and NGLs transportation and processing
system that handles production from around 80 fields in the central
North Sea. The system has a capacity of more than 675mboe/d, with
average throughput in 2015 of 442mboe/d. BP also operated and had a
36% interest in the Central Area Transmission System (CATS), a 400-
kilometre natural gas pipeline system in the central UK sector of the
North Sea providing transport and processing services. Average
throughput in 2015 was 40mboe/d. In April, BP announced the sale of its
equity in the CATS business to Antin Infrastructure Partners for a
headline price of $486 million, and the sale completed in December. BP
also operates the Sullom Voe oil and gas terminal in Shetland.
North America
Our upstream activities in North America take place in four main areas:
deepwater Gulf of Mexico, the Lower 48 states, Alaska and Canada. For
further information on BP’s activities in connection with its
responsibilities following the Deepwater Horizon oil spill, see page 41.
BP has around 500 lease blocks in the deepwater Gulf of Mexico, making
us one of the largest portfolio owners, and operates four production hubs.
• We announced a new ownership and operating model with Chevron and
ConocoPhillips in January 2015. We sold approximately half of our equity
interests in the Gila field to Chevron in December 2014 and
approximately half of our equity interest in the Tiber field to them in
January 2015. BP, Chevron and ConocoPhillips also have agreed to joint
ownership interests in exploration blocks east of Gila known as Gibson
(BP 34%). Chevron will operate Tiber (BP 31%), Gila (BP 34%) and
Gibson. Operatorship transferred at the end of 2015 after BP finished
drilling appraisal wells at Gila and Tiber. These arrangements enable us to
support exploration and development in the Paleogene, share
development costs and maximize synergies allowing us to manage and
improve capital efficiency, as well as increase our focus on maximizing
production at our existing operated hubs.
• In the fourth quarter, BP began drilling operations on two wells, the
Chevron operated Gibson prospect and the appraisal well on the
Hopkins discovery. Both wells will complete in 2016.
• In March we incurred drilling rig contract cancellation costs of
$375 million for two deepwater drilling rigs in the Gulf of Mexico which
are no longer required for our operations.
• In November BP and its partners in the Mad Dog Phase 2 project
(BP 60.5%) approved a modified development plan and were awarded
a Suspension of Production from the US Department of the Interior.
Mad Dog Phase 2 will develop resources in the central area of the field
through a subsea development consisting of up to 24 wells from four
drill centres.
• In December we wrote off $345 million relating to costs for the Gila
discovery as these resources would be challenging to develop in the
current environment.
• See also Significant estimate or judgement: oil and natural gas
accounting on page 109 for further information on leases.
• See page 30 for further information on our Thunder Horse South
Expansion project.
* Defined on page 256.
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The US Lower 48 onshore business has significant activities across six
states producing natural gas, oil, NGLs and condensate. It is organized
into five, geographic business units, and has a resource base that is
mainly in unconventional reservoirs* (tight gas*, shale gas and coalbed
methane). This resource spans 5.4 million gross developed acres
(3.1 million net) and has approximately 9,000 operated gross wells, with
daily net production around 280mboe/d.
Our US Lower 48 onshore business began operating as a separate
business in 2015. While remaining part of our Upstream segment, it has
its own governance, processes and systems and is designed to increase
competitive performance through swift decision making and innovation,
while maintaining BP’s commitment to safe, reliable and compliant
operations.
• In December the US Lower 48 onshore business expanded its San
Juan basin operations by acquiring all of Devon Energy’s assets in the
region. The bulk of the acquired assets, which span northern New
Mexico and southern Colorado, consist of Devon’s operated interest in
the Northeast Blanco Unit.
For further information on the use of hydraulic fracturing in our shale gas
assets see page 47. BP’s onshore US crude oil and product pipelines and
related transportation assets are included in the Downstream segment.
In Alaska BP operated nine North Slope oilfields in the Greater Prudhoe
Bay area at the end of 2015. Our focus continues to be safe and reliable
operations, renewing BP’s Alaska North Slope infrastructure and
minimizing oil production decline. Infrastructure renewal activities in 2015
included fire and gas system upgrades, safety system upgrades, pipeline
renewal and facility siting projects. Production decline is being managed
through annual drilling programmes and rig and non-rig well work
programmes. BP also owns significant interests in six producing fields
operated by others, as well as significant non-operating interests in the
Point Thomson development project and the Liberty prospect.
• Development of the Point Thomson production facility continued in
2015. Construction of field infrastructure and fabrication of the four
main process modules is progressing on schedule. The project is on
track to commence production in early 2016. BP holds a 32% working
interest in the field and ExxonMobil is the operator.
• BP continued to work jointly with ExxonMobil, ConocoPhillips and the
State of Alaska throughout 2015 to advance the Alaska LNG project.
The project concept includes a North Slope gas treatment plant, an
approximately 800-mile pipeline to tidewater and a three-train
liquefaction facility, with an estimated capacity of 3bcf/d (up to
20 million tonnes per annum). In June 2014 the Alaska LNG co-
venturers, including the State of Alaska, executed commercial
agreements and launched the pre-front-end engineering and design
(pre-FEED) phase of the project, which is expected to extend through
2016 with a gross spend of more than $500 million. In March, the
Federal Energy Regulatory Commission issued a Notice of Intent to
prepare an environmental impact statement for the Alaska LNG
project. In May 2015 the US Department of Energy conditionally
authorized the export of Alaska LNG to non-Free Trade Agreement
countries. In October and November the co-venturers received
approval from the Alaska Oil & Gas Conservation Commission for gas
offtake from the Prudhoe Bay and Point Thomson fields respectively
sufficient to underpin gas export. A decision point for progressing to
the front-end engineering and design (FEED) phase of the project will
be reached in 2017 after completion of the pre-FEED phase. First
commercial gas is planned between 2023 and 2025.
• In December, a number of Alaska assets were subject to impairment
charges totalling $194 million, primarily as a result of the lower price
environment.
BP owns a 49% interest in the Trans-Alaska Pipeline System (TAPS). TAPS
transports crude oil from Prudhoe Bay on the Alaska North Slope to the port
of Valdez in south-east Alaska. In April 2012 the two non-controlling owners
of TAPS, Koch (3.08%) and Unocal (1.37%) gave notice to BP, ExxonMobil
(21.1%) and ConocoPhillips (29.1%) of their intention to withdraw as
owners of TAPS. The transfer of Koch’s interest to the remaining owners
was completed in 2012. The remaining owners and Unocal have not yet
reached agreement regarding the terms for the transfer of Unocal’s interest
in TAPS and related litigation will continue in 2016.
• In November 2015, the Federal Energy Regulatory Commission (FERC)
issued an order addressing the TAPS tariff rate filings for years 2009 and
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2010. The decision will result in an increase in BP’s production tax and
royalty liabilities to the State of Alaska, retroactively from 2009 onwards.
In Canada, BP is currently focused on oil sands development using in-situ
steam-assisted gravity drainage (SAGD) technology, which uses the
injection of steam into the reservoir to warm the bitumen so that it can
flow to the surface through producing wells. We hold interests in three
oil sands leases through the Sunrise Oil Sands and Terre de Grace
partnerships and the Pike Oil Sands joint operation*. In addition, we
have significant offshore exploration interests in the Canadian Beaufort
Sea, Nova Scotia and Newfoundland.
• Following the start of steam generation at the Sunrise Phase 1 in-situ
oil sands project in Alberta (BP 50%) in December 2014, oil production
began in March. Production is expected to ramp-up to full capacity of
60,000 barrels per day (gross) in 2017.
• BP completed processing seismic data acquired offshore Nova Scotia
at the end of 2015. We and our partners Hess (40%) and Woodside
(20%) are planning to choose potential exploration well locations in
2016 and, pending regulatory approval, begin the first exploration
drilling programme.
• In partnership with Statoil and ExxonMobil, BP was a successful bidder
for exploration licences in the Flemish Pass Basin offshore
Newfoundland. Statoil will operate all three licences, and ExxonMobil
will participate in two licences as a partner. The licences have an
effective date of 15 January 2016. BP has a 33% share in the
NL15-01-06 and NL15-01-07 licences and a 50% share in the
NL15-01-08 licence.
South America
BP has upstream activities in Brazil and Trinidad & Tobago, as well as in
Argentina, Bolivia, and Chile through an equity-accounted joint venture*.
In Brazil BP has interests in 21 exploration concessions across five
basins.
• We continued appraisal of the Itaipu discovery, located in the
deepwater sector of the Campos basin offshore Brazil in block
BM-C-32, in line with the appraisal plan approved by the Brazilian
National Petroleum Agency (ANP) in 2015. In October BP and its
partner Anadarko submitted an application to ANP to transfer
operatorship from BP to Anadarko. This will achieve significant
efficiencies in progressing the development of this and an adjacent
block, BM-C-30 (Wahoo), where Anadarko is the operator. Also in
October, an extension request was filed with the ANP for three
additional years for each of Itaipu and Wahoo to progress appraisal
activities.
• In May we received final approval from ANP for the previously signed
agreement with Petroleo Brasileiro S.A. (Petrobras) to farm in to five
deepwater exploration blocks in Potiguar basin. The blocks are located in
the Brazilian equatorial margin and cover an area of 3,837km2. The Pitu-2
well was completed during the year and proved the presence of oil.
• After disappointing exploration results in October, BP and Petrobras
submitted an application to ANP to relinquish their interest in
BM-CE-2 block in Ceara basin.
• During the year we progressed the preparatory activities for drilling
exploration wells in the Foz de Amazonas and Barrerinhas blocks
acquired in May 2013.
• We continued discussions with the operators of blocks BM-C-35 and
BC-2, Petrobras and Total respectively, to define the optimal appraisal
of these blocks in the South Campos basin.
In May we notified the Uruguayan oil and gas regulator, ANCAP, that
interpretation of seismic data acquired over BP-operated blocks in
Uruguay had not resulted in identification of viable prospects. As a result
we relinquished our 100% interest in all the blocks in Uruguay and
ANCAP approved this in February 2016.
In Argentina, Bolivia and Chile BP conducts activity through Pan American
Energy LLC (PAE), an equity-accounted joint venture with Bridas
Corporation, in which BP has a 60% interest. In September 2015 PAE
sold its 50% interest in the Coiron licence in Chile. In addition, PAE has
acquired a 60% working interest in the Hokchi production-sharing
agreement* (PSA) in Mexico, effective from January 2016.
In Trinidad & Tobago BP holds exploration and production licences and
PSAs covering 1.8 million acres offshore of the east and north-east coast.
Facilities include 13 offshore platforms and two onshore processing
facilities. Production comprises gas and associated liquids.
BP also has a shareholding in Atlantic LNG (ALNG), an LNG liquefication
plant that averages 39% across four LNG trains* with a combined
capacity of 15 million tonnes per annum. BP sells gas to each of the LNG
trains, supplying 100% of the gas for train 1, 50% for train 2, 75% for
train 3 and around 67% of the gas for train 4. All LNG from train 1 and
most of the LNG from trains 2 and 3 is sold to third parties in the US and
Europe under long-term contracts. BP’s remaining equity LNG
entitlement from trains 2, 3 and 4 is marketed via BP’s LNG marketing
and trading function to markets in the US, UK, Spain and South America.
• Development of the Juniper project continues following its sanction in
2014. The lift and cellar decks are now completed. Fabrication of the
jacket and subsea structures has commenced. The first two wells have
been drilled and work in preparation for drilling the remaining three is
complete.
Africa
BP’s upstream activities in Africa are located in Angola, Algeria, Libya,
Egypt and Morocco.
In Angola BP is present in eight major deepwater licences offshore and is
operator in four of these, blocks 18 and 31 that are producing oil and
blocks 19 and 24 that are in the exploration phase. BP also has an equity
interest in the Angola LNG plant (BP 13.6%).
• In April oil production started ahead of schedule at the Kizomba
Satellites Phase-2 development in block 15 (BP 26.67%), offshore
Angola. The project is a subsea infrastructure development of the
Kakocha, Bavuca and Mondo South fields. Mondo South was the first
to begin production, with the remaining two also starting up in 2015.
This deepwater project is operated by a subsidiary of ExxonMobil.
• Our Greater Plutonio Phase 3 project, in block 18, achieved first
production from the subsea well, Pu-PQ, in the Plutonio reservoir in
June – six months ahead of schedule. The project is a subsea tie-in to
the existing Greater Plutonio FPSO in a water depth of approximately
1,300 metres. BP is the operator with a 50% interest and Sonangol
Sinopec International Limited has the remaining 50% interest.
• On 21 July Total announced that they started production from Dalia
Phase 1A, a new development on its offshore operated block 17
(BP 16.7%). The project involves drilling seven infill wells tied back to
the Dalia FPSO.
• Katambi-1, the first pre-salt play drilled by BP in the Benguela basin in
block 24 discovered hydrocarbons. Technical and commercial
evaluation of this is ongoing.
• Pandora-1, the first pre-salt play drilled by BP in the Kwanza basin in
block 19 also discovered hydrocarbons but will require nearby
developments to be potentially commercial. Due to the uncertainty BP
wrote off the costs of the well and the associated block 19 licence
($336 million) in 2015.
• The Angola LNG plant (BP 13.6%), which has been shut down for
planned repairs since April 2014 is expected to fully restart in 2016.
• In December, several fields in Angola were subject to impairment
charges as a result of falling oil prices. In total, $1.2 billion was
recognized, a significant portion of which relates to the Angola LNG
plant and is reflected in equity accounted earnings.
In Algeria BP, Sonatrach and Statoil are partners in the In Salah
(BP 33.15%) and In Amenas (BP 45.89%) projects that supply gas to the
domestic and European markets. BP’s total assets in Algeria at
31 December 2015 were $1,625 million ($310 million current and
$1,315 million non-current).
• The Bourarhat agreement expired in September 2014 and talks with
Sonatrach to negotiate new terms were not successful. Discussions
with them to close out the project were initiated in the first half of
2015 and are ongoing.
• In February 2016 the In Salah Southern Fields project start-up was
announced. The project is the latest stage in the development of the In
Salah Gas joint venture, which commenced production in 2004. The
project’s scope includes a new 500mmscfd gas dehydration central
processing facility, brownfield modifications to existing processing
facilities, 150km of carbon steel export pipelines, 160km of infield
flowlines and the drilling and tie in of 26 new wells.
In Libya we partner 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 served
the National Oil Corporation with notices of force majeure in August
2014. This is the result of continued civil unrest in Libya which has made
it impossible for BP to undertake its obligations under the EPSA safely
and securely. As a result of this uncertainty, balances associated with
Libya were written off in 2015, incurring an exploration write-off of $432
million and other charges of $166 million.
In Egypt BP and its partners currently produce 10% of Egypt’s liquids
production and almost 30% of its gas production. BP’s total assets at
31 December 2015 were $7,860 million, of which $1,739 million were
current and $6,121 million were non-current. The current assets include
trade receivables and Egyptian pound-denominated cash.
• In March BP announced a gas discovery in the North Damietta offshore
concession in the East Nile Delta at the Atoll-1 Deepwater exploration
well (BP 100%). A Heads of Agreement was signed with the Egyptian
government in November securing gas prices and key terms for the
acceleration of Atoll development, with an estimated investment of
around $900 million for the development of phase 1 of the project.
• BP signed final agreements for the development of two West Nile
Delta projects – Taurus/Libra and Giza/Fayoum/Raven (BP 82.75%).
Production from West Nile Delta is expected to start in 2017.
• The West Nile Delta project concessions amendment, approved by the
Egyptian cabinet in December 2014, was ratified in March 2015 and
will be submitted to Parliament. The amendments agree a new
development plan along with associated start-up dates.
• In May BP signed a sales and purchase agreement with DEA Deutsche
Erdoel AG under which BP increased its working interest in the West
Nile Delta project concessions from 60% in North Alexandria
Concession and 80% in West Mediterranean Deep Water Concession
to 82.75% in both concessions. The transaction completed in
December.
• In August BP announced a further gas discovery at the Nooros
prospect (BP 25%), located in the Abu Madi West concession in the
Nile Delta in Egypt, operated by Eni.
• In October BP was awarded three new exploration blocks in the
Egyptian Natural Gas Holding Company 2015 bid round. The blocks are
North El Tabya (BP 100%), North Ras El Esh (BP 50%) and North El
Hammad (BP 37.5%). We and our partners have committed to
investing over $200 million in the blocks across various phases.
In Morocco, BP has a non-operating interest in each of the Essaouira
Offshore (BP 45%), Foum Assaka Offshore (BP 26.325%) and
Tarhazoute Offshore (BP 45%) blocks in the Agadir Basin, offshore
Morocco. The exploration periods run until 2017.
Asia
BP has activities in Western Indonesia, China, Azerbaijan, Oman, Abu
Dhabi, India, Iraq and Russia.
In Western Indonesia, BP participates in LNG exports through our
interest in Virginia Indonesia Company LLC (VICO), the operator of Sanga-
Sanga PSA (BP 38%) supplying gas to the Bontang LNG plant in
Kalimantan. Sanga-Sanga currently delivers around 13% of the total gas
feed to Bontang, Indonesia’s largest LNG export facility and one of the
world’s largest LNG plants. It has a capacity of 22 million tonnes of LNG
per annum and an output of more than 13 million tonnes.
In addition, BP participates in the Sanga-Sanga CBM PSA, where our
working interest increased from 38% to 50% in January following
withdrawal of Japan CBM Limited and Opicoil Energy at the end of 2014
and pending the Indonesian government’s approval.
BP also exited the Tanjung IV PSA (BP 44%) in the Barito basin of Central
Kalimantan in 2015, in accordance with the PSA and with government
approval.
In China BP has a 30% equity stake in the 6.8 million tonnes per annum
capacity Guangdong LNG regasification and pipeline project, making it
the first foreign partner in China’s LNG import business. The terminal 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
35.8%) and Shah Deniz (BP 28.83%) and also holds other exploration
leases.
* Defined on page 256.
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• In 2012 further EU and US regulations concerning restrictive measures
against Iran were issued. The Shah Deniz joint operation and its gas
marketing and pipeline entities, in which Naftiran Intertrade Co Ltd
(NICO) has an interest, were excluded from the main operative
provisions of the EU regulations, and from the application of the new
US sanctions, as they fall within the exception for certain natural gas
projects under Section 603 of the US Iran Threat Reduction and Syria
Human Rights Act of 2012. The Shah Deniz Stage 2 project is also
excluded from the EU and US sanctions. For further information see
International trade sanctions on page 242.
• In April we received final ratification by the government of Azerbaijan
on the new PSA with the State Oil Company of the Republic of
Azerbaijan, signed in December 2014, to jointly explore for and develop
potential prospects in the shallow water area around the Absheron
peninsula.
• The Shah Deniz Stage 2 project continues to move ahead with a
number of milestones achieved ahead of schedule. The Shah Deniz
Stage 2 project is now more than 50% complete in terms of
engineering, procurement and construction, and remains on target for
first gas in 2018.
BP holds a 30.1% interest in and operates the Baku-Tbilisi-Ceyhan (BTC)
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 BTC pipeline has a capacity of
1mmboe/d with average throughput in 2015 of 716.7mboe/d.
BP is technical operator of, and currently holds a 28.83% interest in, the
693 kilometre South Caucasus Pipeline (SCP). The pipeline takes gas from
Azerbaijan through Georgia to the Turkish border and has a capacity of
134mboe/d with average throughput in 2015 of 113.2mboe/d. BP (as
operator of Azerbaijan International Operating Company) also operates the
Western Export Route Pipeline that transports ACG oil to Supsa on the
Black Sea coast of Georgia, with average throughput of 86mboe/d in 2015.
In April BP became a shareholder in the Trans Anatolian Natural Gas
Pipeline (TANAP), and now holds a 12% equity share in the project.
TANAP is a central part of the Southern Corridor pipeline system that will
transport gas from the Shah Deniz field in Azerbaijan to markets in
Turkey, Greece, Bulgaria and Italy.
In Oman, BP is continuing with development activity on the BP-operated
Khazzan field in block 61 (BP 60%).
• By the end of 2015 10 rigs were operational, drilling the development
wells at Khazzan. The project is more than 40% complete and work
continues on the central processing facility and the associated
infrastructure. Gas production is expected to start in late 2017.
• In February 2016 BP announced it had signed a heads of agreement
with the government of the Sultanate of Oman to amend the block 61
EPSA, extending the licence area of the block and enabling further
development of the Khazzan field.
In Abu Dhabi, we have an equity interest of 14.67% in an offshore
concession. We also have a 10% equity shareholding in the Abu Dhabi
Gas Liquefaction Company that supplied 5.7 million tonnes of LNG
(295.7bcfe regasified) in 2015.
In India, we have a 30% interest in four oil and gas PSAs operated by
Reliance Industries Limited (RIL), and partner with RIL in a 50:50 joint
operation for the gas sourcing and marketing in India.
• In 2015 a number of activities to sustain production and extend the life
of the producing fields in KG D6 block were completed. These included
well side-tracks, the installation of additional onshore compression,
reactivation of shut-in wells and production optimization.
• We also undertook successful tests of three earlier discoveries; two in
the KG D6 block and one in the NEC 25 block to progress towards
Declaration of Commerciality.
• We continue to expect further clarity on the gas price policy to emerge
in due course.
In Iraq, BP holds a 47.6% working interest and is the lead contractor in
the Rumaila technical service contract in Southern Iraq. Rumaila is one of
the world’s largest oil fields, comprising five producing reservoirs. BP’s
total assets in Iraq at 31 December 2015 were $1,707 million
($1,281 million current and $426 million non-current). BP has undertaken
studies with the government of Iraq and North Oil Company in support of
the stabilization and redevelopment of two producing reservoirs in the
Kirkuk field. Access to the Kirkuk field in 2015 was restricted due to the
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security situation and the term of the agreement expired at the end of
2015. BP is entitled to recover all costs incurred to that date. Despite
instability and sectarian violence in the north and west of the country, BP
operations continued as planned in the south.
In Russia, we acquired a 20% participatory interest in a Rosneft
subsidiary, Taas-Yuryakh Neftegazodobycha, in 2015, that will further
develop the Srednebotuobinskoye oil and gas condensate field in East
Siberia. Related to this, Rosneft and BP will jointly undertake exploration
in an adjacent area of mutual interest.
Rosneft and BP have also agreed to jointly explore two additional areas of
mutual interest in the prolific West Siberian and Yenisey-Khatanga basins
where they will jointly appraise the Baikalovskoye discovery subject to
receipt of all relevant consents. This is in addition to the exploration
agreement announced in 2014 for an area of mutual interest in the Volga-
Urals region of Russia where Rosneft and BP have commenced joint
study work to assess potential non-shale, unconventional tight-oil*
exploration projects (see Rosneft on page 38).
Australasia
We are active in Australia and Eastern Indonesia.
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 principal 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 annum.
BP also holds a 5.375% interest in the Jansz-lo field and 12.5% interests
in the Geryon, Orthrus, Maenad, Urania and Eurytion fields which are part
of the Greater Gorgon project. BP’s Jansz-Io interest is in the reserves
and wells which will provide the initial feed gas to the Gorgon LNG plant,
scheduled to commence production in early 2016.
BP holds a 70% interest in four deepwater offshore exploration blocks in
the Ceduna Sub Basin in the Great Australian Bight off the coast of
southern Australia. BP, as operator, expects drilling to commence in late
2016 in this frontier exploration basin. It is also one of five participants in
the Browse LNG venture (operated by Woodside) and holds a 17%
interest.
• The Browse joint operation partners agreed to enter FEED for an
offshore floating LNG concept in June. The proposed development
remains subject to regulatory, joint venture and internal BP approvals.
• In October the Western Flank A project (BP 16.67%) in offshore
Western Australia began production. The Western Flank A project is
the first of a series of subsea tie-back projects that have been
undertaken to extend the production plateau and supply additional gas
to the NWS’s five existing LNG trains and domestic gas plant. The
project is operated by Woodside.
• The Persephone project (BP 16.67%) is the second of the NWS series
of subsea tie-back projects and is on schedule to deliver first gas in the
second half of 2017.
In Eastern Indonesia, BP operates the Tangguh LNG plant. Tangguh
(BP 37.16%), is located in Papua Barat. The asset comprises 14 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, China, South
Korea, Mexico and Japan through a combination of long, medium and
short-term contracts. Plans for a third train, the Tangguh expansion project,
remain on track, with first production expected in 2020.
• The Tangguh expansion project is progressing, with completion of dual
onshore FEED to two separate consortia on the third LNG train during
2015. Marketing on the third train capacity continues, with 65% of the
volumes already contracted.
BP has 100% interests in two deepwater PSAs, West Aru I and II, and
32% interests in the Chevron-operated West Papua I and Ill PSAs. These
PSAs will be relinquished pending approval from the government of
Indonesia.
Downstream plant capacity
The following table summarizes BP group’s interests in refineries and average daily crude distillation capacities as at 31 December 2015.
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
Germany
Netherlands
Spain
Cherry Point
Whiting
Toledo
Bayernoilc
Gelsenkirchen
Karlsruhec
Lingen
Schwedtc
Rotterdam
Castellón
Australia
New Zealand Whangareic
South Africa
Kwinana
Durbanc
Total BP share of capacity at 31 December 2015
a Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period.
b BP share of equity, which is not necessarily the same as BP share of processing entitlements.
c Indicates refineries not operated by BP.
Crude distillation capacitiesa
Group interestb
(%)
BP share
thousand barrels
per day
100
100
50
22.5
50
12
100
18.8
100
100
100
21.2
50
234
430
80
744
49
132
39
95
45
377
110
847
146
26
90
262
1,853
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BP Annual Report and Form 20-F 2015
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Petrochemicals production capacitya
The following table summarizes BP group’s share of petrochemicals production capacities as at 31 December 2015.
Geographical area
US
Europe
UK
Belgium
Germany
Rest of world
Trinidad & Tobago
China
Indonesia
South Korea
Malaysia
Taiwan
Total BP share of capacity at 31 December 2015
BP share of capacity
thousand tonnes per annumb
Site
Group interest
(%)c
PTA
PX
Acetic
acid
Olefins and
derivatives
Cooper River
Decaturd
Texas City
Hulld
Geel
Gelsenkirchenf
Mülheimf
Point Lisas
Caojing
Chongqing
Nanjing
Zhuhaih
Merak
Ulsan
Kertih
Mai Liao
Taichung
100.0
100.0
100.0
100.0
100.0
50-61.0
50.0
36.9
50.0
51.0
50.0
85.0
100.0
34-51.0
70.0
50.0
61.4
1,300
1,000
–
2,300
–
1,300
–
–
1,300
–
–
–
–
2,400
500
–
–
–
500
3,400
7,000
–
700
900
1,600
–
700
–
–
700
–
–
–
–
–
–
–
–
–
–
–
2,300
–
–
600e
600
500
–
–
–
500
–
–
200
300
–
–
300g
400
200
–
1,400
2,500
–
–
–
–
–
–
1,800g
–
1,800
–
3,500
–
–
–
–
–
–
–
–
3,500
5,300
Product
Others
–
–
100
100
200
–
–
100
300
700
–
100
–
–
–
100g
–
–
–
900
1,300
18,400
a Petrochemicals production capacity is the proven maximum sustainable daily rate (MSDR) multiplied by the number of days in the respective period, where MSDR is the highest average daily rate ever
achieved over a sustained period.
b Capacities are shown to the nearest hundred thousand tonnes per annum.
c Includes BP share of equity-accounted entities, as indicated.
d These sites have capacity under 100,000 tonnes per annum for a speciality product (e.g. naphthalene dicarboxylate and ethylidene diacetate). In January 2016 we announced the sale of the Decatur, US
petrochemicals complex.
e Group interest is quoted at 100%, reflecting the capacity entitlement, which is marketed by BP.
f Due to the integrated nature of these plants with our Gelsenkirchen refinery, the income and expenditure of these plants is managed and reported through the fuels business.
g Group interest varies by product.
h BP Zhuhai Chemical Company Ltd is a subsidiary* of BP, the capacity of which is shown above at 100%.
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Oil and gas disclosures for the group
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.
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 2015 BP had material volumes of proved undeveloped
reserves held for more than five years in Trinidad, the North Sea and the
Gulf of Mexico. 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.
Over the past five years, BP has annually progressed a weighted average
18% 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 about five and a half years.
We expect the turnover time to remain near this level and anticipate the
volume of proved undeveloped reserves held for more than five years to
remain about the same.
In 2015 we progressed 959mmboe of proved undeveloped reserves
(626mmboe 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 $16,731 million in 2015
($13,458 million for subsidiaries and $3,273 million for equity-accounted
entities). The major areas with progressed volumes in 2015 were Angola,
Azerbaijan, Russia, UK and US. 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
volumes in mmboea
Proved undeveloped reserves at 1 January 2015
Revisions of previous estimates
Improved recovery
Discoveries and extensions
Purchases
Sales
Total in year proved undeveloped reserves changes
Progressed to proved developed reserves
Proved undeveloped reserves at 31 December 2015
7,788
300
111
339
126
(17)
8,646
(959)
7,687
Subsidiaries only
volumes in mmboea
Proved undeveloped reserves at 1 January 2015
Revisions of previous estimates
Improved recovery
Discoveries and extensions
Purchases
Sales
Total in year proved undeveloped reserves changes
Progressed to proved developed reserves
Proved undeveloped reserves at 31 December 2015
4,507
61
106
79
101
(17)
4,837
(626)
4,211
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:
1. Well data used to assess the local characteristics and conditions of
reservoirs and fluids.
2. Field scale seismic data to allow the interpolation and extrapolation of
these characteristics outside the immediate area of the local well
control.
3. Data from relevant analogous fields.
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
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.
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227
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 petroleum engineer
primarily responsible for overseeing the preparation of the reserves
estimate. He has more than 30 years of diversified industry experience
with more than 10 years spent managing the governance and compliance
of BP’s reserves estimation. He is a past member of the Society of
Petroleum Engineers Oil and Gas Reserves Committee and of the
American Association of Petroleum Geologists Committee on Resource
Evaluation and is the current chair of the bureau of the United Nations
Economic Commission for Europe Expert Group on Resource
Classification.
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 some 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 with the exception of those
proved reserves held by our Russian equity-accounted entity, Rosneft,
are estimated 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 2015, 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
2015. 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 Regulation S-X. All reserves estimates involve
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some degree of uncertainty. BP has filed D&M’s independent report on
its reserves estimates as an exhibit to its 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
Eighty-four per cent of our total proved reserves of subsidiaries at
31 December 2015 were held through joint operations* (84% in 2014),
and 34% of the proved reserves were held through such joint operations
where we were not the operator (33% in 2014).
Estimated net proved reserves of crude oil at 31 December 2015a b c
UK
Rest of Europe
US
Rest of North America
South America
Africa
Rest of Asia
Australasia
Subsidiaries*
Equity-accounted entities
Total
Developed
Undeveloped
141
86
890
46
8
340
598
35
2,146
3,225
5,371
298
19
577
205
18
89
192
16
1,414
2,292
3,707
million barrels
Total
440
106
1,467
252
26
429
790
51
3,560
5,517
9,078
Estimated net proved reserves of natural gas liquids at 31 December 2015a b
million barrels
UK
Rest of Europe
US
Rest of North America
South America
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entities
Total
Developed
Undeveloped
5
11
269
–
7
5
–
9
308
45
352
4
1
70
–
28
10
–
2
115
15
130
Total
10
12
339
–
35
15
–
12
422
60
482
Estimated net proved reserves of liquids*
Subsidiaries
Equity-accounted entities
Total
Developed
Undeveloped
2,453
3,270
5,723
1,529
2,307
3,836
million barrels
Total
3,982d e
5,577f
9,560
In 2015 net additions to the group’s proved reserves (excluding
production and sales and purchases of reserves-in-place) amounted to
751mmboe (212mmboe for subsidiaries and 539mmboe for
equity-accounted entities), through revisions to previous estimates,
improved recovery from, and extensions to, existing fields and
discoveries of new fields. The subsidiary additions through improved
recovery from, and extensions to, existing fields and discoveries of new
fields were in existing developments where they represented a mixture
of proved developed and proved undeveloped reserves. Volumes added
in 2015 principally resulted from the application of conventional
technologies and increases in PSA entitlement as a result of lower prices.
The principal proved reserves additions in our subsidiaries were in
Angola, Azerbaijan, Canada, Egypt and Iraq. We had material reductions
in our proved reserves in the US principally due to activity reduction and
lower price. The principal reserves additions in our equity-accounted
entities were in Argentina and Russia.
Sixteen per cent of our proved reserves are associated with PSAs. The
countries in which we operated under PSAs in 2015 were Algeria,
Angola, Azerbaijan, Egypt, India, Indonesia, Oman and a non-material
volume of our proved reserves in Trinidad. In addition, the technical
service contract (TSC) governing our investment in the Rumaila field in
Iraq functions as a PSA.
Our Abu Dhabi offshore and Virginia Indonesia Company LLC (Western
Indonesia) conventional concessions are due to expire in 2018. The group
holds no other licences due to expire within the next three years that
would have a significant impact on BP’s reserves or production.
For further information on our reserves see page 176.
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Estimated net proved reserves of natural gas at 31 December 2015a b
billion cubic feet
UK
Rest of Europe
US
Rest of North America
South America
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entities
Total
Developed
Undeveloped
348
274
6,257
–
2,071
847
1,803
3,408
15,009
6,856
21,865
343
14
2,105
–
5,989
2,305
3,455
1,343
15,553
6,778
22,331
Total
691
288
8,363
–
8,060
3,152
5,257
4,751
30,563g
13,634h
44,197
Estimated net proved reserves on an oil equivalent basis
Subsidiaries
Equity-accounted entities
Total
million barrels of oil equivalent
Developed
Undeveloped
5,041
4,452
9,493
4,211
3,476
7,687
Total
9,252
7,928
17,180
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, 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 2015 marker prices used were Brent* $54.17/bbl (2014 $101.27/bbl and 2013 $108.02/bbl)
and Henry Hub* $2.59/mmBtu (2014 $4.31/mmBtu and 2013 $3.66/mmBtu).
c Includes condensate and bitumen which are not material.
d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 23 million barrels on
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 19 million barrels of liquids in respect of the 30% non-controlling interest in BP Trinidad
and Tobago LLC.
f Includes 70 million barrels of crude oil in respect of the 1.27% non-controlling interest in Rosneft
held assets in Russia including 28 million barrels held through BP’s equity-accounted interest in
Taas-Yuryakh Neftegazodobycha.
g Includes 2,359 billion cubic feet of natural gas in respect of the 30% non-controlling interest in
BP Trinidad and Tobago LLC.
h Includes 129 billion cubic feet of natural gas in respect of the 0.23% non-controlling interest in
Rosneft held assets in Russia including 5 billion cubic feet held through BP’s equity-accounted
interest in Taas-Yuryakh Neftegazodobycha.
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 2015, on an oil
equivalent basis including equity-accounted entities, decreased by 2%
(decrease of 5% for subsidiaries and increase of 1% for equity-accounted
entities) compared with 31 December 2014. Natural gas represented
about 44% (57% for subsidiaries and 30% for equity-accounted entities)
of these reserves. The change includes a net increase from acquisitions
and disposals of 130mmboe (103mmboe within our subsidiaries and
28mmboe within our equity-accounted entities). Acquisition activity in our
subsidiaries occurred in Egypt, Trinidad, the US and the UK, and
divestment activity in our subsidiaries in Egypt, Trinidad, the US and the
UK. In our equity-accounted entities the most significant item was a
purchase in Russia.
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 2015, the proved reserves replacement ratio excluding acquisitions
and disposals was 61% (63% in 2014 and 129% in 2013) for subsidiaries
and equity-accounted entities, 28% for subsidiaries alone and 115% for
equity-accounted entities alone. The ratio reflects lower reserves
bookings as a result of a low number of final investment decisions adding
new projects and reduced activity in Alaska and the US Lower 48. Lower
prices impacted the reserves in a number of regions, but these were
largely offset by increases in reserves in our PSAs. In some cases, cost
recovery in PSAs may be limited by production or revenue caps.
* Defined on page 256.
BP Annual Report and Form 20-F 2015
229
BP’s net production by country – crude oila and natural gas liquids
Subsidiaries
UKc d
Norway
Total Rest of Europe
Total Europe
Alaskac
Lower 48 onshorec
Gulf of Mexico deepwaterc
Total US
Canada
Total Rest of North America
Total North America
Trinidad & Tobagoc
Brazilc
Total South America
Angola
Egyptc
Algeria
Total Africa
Azerbaijanc
Western Indonesia
Iraq
Other
Total Rest of Asia
Total Asia
Australia
Other
Total Australasia
Total subsidiaries
Equity-accounted entities (BP share)
TNK-BP (Russia, Venezuela, Vietnam)c e
Rosneft (Russia, Canada,Venezuela, Vietnam)c f
Abu Dhabig
Argentina
Bolivia
Egypt
Otherc
Total equity-accounted entities
Total subsidiaries and equity-accounted entitiesh
2015
2014
Crude oil
2013
72
38
38
110
107
14
203
323
3
3
46
41
41
87
127
14
206
347
–
–
58
31
31
89
137
12
156
305
–
–
327
347
305
12
–
12
221
42
6
270
111
2
123
1
237
237
15
2
17
13
–
13
181
37
5
222
98
2
55
2
156
156
17
2
19
10
7
17
180
33
3
217
96
1
39
4
141
141
19
2
21
thousand barrels per day
BP net share of productionb
2015
2014
Natural gas
liquids
2013
7
5
5
11
–
37
19
56
–
–
56
11
–
11
–
–
7
7
–
–
–
–
1
1
3
–
3
2
5
5
7
–
45
18
63
–
–
63
12
–
12
–
–
5
5
–
–
–
–
–
–
3
–
3
3
4
4
7
–
45
13
58
–
–
58
12
–
12
–
–
3
3
–
–
–
1
1
1
4
–
4
971
844
789
88
91
86
–
809
96
65
4
–
1
–
816
97
62
3
–
1
183
643
231
60
2
–
1
974
979
1,120
1,946
1,823
1,909
–
4
–
3
–
3
–
10
99
–
5
–
3
–
4
–
4
7
–
3
–
5
–
12
104
19
105
a Includes condensate and bitumen which are not material.
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 2015, BP acquired an interest in Taas-Yuryakh Neftegazodobycha. It also increased its interest in the North Alexandria and West Mediterranean Deep Water Concessions of the West Nile Delta
project in Egypt. It increased its interest in certain UK North Sea, Trinidad, and US onshore assets. It also decreased its interest in certain other assets in the same Regions. In 2014, BP divested its
interests in the Endicott and Northstar fields, and 50% of its interests in the Milne Point field, in Alaska, its interest in the US onshore Hugoton upstream operation and its interest in the Polvo asset in
Brazil. BP also reduced its interest in certain wells in the US onshore Eagle Ford Shale in south Texas. It increased its interest in the Shah Deniz asset in Azerbaijan, in certain UK North Sea assets, and
in certain US onshore assets. In 2013, BP divested its interests in TNK-BP, its interests in the Harding, Devenick, Maclure, Braes and Braemar fields in the North Sea and its interests in the US onshore
Moxa upstream operation in Wyoming. It also acquired an interest in Rosneft.
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 Estimated production for 2013 represents BP’s share of TNK-BP’s estimated production from 1 January to 20 March, averaged over the full year.
f 2015 is based on preliminary operational results of Rosneft for the three months ended 31 December 2015. Actual results may differ from these amounts. 2013 reflects production for the period
21 March to 31 December, averaged over the full year.
g BP holds interests, through associates, in offshore concessions in Abu Dhabi which expire in 2018. We also held onshore concessions which expired in 2014.
h Includes 4 net mboe/d of NGLs from processing plants in which BP has an interest (2014 7mboe/d and 2013 5.5mboe/d).
Because of rounding, some totals may not agree exactly with the sum of their component parts.
230
BP Annual Report and Form 20-F 2015
BP’s net production by country – natural gas
Subsidiaries
UKb
Norway
Total Rest of Europe
Total Europe
Lower 48 onshoreb
Gulf of Mexico deepwaterb
Alaska
Total US
Canada
Total Rest of North America
Total North America
Trinidad & Tobagob
Total South America
Egyptb
Algeria
Total Africa
Azerbaijanb
Western Indonesia
India
Otherb
Total Rest of Asia
Total Asia
Australia
Eastern Indonesia
Total Australasia
Total subsidiariesc
Equity-accounted entities (BP share)
TNK-BP (Russia, Venezuela, Vietnam)b d
Rosneft (Russia, Canada, Venezuela, Vietnam)b e
Argentina
Bolivia
Otherb
Total equity-accounted entitiesc
Total subsidiaries and equity-accounted entities
million cubic feet per day
BP net share of productiona
2015
2014
2013
155
111
111
266
71
102
102
173
157
80
80
237
1,353
1,350
1,404
168
7
159
11
114
21
1,528
1,519
1,539
10
10
10
10
11
11
1,538
1,529
1,551
1,922
1,922
2,147
2,147
2,221
2,221
402
187
589
219
48
113
–
380
380
447
354
801
406
107
513
230
47
131
–
408
408
450
364
814
444
117
561
203
51
156
81
490
490
431
353
784
5,495
5,585
5,845
–
–
1,195
1,084
184
617
329
55
30
323
80
28
1,515
1,216
7,100
7,060
341
93
21
1,651
7,146
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 2015, BP acquired an interest in Taas-Yuryakh Neftegazodobycha. It also increased its interest in the North Alexandria and West Mediterranean Deep Water Concessions of the West Nile Delta
project in Egypt. It increased its interest in certain UK North Sea, Trinidad, and US onshore assets. It also decreased its interest in certain other assets in the same Regions. In 2014, BP divested its
interest in the US onshore Hugoton upstream operation. BP also reduced its interest in certain wells in the US onshore Eagle Ford Shale in south Texas. It increased its interest in the Shah Deniz asset
in Azerbaijan, in certain UK North Sea assets, and in certain US onshore assets. In 2013, BP divested its interests in TNK-BP, its interests in the Harding, Devenick, Maclure, Braes, Braemar and Sean
fields in the North Sea, its interests in the US onshore Moxa upstream operation in Wyoming and its interests in the Yacheng gas field in the South China Sea. It also acquired an interest in Rosneft.
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 Estimated production for 2013 represents BP’s share of TNK-BP’s estimated production from 1 January to 20 March, averaged over the full year.
e 2015 is based on preliminary operational results of Rosneft for the three months ended 31 December 2015. Actual results may differ from these amounts. 2013 reflects production for the period
21 March to 31 December, averaged over the full year.
Because of rounding, some totals may not agree exactly with the sum of their component parts.
BP Annual Report and Form 20-F 2015
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The following tables provide additional data and disclosures in relation to our oil and gas operations.
Average sales price per unit of productiona
$ per unit of production
Total
group
average
47.78
20.75
3.80
93.65
36.15
5.70
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
Africa
Asia
Australasia
Russiab
Rest of
Asia
Subsidiaries
2015
Crude oilc
Natural gas liquids
Gas
2014
Crude oilc
Natural gas liquids
Gas
2013
Crude oilc
Natural gas liquids
Gas
Equity-accounted entitiesd
2015
Crude oilc
Natural gas liquids
Gas
2014
Crude oilc
Natural gas liquids
Gas
2013
52.42
30.66
7.83
96.02
58.11
8.13
50.68
28.20
6.49
97.77
52.97
8.22
49.84
14.80
2.10
93.66
32.28
3.80
107.83
62.53
9.43
107.78
61.82
10.18
102.07
30.95
3.07
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
26.71
–
–
–
–
–
–
–
–
–
–
–
–
–
–
41.41
–
5.35
91.05
–
6.28
50.64
36.69
7.35
94.04
65.70
11.20
53.19
27.66
2.67
96.85
41.62
4.65
49.09
31.94
4.40
93.99
53.67
5.92
106.37
54.92
4.66
107.02
69.39
5.75
–
–
–
–
–
–
–
–
–
108.26
–
4.99
105.89
68.13
10.55
105.38
38.38
5.35
54.24
13.17
4.35
73.87
15.75
4.73
–
–
–
–
–
–
44.78
n/a
1.48
84.19
n/a
2.18
16.87
–
7.56
14.70
–
12.83
–
–
–
–
–
–
41.49
13.17
2.35
72.53
15.75
3.01
Crude oilc
Natural gas liquids
Gas
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 The operational and financial information of the Rosneft segment for 2015 is based on preliminary operational and financial results of Rosneft for the three months ended 31 December 2015. Actual
95.28
n/a
2.47
74.01
29.63
4.05
11.58
–
13.21
63.51
29.63
3.26
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
results may differ from these amounts. Crude oil includes natural gas liquids.
c Includes condensate. 2015 for subsidiaries also includes bitumen.
d 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 at discounted
prices.
Average production cost per unit of productiona
Subsidiaries
2015
2014
2013
Equity-accounted entities
2015
2014
2013
$ per unit of production
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
US
22.95
44.67
34.10
13.80
18.85
24.48
11.84
14.22
16.11
43.56
–
–
–
–
–
–
–
–
–
–
–
–
–
–
Russiab
Rest of
Asia
5.44
5.43
5.92
12.10
11.28
12.16
11.02
13.37
13.84
–
–
–
9.81
15.55
13.20
–
–
–
2.60
3.82
4.36
4.59
4.34
4.19
2.88
3.92
3.21
–
–
–
Total
group
average
10.26
12.68
13.16
3.93
4.75
5.28
a Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes.
b The operational and financial information of the Rosneft segment for 2015 is based on preliminary operational and financial results of Rosneft for the three months ended 31 December 2015. Actual
results may differ from these amounts.
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BP Annual Report and Form 20-F 2015
Environmental expenditure
Environmental expenditure relating to the
Gulf of Mexico oil spill
Operating expenditure
Capital expenditure
Clean-ups
Additions to environmental remediation
provision
Additions to decommissioning provision
2015
2014
5,452
521
733
34
190
624
590
33
$ million
2013
(66)a
657
1,091
42
305
972
371
2,216
472
2,092
a The environmental expenditure credit of $66 million in 2013 arises primarily from the write-back
of a spill response provision.
Environmental expenditure relating to the Gulf of
Mexico oil spill
For full details of all environmental activities in relation to the Gulf of
Mexico oil spill, see Financial statements – Note 2.
Other environmental expenditure
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 $521 million in 2015 (2014
$624 million) decreased primarily due to Downstream reduced level of
turnaround activity in 2015.
Environmental capital expenditure in 2015 was higher than in 2014,
primarily driven by the installation of a dissolved nitrogen floatation unit at
Whiting refinery’s wastewater treatment plant that is designed to
improve the quality of cleaned water before it leaves the refinery. The
increase also reflects the investment at our Cooper River, US and Geel,
Belgium petrochemicals site to upgrade it to our latest generation PTA
technology that is expected to significantly increase manufacturing
efficiency resulting in lower greenhouse gas emissions and improved
energy efficiency.
Clean-up costs increased to $34 million in 2015 compared with
$33 million in 2014, primarily due to higher remediation management
costs.
In addition to operating and capital expenditures, we also establish
provisions for future environmental remediation. 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.
In 2015 the additions to the environmental provision were lower as 2014
included more new sites and increased provisions from existing sites
resulting from recent acquisitions. The charge for environmental
remediation provisions in 2015 included $6 million in respect of
provisions for new sites (2014 $13 million and 2013 $13 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 2015 additions to the decommissioning provision were less than in
2014, and occurred as a result of detailed reviews of expected future
costs. The majority of these additions related to our sites in the North
Sea, the Gulf of Mexico and Angola. The additions in 2013 and 2014
were driven by detailed reviews of expected future costs, increases to
the asset base and for 2013, changes in estimation processes.
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 the financial statements – Note 22.
Regulation of the group’s business
BP’s activities, including its oil and gas exploration and production,
pipelines and transportation, refining and marketing, petrochemicals
production, trading, biofuels, wind and shipping activities, are conducted
in more than 70 countries and are subject to a broad range of EU, US,
international, regional and local legislation and regulations, including
legislation that implements international conventions and protocols.
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.
The terms and conditions of the leases, licences and contracts under
which our 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 the US government can be by lease. Arrangements
with private property owners are usually in the form of leases.
Licences (or concessions) give the holder the right to explore for and
exploit 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. Less typically, BP may explore for and
exploit 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.
PSAs entered into with a government entity or state-owned or
controlled company generally require BP 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.
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.
Both exploration and production licences are generally for a specified
period of time. In the US, leases from the US government typically
remain in effect for a specified term, but may be extended beyond that
term as long as there is production in paying quantities. The term of
BP’s licences and the extent to which these licences may be renewed
vary from country to country.
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. These joint arrangements may be incorporated or
unincorporated arrangements, while the co-ownerships are typically
unincorporated. Whether incorporated or unincorporated, relevant
agreements set out each party’s level of participation or ownership
BP Annual Report and Form 20-F 2015
233
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interest in the joint arrangement or co-ownership. Conventionally, all
costs, benefits, rights, obligations, liabilities and risks incurred in carrying
out joint arrangement or co-ownership operations under a lease or
licence are shared among the joint arrangement or co-owning parties
according to these agreed ownership interests. Ownership of joint
arrangement or co-owned property and hydrocarbons to which the joint
arrangement or co-ownership is entitled is also shared in these
proportions. 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 where it has exploration
and production activities.
Frequently, work (including drilling and related activities) will be
contracted out to third-party service providers who have the relevant
expertise and equipment not available within the joint arrangement or
the co-owning operator’s organization. The relevant contract will specify
the work to be done and the remuneration to be paid and will typically
set out how major risks will be allocated between the joint arrangement
or co-ownership and the service provider. Generally, the joint
arrangement or co-owner and the contractor would respectively allocate
responsibility for and provide reciprocal indemnities to each other for
harm caused to and by their respective staff and property. Depending on
the service to be provided, an oil and gas industry service contract may
also contain provisions allocating risks and liabilities associated with
pollution and environmental damage, damage to a well or hydrocarbon
reservoir 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.
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.
Environmental regulation
Current and proposed fuel and product specifications, emission controls
(including control of vehicle emissions), 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.
There are also environmental laws that 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 22 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
234
BP Annual Report and Form 20-F 2015
developments, such as stricter environmental laws 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 233.
A significant proportion of our fixed assets are located in the US and the
EU. US and EU environmental, health and safety regulations significantly
affect BP’s operations. Significant legislation and regulation in the US
and the EU affecting our businesses and profitability includes the
following:
United States
• The Clean Air Act (CAA) regulates air emissions, permitting, fuel
specifications and other aspects of our production, distribution and
marketing activities. Stricter limits on sulphur in fuels will affect us in
future, as will actions on greenhouse gas (GHG) emissions and other
air pollutants. The revised lower ambient air quality standard for ozone,
finalized by the Environmental Protection Agency (EPA) in October
2015, as well as proposed new restrictions on methane and volatile
organic emissions and on gas flaring, will affect our US operations in
the future. States may also have separate, stricter air emission laws in
addition to the CAA.
• The Energy Policy Act of 2005 and the Energy Independence and
Security Act of 2007 affect our US fuel markets by, among other
things, imposing renewable fuel mandates and imposing GHG
emissions thresholds for certain renewable fuels. States such as
California also impose additional carbon fuel standards as well as Low
Emission Vehicle (LEV) and Zero Emission Vehicle (ZEV) standards
imposed on vehicle manufacturers. These regulations will have an
impact on fuel demand and product mix in California and those states
adopting LEV and ZEV standards.
• 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.
• 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 arranged
for disposal of a hazardous substance at a site. BP has incurred, or is
likely to incur, liability under the CERCLA or similar state laws,
including costs attributed to insolvent or unidentified parties. BP is also
subject to claims for remediation costs under other federal and state
laws, and to claims for natural resource damages under the CERCLA,
the Oil Pollution Act of 1990 (OPA 90) (discussed below) and other
federal and state laws. CERCLA also requires notification of releases of
hazardous substances to national, state and local government
agencies, as applicable. In addition, the Emergency Planning and
Community Right-to-Know Act requires notification of releases of
designated quantities of certain listed hazardous substances to state
and local government agencies, as applicable.
• The Toxic Substances Control Act regulates BP’s manufacture, import,
export, sale and use of chemical substances and products.
• 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 and refining facilities.
• In May 2012, the US adopted the UN Global Harmonization System
(GHS) for hazard classification and labelling of chemicals and products,
with the modification of the Occupational Safety & Health
Administration (OSHA) Hazard Communication Standard. This required
BP to reassess the hazards of all of its chemicals and products against
new GHS criteria as adopted or modified by OSHA and warning labels
and safety data sheets were updated accordingly by 1 June 2015.
• The US Department of Transportation (DOT) regulates the transport of
BP’s petroleum products such as crude oil, gasoline, petrochemicals
and other hydrocarbon liquids.
• The Maritime Transportation Security Act, the DOT Hazardous
Materials (HAZMAT) and the Chemical Facility Anti-Terrorism Standard
regulations impose security compliance regulations on around 15 BP
facilities.
• OPA 90 is implemented through regulations issued by the EPA, the
US Coast Guard, the DOT, OSHA, the Bureau of Safety and
Environmental Enforcement and various states. Alaska and the West
Coast states currently have the most demanding state requirements.
443/2009). From 2020 onwards, the European passenger fleet
emissions target is 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
addition, vehicle emission test cycles and vehicle type approval
procedures are being updated to improve accuracy of emission and
efficiency measurements. Consequently, product mix and overall levels
of demand will be impacted.
• The Outer Continental Shelf Land Act and other statutes give the
• European vehicle CO2 emission regulations also impact the fuel
Department of Interior (DOI) and the Bureau of Land Management
(BLM) authority to regulate operations and air emissions on offshore
and onshore operations on federal lands subject to DOI authority. New
stricter regulations on operational practices, equipment and testing
have been imposed on our operations in the Gulf of Mexico and
elsewhere following the Deepwater Horizon oil spill.
European Union
• In October 2014, the European Council agreed on new climate and
energy targets for the period up to 2030. Specifically, Member States
have agreed to a 40% reduction in GHG emissions below 1990 levels
and to a 27% share of renewable energy in final energy consumption.
Specific EU legislation and agreements required to achieve these goals
are not yet in place.
• The 2008 EU Climate and Energy Package is expected to remain in
place until 2020 and includes an updated EU Emissions Trading
System (EU ETS) Directive (see Greenhouse gas regulation below), the
EU Fuel Quality Directive and the Renewable Energy Directive.
• The EU Fuel Quality Directive affects our production and marketing of
transport fuels. Revisions adopted in 2009 mandate reductions in the
life cycle GHG emissions per unit of energy and tighter environmental
fuel quality standards for petrol and diesel.
• The Renewable Energy Directive requires Member States to have 10%
(by energy content) of final transportation fuel to be derived from
renewable energy, such as biofuels and renewable electricity. This
target must be met by the end of 2020.
• The Energy Efficiency Directive (EED) was adopted in 2012. It requires
EU Member States to implement an indicative 2020 energy saving
target and apply a framework of measures as part of a national energy
efficiency programme, including mandatory industrial energy efficiency
surveys. This directive has been implemented in the UK by the Energy
Savings Opportunity Scheme Regulations 2014, which affects our
offshore and onshore assets. The ISO50001 standard is being
implemented by organizations in some EU states to meet some
elements of the Energy Efficiency Directive.
• 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. This may result in requirements for BP to
further reduce its emissions, particularly its air and water emissions. As
part of the IED framework, additional emission limit values are
informed by the sector specific and cross-sector Best Available
Technology (BAT) Conclusions, such as the BAT Conclusions for the
refining sector and for combustion.
• The National Emission Ceiling Directive 2001 is currently being revised
and subsequent source-control measures by Member States may be
required to meet national emissions targets. These may result in
further emission reduction requirements.
• The EU regulation on ozone depleting substances (ODS) 2009 requires
BP to reduce the use of ODS and phase out use of certain ODSs. BP
continues to replace ODS in refrigerants and/or equipment in the EU
and elsewhere, in accordance with the Montreal Protocol and related
legislation. In addition, the EU regulation on fluorinated greenhouse
gases with high global warming potential (the F-gas Regulations) came
into force on 1 January 2015. The F-gas Regulations require a phase-
out of certain hydrofluorocarbons, based on global warming potential.
• European regulations also establish passenger car performance
standards for CO2 tailpipe emissions (European Regulation (EC) No
efficiency of vans. By 2020, the EU fleet of newly registered vans must
meet a target of 147 grams of CO2 per kilometre, which is 19% below
the 2012 fleet average.
• The EU Registration, Evaluation Authorization and Restriction of
Chemicals (REACH) Regulation 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
refining, petrochemicals, exploration and production, biofuels,
lubricants and other manufacturing or trading/import operations. In
accordance with the required phase-in timetable, BP completed
registration of all substances in tonnage bands equal to or greater than
100 tonnes per annum/legal entity, and is in the process of preparing
registration dossiers for substances manufactured or imported in
amounts in the range 1-100 tonnes per annum/legal entity that are
currently due to be submitted before 31 May 2018 or checking that BP
imports are covered by the registrations of non-EU suppliers’ only
representatives. BP continues to maintain compliance by submitting
registrations to cover new manufactured and imported substances,
and to update 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, the EU implemented the UN’s Globally Harmonized
System of Classification and Labelling of Chemicals (GHS) through the
Classification Labelling and Packaging (CLP) Regulation. This requires
BP to reassess the hazards of all our chemicals and products against
the new GHS criteria as adopted or modified by the EU and to update
warning labels and safety data sheets accordingly. From 1 June 2015,
the CLP Regulation applies in full to mixtures (e.g. lubricants) that are
placed on the market. A separate EU regulation on export and import
of hazardous chemicals requires warning labels and safety data sheets
accompanying EU exports to be compliant with relevant CLP and
REACH requirements (unless this conflicts with requirements in the
importing country) and, as far as practicable, in the official or one or
more principal languages of the intended area of use. Safety data
sheets for the EU market have been updated to include both REACH
and CLP information.
• 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 implementation of the Water Framework Directive 2000 and the
Environmental Quality Standards Directive 2008 may mean that BP has
to take further steps to manage freshwater withdrawals and
discharges from its EU operations.
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. In Trinidad, BP has been working 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 been upgrading produced
water treatment systems to meet revised Oil in Water limits for produced
water discharge under Executive Decree ED 97-14 (superseded ED 12/05
on 1 January 2016).
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Environmental maritime regulations
BP’s shipping operations are subject to extensive national and
international regulations governing liability, operations, training, spill
prevention and insurance. These include:
• In US waters, OPA 90 imposes liability and spill prevention and
planning requirements governing, among others, tankers, barges and
offshore facilities. It 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 liability, spill response and preparedness
regulations under the UN’s International Maritime Organization,
including the International Convention on Civil Liability for Oil Pollution,
the International Convention for the Prevention of Pollution from Ships
(MARPOL) Convention, 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 year end, as the required minimum number of
contracting states had not been achieved, the HNS Convention has not
yet entered into force.
• Changes to the permitted level of sulphur in marine fuels under EU
mandated reductions for European waters and International Maritime
Organization (IMO) regulations are being phased in until 2020, when
the low sulphur rules for shipping in global waters are scheduled to
take effect. Depending on the outcome of ongoing IMO deliberations,
the regulations impacting operations in global waters may be delayed
until 2025. Regulations requiring the reduction of sulphur oxides
emissions will require ships to either burn low sulphur marine fuels or
continue using higher sulphur fuel along with approved on-board
sulphur abatement technology. Compliance with the IMO regulations
may place additional costs on refineries producing marine fuel,
including costs to dispose of sulphur, as well as increased GHG
emissions and energy costs for additional refining.
To meet its financial responsibility requirements, BP shipping maintains
marine liability pollution 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 will necessarily be adequately covered by insurance or that
liabilities will not exceed insurance recoveries.
Greenhouse gas regulation
In 2011, parties to the UN Framework Convention on Climate Change
(Framework Convention) at the Conference of the Parties (COP17) in
Durban agreed to several measures. One was a ‘roadmap’ for negotiating
a legal framework for action on climate change by 2015 that would
involve all countries by 2020 and would close the ‘ambition gap’ between
existing GHG reduction pledges and what is required to achieve the goal
of limiting global temperature rise to 2°C. Another was a second
commitment period for the Kyoto Protocol to begin immediately after the
first period. An amendment was subsequently adopted at the 2012
conference of parties in Doha (COP18) establishing a second
commitment period to run until the end of 2020. However, it did not
include the US, Canada, Japan and Russia and thus covers only about
15% of global emissions.
The 2014 conference in Lima (COP20) adopted the Lima Call for Climate
Action. This included the elements of a negotiating text for a new
international agreement, as specified in Durban in 2011, that would be
finalized at COP21 in Paris in December 2015. This text covers long-term
ambitions and pathways and a framework for reaching it. COP20 also
agreed on the rules for providing and assessing information about each
country’s ’Intended Nationally Determined Contributions’ towards
reaching the overall ambition. The world’s three largest emitters – China,
the US and the EU – have all announced their intentions to limit their
GHG emissions.
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In December 2015, 195 nations at the United Nations climate change
conference in Paris (COP21) adopted the Paris Agreement, for
implementation post-2020. This will come into force when it has been
ratified by at least 55 of the parties to the Framework Convention,
representing at least 55% of global GHG emissions. For the first time this
binds all participants to its provisions and encourages voluntary
contributions by developing countries. The Paris Agreement aims to hold
global average temperature rise to well below 2oC above pre-industrial
levels and to pursue efforts to limit temperature rise to 1.5oC above pre-
industrial levels. There is no quantitative long-term emissions goal but
countries aim to reach global peaking of GHG emissions as soon as
possible and to undertake rapid reductions thereafter to achieve a
balance between human caused emissions and natural absorption in the
second half of this century. The Paris Agreement places binding
commitments on all parties, from 2020, to make Nationally Determined
Contributions (NDCs) and pursue domestic measures aimed at achieving
the objectives of their NDCs. Developed country NDCs should include
absolute emission reduction targets, and developing countries are
encouraged to move over time towards them. The Paris Agreement
places binding commitments on countries, starting by 2023, to report on
their emissions and progress made on their NDCs; undergo international
review of collective progress; and submit new, more ambitious NDCs
every five years. The Paris Agreement extends the existing goal for
climate finance to a minimum of $100 billion after 2025.
More stringent national and regional measures can be expected in the
future. These measures could increase BP’s production costs for certain
products, increase demand for competing energy alternatives or products
with lower-carbon intensity, and affect the sales and specifications of
many of BP’s products. Current and announced measures and
developments potentially affecting BP’s businesses include the
following:
• The EU has agreed to an overall GHG reduction target of 20% by 2020.
To meet this, a ‘Climate and Energy Package’ of regulatory measures
was adopted that includes: a collective national reduction target for
emissions not covered by the EU ETS; binding national renewable
energy targets to double usage of renewable energy sources in the EU
including at least a 10% share of renewable energy in the transport
sector; a legal framework to promote carbon capture and storage
(CCS); and a revised EU ETS Phase 3. EU ETS revisions included a
GHG reduction of 21% from 2005 levels; a significant increase in
allowance auctioning; an expansion in the scope of the EU ETS to
encompass more industrial sectors (including the petrochemicals
sector) and gases; no free allocation for electricity generation (including
that which is self-generated off-shore) or production, but benchmarked
free allocation for energy-intensive and trade-exposed industrial
sectors. EU ETS revisions also included the adoption of a Market
Stability Reserve to reduce the supply of auctioned allowances. This
will take effect in 2019 and could potentially lead to higher carbon
costs. EU Energy efficiency policy is currently implemented via national
energy efficiency action plans and the Energy Efficiency Directive
adopted in 2012. The EU has also agreed to the 2030 Climate and
Energy Policy framework with a goal of at least a 40% reduction in
GHGs from 1990 and measures to achieve a 27% share of renewable
energy and a 27% increase in energy efficiency. The GHG reduction
target is to be achieved by a 43% reduction of emissions from sectors
covered by the EU ETS, and a 30% GHG reduction by Member States
for all other GHG emissions.
• Canada’s highest emitting province, Alberta, has regulations targeting
large final emitters (sites with over 100,000 tonnes of carbon dioxide
equivalent per annum) with intensity targets of 2% improvement per
year up to 20%. Compliance is possible via direct reductions, the
purchase of offsets or the payment of C$20/tonne to a technology fund
which will escalate to $30/tonne in 2017. A new policy direction has
just been announced for post-2018 where performance relative to a
best in sector benchmark (to be determined) will now determine the
volume of emissions subject to a cost ($30/tonne escalating in real
terms) or use of other compliance mechanisms such as offsets.
• In the US, the EPA continues to pursue regulatory measures to
address GHGs under the CAA.
– EPA regulations impose light, medium and heavy duty vehicle
emissions standards for GHGs and permitting requirements for
certain large GHG stationary emission sources. The EPA and the
National Highway Traffic Safety Administration are considering a
proposed rulemaking to extend and tighten GHG emission and
fuel efficiency standards until 2027. This will have an impact on
BP’s product mix and overall demand.
– Under the GHG mandatory reporting rule (GHGMRR), annual
reports on GHG emissions must be filed. In addition to direct
emissions from affected facilities, producers and importers/
exporters of petroleum products, certain natural gas liquids and
GHGs are required to report product volumes and notional GHG
emissions as if these products were fully combusted.
– The EPA proposed regulations establishing GHG emission limits
for new and modified power plants in September 2013. In June
2014, the EPA proposed a ‘Clean Energy Plan’ Regulation that
establishes GHG reduction requirements, at a state or regional
level, for existing power plants. The new and modified power
plant rule was finalized in August 2015 while the existing power
plant rule was finalized in October 2015. Legal challenges to both
rules have been filed by a number of US States; utility, coal, and
mining companies; and the US Chamber of Commerce. These
rules are important due to potential impacts on electricity prices,
reliability of electricity supply, precedents for similar rules
targeting other sectors and potential impacts on combined heat
and power installations.
In January 2015, the US government announced plans to reduce
methane emissions from the oil and gas sector by 40-45% from
2012 levels by 2025. In September 2015, the EPA proposed rules
aimed at limiting methane emissions from the oil and natural gas
sector in the US with plans to finalize these rules in early 2016. In
January 2016, the BLM released proposed rules aimed at limiting
methane emissions on federal lands from new, modified and
existing sources in the oil and gas sector. If implemented as
proposed, these EPA and BLM rules will require further actions by
our US upstream businesses to manage methane emissions.
–
• A number of additional state and regional initiatives in the US will affect
our operations. California implemented a low-carbon fuel standard in
2010. The California cap and trade programme started in January 2012
with the first auctions of carbon allowances held in November 2012
and obligations commencing from 2013. The California cap and trade
programme was broadened to include transport fuels on 1 January
2015.
• In the November 2014 US-China joint announcement on climate
change addressing post-2020 actions, which was reaffirmed by the
countries’ respective presidents in 2015, the US committed to
reducing its GHG emissions by 26-28% below its 2005 level by 2025.
Achieving these reductions will require expanded efforts to reduce
emissions, which likely will include regulatory measures. China
announced it intends to achieve a peak in CO2 emissions around 2030,
with the intention to try to peak earlier and to increase the non-fossil
fuel share of all energy to around 20% by 2030. Currently, China has
targets to reduce carbon intensity of GDP 40-45% below 2005 levels
by 2020 and increase the share of non-fossil fuels in total energy
consumption from 7.5% in 2005 to 15% by 2020.
• China is operating emission trading pilot programmes in five cities and
two provinces. A number of BP joint venture* companies in China are
participating in these schemes. A nationwide carbon emissions trading
market is expected to be launched in 2017 following the above seven
pilot programmes.
• 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.
• South Africa has delayed implementation of a carbon tax on carbon
intensive emitters until 2017.
For information on the steps that BP is taking in relation to climate
change issues and for details of BP’s GHG reporting see Environment
and society on page 46.
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 (Macondo), where
the semi-submersible rig Deepwater Horizon was deployed at the time of
the 20 April 2010 explosions and fire and resulting oil spill (the Incident).
The other working interest owners at the time of the Incident were
Anadarko Petroleum Company (Anadarko) and MOEX Offshore 2007
LLC, claims against whom were settled by BP in 2011. The Deepwater
Horizon, which was owned and operated by certain affiliates of
Transocean Ltd. (Transocean), sank on 22 April 2010. Lawsuits and
claims arising from the Incident have generally been brought in US
federal and state courts. The lawsuits have asserted, among others,
claims under the Oil Pollution Act of 1990 (OPA 90), claims for personal
injury in connection with the Incident itself and the response to it,
wrongful death, commercial and economic injury, breach of contract and
violations of statutes. The plaintiffs include individuals, corporations,
insurers and governmental entities and many of the lawsuits purport to
be class actions.
Many of the lawsuits in federal court were consolidated by the Federal
Judicial Panel on Multidistrict Litigation into two multi-district litigation
proceedings, one in federal district court in Houston for the securities,
derivative and Employee Retirement Income Security Act (ERISA) cases
(MDL 2185) and another in federal district court in New Orleans for the
remaining cases (MDL 2179). A Plaintiffs’ Steering Committee (PSC) was
established to act on behalf of individual and business plaintiffs in MDL
2179. These proceedings, and other material ongoing lawsuits and claims
arising from the Incident are discussed below.
Federal and state claims
MDL 2179 – Department of Justice (DoJ) Action and Trial of Liability,
Limitation, Exoneration and Fault Allocation
The US filed a civil complaint in MDL 2179 against BPXP and others on
15 December 2010 (the DoJ Action). The complaint sought an order
finding liability under OPA 90 for natural resources damages and civil
penalties under the Clean Water Act (CWA). To address certain issues
asserted in or relevant to the claims, counterclaims, cross-claims, third-
party claims, and comparative fault defences raised in the DoJ Action, a
Trial of Liability, Limitation, Exoneration and Fault Allocation (the Trial) in
MDL 2179 commenced on 25 February 2013.
The district court issued its ruling on the first phase of the Trial in
September 2014. BPXP, BP America Production Company (BPAPC) and
various other parties were each found liable under general maritime law
for the blowout, explosion and oil spill from the Macondo well. With
respect to the United States’ claim against BPXP under the CWA, the
district court found that the discharge of oil was the result of BPXP’s
gross negligence and wilful misconduct and that BPXP was therefore
subject to enhanced civil penalties.
The district court issued its ruling on the second phase of the Trial in
January 2015. It found that 3.19 million barrels of oil were discharged into
the Gulf of Mexico and were therefore subject to a CWA penalty. In
addition, the district court found that BP was not grossly negligent in its
source control efforts. For further details of the Trial, see ‘Legal
proceedings’ in BP Annual Report and Form 20-F 2014.
BP appealed both rulings.
The penalty phase of the Trial involved consideration of the amount of
CWA civil penalties owed to the United States, and concluded in
February 2015. Briefing concluded on the post-trial briefing schedule for
the penalty phase on 24 April 2015.
State and local authority claims consolidated into MDL 2179
On 12 August 2010, the State of Alabama filed a lawsuit seeking
damages for alleged economic and environmental harms, including
natural resource damages, civil penalties under state law, declaratory and
injunctive relief, and punitive damages as a result of the Incident.
On 3 March 2011, the State of Louisiana filed a lawsuit to declare various
BP entities (as well as other entities) liable for removal costs and
* Defined on page 256.
BP Annual Report and Form 20-F 2015
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damages, including natural resource damages under federal and state
law, to recover civil penalties, attorney’s fees and response costs under
state law, and to recover for alleged negligence, nuisance, trespass,
fraudulent concealment and negligent misrepresentation of material facts
regarding safety procedures and BP’s (and other defendants’) ability to
manage the oil spill, unjust enrichment from economic and other
damages to the State of Louisiana and its citizens, and punitive damages.
In addition, the Louisiana Department of Environmental Quality issued an
administrative order seeking environmental civil penalties and other relief
under state law.
The principal payments are as follows:
• BPXP is to pay the United States a civil penalty of $5.5 billion under the
CWA – payable over 15 years.
• BPXP will pay $7.1 billion to the United States and the five Gulf states
over 15 years for natural resource damages (NRD). This is in addition to
the $1 billion already committed for early restoration. BPXP will also
set aside an additional amount (up to $700 million) consisting of
$232 million and the NRD interest payment (see below) partly to cover
any further natural resource damages that are unknown at the time of
the agreement.
On 10 December 2010, the Mississippi Department of Environmental
Quality issued a Complaint and Notice of Violation alleging violations of
several state environmental statutes.
• A total of $4.9 billion will be paid over 18 years to settle economic and
other claims made by the five Gulf Coast states.
• Up to $1 billion to resolve claims made by more than 400 local
In April 2013, the states of Alabama, Florida and Mississippi each filed
actions against BP related to the Incident, including general maritime law
claims of negligence, gross negligence, and wilful misconduct; claims
under OPA 90 seeking damages for removal costs, natural resource
damages, property damage, lost tax and other revenue and damages for
providing increased public services during or after removal activities; and
various state law claims.
On 17 May 2013, the State of Texas filed suit against BP and others in
federal court in Texas. Its complaint asserted claims under OPA 90 for
natural resource damages, lost sales tax and state park revenue; claims
for natural resource damages under the Comprehensive Environmental
Response, Compensation, and Liability Act; and claims for natural
resource damages, cost recovery, civil penalties and economic damages
under state environmental statutes.
Each of these actions filed by the Gulf Coast states was consolidated
with MDL 2179.
On 28 August 2015, the district court in MDL 2179 issued an order
dismissing the local government entity master complaint in view of the
fact that the vast majority of local government entity plaintiffs who had
preserved their claims had released their claims as part of the local
government entity settlement with BPXP (as described below under
‘Consent Decree and Settlement Agreement’). With respect to claims by
local government entities that have not released their claims, the court
held that they are time-barred except to the extent that those local
government entities previously made timely presentment of their claims
under OPA 90 and previously filed either a complaint or a valid short-form
joinder in the MDL 2179 master complaint for local government entities.
Consent Decree and Settlement Agreement
On 2 July 2015, BP announced that BPXP had executed agreements in
principle with the United States federal government and five Gulf Coast
states to settle all federal and state claims arising from the Incident. In
addition to settling claims with the states of Alabama, Florida, Louisiana,
Mississippi and Texas, BPXP also settled the claims made by more than
400 local government entities.
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 and BP 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 CWA 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. The United States is expected to file a motion
with the court to enter the Consent Decree as a final settlement around
the end of March, which the court will then consider. The time period for
public comments on the Consent Decree ended on 4 December 2015.
The proposed Consent Decree and the Settlement Agreement are
conditional upon each other and neither will become effective unless
there is final court approval of the Consent Decree. A further condition of
the agreements in principle was that local government entities execute
releases to BP’s satisfaction. BP advised the court that it was satisfied
with and has accepted releases received from the vast majority of local
entities. Accordingly, on 27 July 2015, the district court ordered BP to
commence processing payments required under the releases and BP
made such payments in accordance with the court’s order.
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government entities.
BPXP has also agreed to pay $350 million to cover outstanding NRD
assessment costs and $250 million to cover the full settlement of
outstanding response costs, claims related to the False Claims Act and
royalties owed for the Macondo well. These additional payments will be
paid over nine years, beginning in 2015.
NRD and CWA payments are scheduled to start 12 months after the
Consent Decree and the Settlement Agreement become effective. The
2016 payments in respect of the state claims are due within 90 days of
the Settlement Agreement becoming effective. Total payments for NRD,
CWA and state claims will be made at a rate of around $1.1 billion a year
for the majority of the payment period.
Interest will accrue at a fixed rate on the unpaid balance of the CWA and
NRD payments, compounded annually and payable in year 16. To address
possible natural resource damages unknown at the time of the
settlement, beginning 10 years after the Consent Decree and the
Settlement Agreement become effective, the federal government and
the five Gulf states may request accelerated payment of accrued but
unpaid interest on the NRD payments.
Parent company guarantees for these payments will be provided by BP
Corporation North America Inc. as the primary guarantor and BP p.l.c. as
the secondary guarantor.
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.
The proposed Consent Decree and Settlement Agreement do not cover
the remaining costs of the 2012 class action settlements with the PSC
for economic and property damage and medical claims. They also do not
cover claims by individuals and businesses that opted out of the 2012
PSC settlements and/or whose claims were excluded from them,
including claims for recovery of losses allegedly resulting from the 2010
federal deepwater drilling moratoria and/or the related permitting
processes. The proposed Consent Decree and Settlement Agreement
also do not resolve private securities litigation pending in MDL 2185.
Each of these outstanding proceedings and claims is discussed further
below.
On 5 October 2015, on the joint motion of BP and the five Gulf states,
the district court dismissed the five Gulf states’ claims (with the
exception of claims for NRD and CWA penalties being addressed by the
proposed Consent Decree) against BP. The dismissal is without prejudice
pending the court’s entry of the Consent Decree, which is required for
the Settlement Agreement with the Gulf states to become effective, at
which time the dismissal would be converted into a dismissal with
prejudice.
OPA 90 Test Case Proceedings
A number of lawsuits have been brought, primarily from business
claimants, under OPA 90 in relation to the 2010 federal deepwater drilling
moratoria. Following the dismissal of one test case in January 2016, six
test cases, consolidated with MDL 2179, will address certain OPA 90
liability questions focusing on, among other issues, whether plaintiffs’
alleged losses tied to the moratoria and whether federal permit delays
are compensable. In December 2015, BP filed a motion to dismiss
plaintiffs’ claims arising from the moratoria or permit process, and
plaintiffs filed a motion asking the court to prevent BP from arguing that
government action and/or inaction following the oil spill is a ‘superseding’
cause with respect to some or all of the damages that plaintiffs claim.
The motions are fully briefed, but the court has not yet issued a ruling.
Halliburton and Transocean settlements.
On 20 May 2015, BP and Transocean, and BP and Halliburton Energy
Services Inc. (Halliburton), entered into confidential settlement
agreements to resolve the final remaining disputes between these
parties stemming from the Incident.
Under the agreement with Transocean, BPXP and BPAPC agreed to
indemnify Transocean for compensatory damages (including natural
resource damages), to pay Transocean $125 million in compensation for
incurred legal fees, and discontinue attempts to recover as an additional
insured under Transocean’s liability policies. Transocean agreed to
indemnify BPXP and BPAPC for the personal and bodily injury claims of
Transocean employees, as well as for claims relating to any future
cleanup or removal of diesel or other pollutants stored on the Deepwater
Horizon. BPXP, BPAPC, and Transocean will mutually release all claims
between the companies.
BPXP’s agreement with Halliburton resolves the remaining claims
between the two companies and includes indemnities and the dismissal
of all claims against each other.
Agreement for early natural resource restoration
On 21 April 2011, BP announced an agreement with natural resource
trustees for the US and five Gulf Coast states, providing for up to
$1 billion to be spent on early restoration projects to address natural
resource injuries resulting from the Incident. To date, BP and the trustees
have reached agreement on a total of 65 early restoration projects that
are expected to cost approximately $877 million. The remaining unpaid
balance of the $1 billion will be paid within 30 days after court approval of
the proposed Consent Decree.
Under the proposed Consent Decree, Trustees would continue to
implement these early restoration projects as part of the final settlement
of all US and state claims for natural resource damages.
PSC settlements
PSC settlements – Economic and Property Damages Settlement
Agreement
The Economic and Property Damages Settlement resolves certain
economic and property damage claims, and includes a $2.3 billion BP
commitment to help resolve economic loss claims related to the Gulf
seafood industry (which we refer to as the Seafood Compensation Fund)
and a $57-million fund to support advertising to promote Gulf Coast
tourism. It also resolves property damage in certain areas along the Gulf
Coast, as well as claims for additional payments under certain Master
Vessel Charter Agreements entered into in the course of the Vessels of
Opportunity Program implemented as part of the response to the
Incident. The Economic and Property Damages Settlement does not
cover claims by individuals and businesses that opted out of the 2012
PSC settlements and/or whose claims were excluded from them,
including claims for recovery of losses allegedly resulting from the 2010
federal deepwater drilling moratoria and/or the related permitting
processes. The Economic and Property Damages Settlement also does
not resolve private securities litigation pending in MDL 2185.
The economic and property damages claims process is under court
supervision through the settlement claims process established by the
Economic and Property Damages Settlement. This provides that class
members release and dismiss their claims against BP not expressly
reserved by that agreement. The Economic and Property Damages
Settlement also provided that, to the extent permitted by law, BP
assigned to the PSC certain of its claims, rights and recoveries against
Transocean and Halliburton for damages with protections such that
Transocean and Halliburton cannot pass those damages through to BP.
The claims facility operating under the framework established by the
Economic and Property Damages Settlement commenced operation in
June 2012. Following numerous court decisions on 31 March 2015, the
court denied the PSC’s motion seeking to alter or amend a revised policy,
addressing the matching of revenue and expenses for business
economic loss claims, which requires the matching of revenue with the
expenses incurred by claimants to generate that revenue, even where
the revenue and expenses were recorded at different times. On 23 April
2015, the PSC appealed this decision to the Fifth Circuit. On
18 December 2015, the PSC and BP entered into a joint stipulation to
stay this appeal pending resolution of certain issues in the district court in
New Orleans. On 8 January 2016, the Fifth Circuit granted the joint
stipulation and stayed the appeal for 120 days.
The effective date of the Economic and Property Damages Settlement
Agreement was 8 December 2014, and the final deadline for filing all
claims other than those that fall into the Seafood Compensation Program
was 8 June 2015.
On 8 May 2015, the Fifth Circuit upheld three awards to non-profit
entities under the Economic and Property Damages Settlement, each of
which was premised on an official policy that typically treated grant
monies and contributions to non-profit entities as revenue for purposes of
the settlement’s calculations. BP argued that this policy was inconsistent
with the language of the settlement agreement and would place the
agreement in violation of United States law, but the Fifth Circuit upheld
the policy and determined that the district court did not otherwise abuse
its discretion in denying review of the three awards. The court also held
that requests for discretionary review of settlement claims by BP or
individual claimants under the Economic and Property Damages
Settlement can be appealed by BP or individual claimants to the Fifth
Circuit.
For more information about BP’s current estimate of the total cost of the
Economic and Property Damages Settlement, see Financial statements –
Note 2.
PSC settlements – Medical Benefits Class Action Settlement
The Medical Benefits Class Action Settlement (Medical Settlement)
resolves certain medical claims by response workers and Gulf Coast
residents. Under the Medical Settlement, class members release and
dismiss their claims against BP covered by that settlement, except that
class members do not release certain claims for later-manifested physical
conditions (LMPCs).
The Medical Settlement 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. The Medical Settlement also provides that
class members claiming LMPCs may pursue their claims through a
mediation/litigation process, but waive, among other things, the right to
seek punitive damages. Consistent with its commitment to the Gulf, BP
has also agreed to provide $105 million to the Gulf Region Health
Outreach Program to improve the availability, scope and quality of
healthcare in certain Gulf Coast communities. This healthcare outreach
programme will be available to, and is intended to benefit, class
members and other individuals in those communities. BP has already
funded $93.7 million for projects sponsored by this programme.
The district court approved the Medical Settlement in a final order and
judgment on 11 January 2013. The effective date was 12 February 2014
and the deadline for submitting claims was 12 February 2015. The total
number of claims estimated by the Medical Claims Administrator is
approximately 37,200. At year end, approximately 7,600 SPC claims,
totalling approximately $17 million, have been approved for
compensation. In addition, approximately 22,000 claimants have been
determined eligible for the PMCP.
MDL 2185 and other securities-related litigation
Since the Incident, shareholders have sued BP and various of its current
and former officers and directors asserting shareholder derivative claims
and class and individual securities fraud claims. Many of these lawsuits
have been consolidated or co-ordinated in federal district court in
Houston (MDL 2185).
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Securities class action
On 20 May 2014, the court denied plaintiffs’ motion to certify a proposed
class of ADS purchasers before the Deepwater Horizon explosion (from
8 November 2007 to 20 April 2010) and granted plaintiffs’ motions to
certify a class of post-explosion ADS purchasers from 26 April 2010 to
28 May 2010 and to amend their complaint to add one additional alleged
misstatement. The parties appealed the district court’s class certification
decisions and on 8 September 2015, the Fifth Circuit affirmed both of the
district court’s decisions. On 26 October 2015, the Fifth Circuit denied
the pre-explosion ADS purchasers’ motion for rehearing en banc. On
25 January 2016, the pre-explosion ADS purchasers filed in the Supreme
Court a petition for a writ of certiorari seeking review of the Fifth Circuit’s
decision. The trial of the securities fraud claims of the class of post
explosion ADS purchasers has been scheduled to commence on 5 July
2016.
Individual securities litigation
From April 2012 to September 2015, 37 cases were filed in state and
federal courts by pension funds and investment funds and advisers
against BP entities and several current and former officers and directors
seeking damages for alleged losses those funds suffered because of
their purchases of BP ordinary shares and, in two cases, ADSs. The funds
assert claims under English law and, for plaintiffs purchasing ADSs,
federal securities law, and seek damages for alleged losses that those
funds suffered because of their purchases of BP ordinary shares and/or
ADSs. All the cases, with the exception of one case that has been
stayed, have been transferred to MDL 2185. In August and September
2015, plaintiffs filed or sought leave to file amended complaints in those
cases. On 4 January 2016, the district court dismissed two of those
cases and some of the claims of a third case with leave to replead by
19 January 2016. Plaintiffs in the two dismissed cases filed amended
complaints on 19 January 2016.
Canadian class action
On 15 November 2012, a plaintiff re-filed a statement of claim against BP
in Ontario, Canada, 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. On
14 August 2014, the Ontario Court of Appeal held that the claims made
on behalf of Canadian residents who purchased BP ordinary shares and
ADSs on exchanges outside of Canada should be litigated in those
countries, and granted leave for the plaintiff to amend the complaint to
assert claims only on behalf of Canadian residents who purchased ADSs
on the Toronto Stock Exchange. On 26 March 2015, the Supreme Court
of Canada dismissed the plaintiff’s appeal of this decision. Plaintiff has
not amended his complaint to assert claims on behalf of Canadian
residents who purchased ADSs on the Toronto Stock Exchange, and thus
there have been no further proceedings in the case. On 27 March 2015,
the plaintiff filed a complaint in Texas federal court asserting claims under
Canadian law against BP on behalf of a class of Canadian residents who
allegedly suffered losses because of their purchase of BP ADSs on the
New York Stock Exchange. That action was transferred to MDL 2185 and
was dismissed by the district court on 25 September 2015. The time to
appeal that dismissal has expired.
Dividend-related proceedings
On 11 May 2015, the Fifth Circuit affirmed a district court decision in
June 2014 dismissing an action against BP p.l.c. for cancelling its
dividend payments in June 2010 on the grounds that the courts of
England were the more appropriate forum for the litigation. This followed
earlier unsuccessful lawsuits against BP p.l.c. for the 2010 dividend
payment cancellation.
ERISA
On 15 January 2015, following an earlier dismissal in the ERISA case
related to BP share funds in several employee benefit savings plans, the
district court allowed the plaintiffs’ to amend their complaint to allege
some of their proposed claims against certain defendants. The district
court certified that decision for appeal, and the Fifth Circuit accepted that
appeal on 20 May 2015. Plaintiffs filed an amended complaint on
12 February 2015. On 30 October 2015, the district court granted
defendants’ partial motion to dismiss, dismissing some of the claims in
the amended complaint.
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Other Deepwater Horizon oil spill related claims
Other civil complaints
On 26 August 2011, the district court in MDL 2179 granted in part BP’s
motion to dismiss a master complaint raising claims for economic loss by
private plaintiffs, dismissing the plaintiffs’ state law claims and limiting
the types of maritime law claims the plaintiffs may pursue, but also held
that certain classes of claimants may seek punitive damages under
general maritime law. On 30 September 2011, the court granted in part
BP’s motion to dismiss a master complaint asserting personal injury
claims on behalf of persons exposed to crude oil or chemical dispersants,
including state law claims, claims for punitive damages and claims for
medical monitoring damages. In each case the court did not, however, lift
an earlier stay on the underlying individual complaints raising those
claims or otherwise apply its dismissal of the master complaints to those
individual complaints.
On 4 September 2015, the district court in MDL 2179 issued an order
directing the clerk to docket no further joinders by plaintiffs in the two
master complaints for private plaintiff economic and property damages
claims and for medical claims.
On 14 September 2015, the district court granted BP’s motion for
summary judgment and issued a judgment dismissing with prejudice the
Center for Biological Diversity’s claim against BP under the Emergency
Planning and Community Right to Know Act. This followed an earlier
unsuccessful appeal against the dismissal of the other action brought
against BP by the Center for Biological Diversity. On 8 October 2015, the
Center for Biological Diversity filed a motion asking the district court to
reconsider its 14 September 2015 order. That motion was denied on
4 December 2015.
Non-US government lawsuits
On 1 May 2015, the Fifth Circuit affirmed the district court’s dismissal
with prejudice of the claims brought in September 2010 by three
Mexican states bordering the Gulf of Mexico (Veracruz, Quintana Roo
and Tamaulipas) against several BP entities. The lawsuits allege that the
Incident harmed their tourism, fishing and commercial shipping industries
(resulting in, among other things, diminished tax revenue), damaged
natural resources and the environment and caused the states to incur
expenses in preparing a response to the Incident. On 30 July 2015, the
three Mexican states filed a petition for certiorari to the US Supreme
Court, which was denied on 30 November 2015.
On 5 April 2011, the Mexican State of Yucatan submitted a claim to the
Gulf Coast Claims Facility (GCCF) alleging potential damage to its natural
resources and environment, and seeking to recover the cost of assessing
the alleged damage. This was followed by a suit against BP which was
transferred to MDL 2179.
On 19 April 2013, the Mexican federal government filed a civil action
against BP and others in MDL 2179. The complaint seeks a
determination that each defendant bears liability under OPA 90 for
damages that include the costs of responding to the spill; natural
resource damages allegedly recoverable by Mexico as an OPA 90
trustee; and the net loss of taxes, royalties, fees or net profits.
On 18 October 2012, before a Mexican Federal District Court located in
Mexico City, a class action complaint was filed against BPXP, BPAPC,
and other BP subsidiaries. The plaintiffs, consisting of fishermen and
other groups, are seeking, among other things, compensatory damages
for the class members who allegedly suffered economic losses, as well
as an order requiring BP to remediate environmental damage resulting
from the Incident, to provide funding for the preservation of the
environment and to conduct environmental impact studies in the Gulf of
Mexico for the next 10 years. After initial dismissal of the action, it was
reported in December 2015 that the action was reinstated after appeal,
although BP has not been formally served with the action.
False Claims Act actions
On 17 December 2012, the court ordered unsealed one complaint that
had been filed in the US District Court for the Eastern District of
Louisiana by an individual under the Qui Tam (whistle-blower) provisions
of the False Claims Act (FCA). The complaint alleged that BP and another
defendant had made false reports and certifications of the amount of oil
released into the Gulf of Mexico following the Incident. On 17 December
2012, the DoJ filed with the court a notice that the DoJ elected to decline
to intervene in the action. On 31 January 2013, the complaint was
transferred to MDL 2179. Under the terms of the proposed Consent
Decree, the United States and Gulf states would covenant not to pursue
claims against BP under the FCA.
Criminal settlement with the DoJ and settlement with the SEC
On 15 November 2012, BP announced that it reached agreement with
the US government, subject to court approval, to resolve all federal
criminal charges and all claims by the SEC against BP arising from the
Deepwater Horizon accident, oil spill and response.
On 29 January 2013, the US District Court for the Eastern District of
Louisiana accepted BP’s pleas regarding the federal criminal charges, and
sentenced BP in connection with the criminal plea agreement. Pursuant
to that sentence, BP is required to pay $4 billion, including $1,256 million
in criminal fines, in instalments over five years. Under the terms of the
criminal plea agreement, a total of $2,394 million is required to be paid to
the National Fish & Wildlife Foundation (NFWF) over five years. In
addition, $350 million is required to be paid to the National Academy of
Sciences (NAS) over five years. BP made its required payments that
were due in March and April 2013, January 2014, January 2015 and
January 2016 totalling $2.1 billion. BP was required to serve a term of
five years’ probation and agree to certain equitable relief relating to BP’s
risk management processes in order to further enhance the safety of
drilling operations in the Gulf of Mexico. BP also agreed to maintain a
real-time drilling operations monitoring centre and to undertake several
initiatives with academia and regulators to develop new technologies
related to deepwater drilling safety. The resolution also provided for the
appointment of two monitors, a process safety monitor, to review and
provide recommendations concerning BPXP’s process safety and risk
management procedures for deepwater drilling in the Gulf of Mexico and
an ethics monitor, to review and provide recommendations concerning
BP’s ethics and compliance programme. BP has also agreed to retain an
independent third-party auditor to review and report to the probation
officer, the DoJ and BP regarding BPXP’s compliance with the key terms
of the plea agreement. Under the plea agreement, BP has also agreed to
co-operate in ongoing criminal actions and investigations, including
prosecutions of four former employees who have been separately
charged.
In its resolution with the SEC, BP has resolved the SEC’s Deepwater
Horizon-related claims against the company under Sections 10(b) and
13(a) of the Securities Exchange Act of 1934 and the associated rules. BP
agreed to a civil penalty of $525 million, the last instalment of which was
paid in August 2014, and consented to the entry of an injunction
prohibiting it from violating certain US securities laws and regulations.
US Environmental Protection Agency matters
On 13 March 2014, BP, BPXP, and all other temporarily suspended BP
entities entered into an administrative agreement with the US
Environmental Protection Agency (EPA) resolving all issues related to
suspension or debarment arising from the Incident. Under the terms and
conditions of the administrative agreement, which will apply until
13 March 2019, BP may enter into new contracts or leases with the US
government but must comply with a set of safety and operations, ethics
and compliance and corporate governance requirements.
US Department of Interior matters
On 12 October 2011, the US Department of the Interior Bureau of Safety
and Environmental Enforcement issued to BP, Transocean, and
Halliburton Notification of Incidents of Noncompliance (INCs). The
notification issued to BP is for a number of alleged regulatory violations
concerning Macondo well operations. On 7 December 2011, the Bureau
of Safety and Environmental Enforcement issued to BP a second INC for
five alleged violations related to drilling and abandonment operations at
the Macondo well. BP filed an administrative appeal with respect to the
first and second INCs and filed a joint stay of proceedings with the
Department of Interior with respect to both INCs. Pursuant to the
proposed Consent Decree with the United States (see above), if entered
by the court, BP would withdraw its appeals within 15 days of the
effective date of the Consent Decree, and the INCs would then be fully
and finally resolved.
Pending investigations and reports relating to the Deepwater
Horizon oil spill CSB investigation
The US Chemical Safety and Hazard Investigation Board (CSB) has
indicated that it plans to release the final two volumes of its four-volume
report on its investigation into the Incident (concerning the role of the
regulator in the oversight of the offshore industry and organizational and
cultural factors) in March 2016.
Other legal proceedings
FERC and CFTC matters
The US Federal Energy Regulatory Commission (FERC) and the US
Commodity Futures Trading Commission (CFTC) have been investigating
several BP entities regarding trading in the next-day natural gas market at
Houston Ship Channel in 2008. On 5 August 2013, the FERC issued an
Order to Show Cause and Notice of Proposed Penalty directing BP to
respond to a FERC Enforcement Staff report alleging that BP manipulated
the next-day, fixed price gas market at Houston Ship Channel from mid-
September 2008 to 30 November 2008. The FERC Enforcement Staff
report proposed a civil penalty of $28 million and the surrender of
$800,000 of alleged profits. The Administrative Law Judge 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. BP filed an appeal to
the initial decision with the FERC on 14 September 2015 and the Office
of Enforcement filed an opposing brief on 5 October 2015.
Canadian Pipeline Nominations
The CFTC is currently investigating certain practices relating to crude oil
pipeline nominations procedures on Canadian pipelines. On 17 November
2014, the CFTC Enforcement Staff notified BP that it intends to
recommend an enforcement action naming certain parties, including
several BP entities, alleging violations of the anti-fraud and false reporting
provisions of the Commodity Exchange Act in connection with these
nomination procedures and related trades. On 17 December 2014 BP
submitted a detailed defence responding to the allegations in the notice
and challenging the CFTC’s jurisdiction over the alleged conduct.
Investigations by the FERC and CFTC into BP’s trading activities continue
to be conducted from time to time.
CSB matters
In March 2007, the CSB issued a report on the March 2005 explosion and
fire at the Texas City refinery incident. The report contained
recommendations to the BP Texas City refinery and to the board of
directors of BP. To date, the CSB has accepted that all but one of BP’s
responses to its recommendations have been satisfactorily addressed.
BP and the CSB are continuing to discuss the remaining open
recommendation with the objective of the CSB agreeing to accept this as
satisfactorily addressed as well.
OSHA matters
On 4 March 2014, BP and the US Occupational Safety and Health
Administration (OSHA) reached agreement in relation to the remaining
30 citations issued by OSHA to the Texas City refinery in 2009 related to
the Process Safety Management (PSM) standard. This followed an earlier
settlement of approximately 400 Texas City citations. The agreement
links the outcome of these citations to the ultimate outcome of certain
specified Toledo citations which address similar issues (see below). If the
31 July 2013 decision of the Administrative Law Judge in relation to the
similar Toledo issues is ultimately upheld when a final decision is
entered, OSHA has agreed to dismiss the remaining Texas City citations.
If the 31 July 2013 decision is ultimately overturned, BP has agreed to
pay a penalty not exceeding $1 million to resolve the remaining Texas
City citations.
On 8 March 2010, OSHA issued 65 citations to BP Products North
America Inc. (BP Products) and BP- Husky Refining LLC (BP-Husky) for
alleged violations of the PSM standard at the Toledo refinery, with
penalties of approximately $3 million. These citations resulted from an
inspection conducted pursuant to OSHA’s Petroleum Refinery Process
Safety Management National Emphasis Program. Both BP Products and
BP-Husky contested the citations. The outcome of a pre-trial settlement
of a number of the citations and a trial of the remainder was a reduction
in the total penalty in respect of the citations from the original amount of
approximately $3 million to $80,000. The OSH Review Commission
BP Annual Report and Form 20-F 2015
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granted OSHA’s petition for review and briefing was completed in the
first half of 2014. The Review Commission is not expected to issue its
decision until later this year at the earliest.
Prudhoe Bay leak
In March and August 2006, oil leaked from oil transit pipelines operated
by BP Exploration (Alaska) Inc. (BPXA) at the Prudhoe Bay unit on the
North Slope of Alaska. On 12 May 2008, a BP p.l.c. shareholder filed a
consolidated complaint alleging violations of federal securities law on
behalf of a putative class of BP p.l.c. shareholders, based on alleged
misrepresentations concerning the integrity of the Prudhoe Bay pipeline
before its shutdown on 6 August 2006. On 7 December 2015, the
complaint was dismissed with prejudice. On 5 January 2016, plaintiffs
filed a notice of appeal of that decision to the Ninth Circuit 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.
Abbott Atlantis related matters
In April 2009, Kenneth Abbott, as relator, filed a US False Claims Act
lawsuit against BP, alleging that BP violated federal regulations, and
made false statements in connection with its compliance with those
regulations, by failing to have necessary documentation for the Atlantis
subsea and other systems. BP is the operator and 56% interest owner of
the Atlantis unit which is in production in the Gulf of Mexico. On
21 August 2014, the court granted BP’s motions for summary judgment.
On 28 August 2014, the court entered final judgment in favour of BP. In
September 2014 the plaintiff filed a motion for reconsideration, which BP
opposed. On 18 December 2015, the judge denied plaintiffs’ motion for
reconsideration. On 8 January 2016, plaintiffs filed a notice of appeal.
EC investigation and related matters
On 14 May 2013, European Commission officials made a series of
unannounced inspections at the offices of BP and other companies
involved in the oil industry acting on concerns that anticompetitive
practices may have occurred in connection with oil price reporting
practices and the reference price assessment process. Related inquiries
and requests for information were also received from US and other
regulators following the European Commission’s actions, including from
the Japanese Fair Trade Commission, the Korean Fair Trade Commission,
the Federal Trade Commission (FTC) and the CFTC. On 1 October 2014,
BP was informed by the FTC that it was closing its investigation. On
7 December 2015, the European Commission confirmed that it has
dropped BP from its investigation.
In addition, 15 purported class actions related to these matters have been
filed in US district courts alleging manipulation and antitrust violations
under the Commodity Exchange Act and US antitrust laws, and these
purported class actions have been consolidated in federal court in
New York.
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California False Claims Act matters
On 4 November 2014 the California Attorney General filed a notice in
California state court that it was intervening in a previously-sealed
California False Claims Act (CFCA) lawsuit filed by relator Christopher
Schroen against BP, BP Energy Company, BP Corporation North America
Inc., BP Products and BPAPC. On 7 January 2015, the California Attorney
General filed a complaint in intervention alleging that BP violated the
CFCA and the California Unfair Competition Law by falsely and
fraudulently overcharging California state entities for natural gas. The
relator’s complaint makes similar allegations, in addition to individual
claims. The complaints seek treble damages, punitive damages, penalties
and injunctive relief. On 9 April 2015, the BP defendants filed a demurrer,
motion to strike and motion to dismiss (forum non conveniens) to the
relator’s claims that were not adopted in the Attorney General’s
complaint, which was denied on 10 June 2015. BP filed additional
demurrers to the Attorney General’s and the relator’s complaints, which
were granted in part and denied in part on 14 August 2015. On
22 September 2015, BP filed its answer and affirmative defenses. Trial is
scheduled to commence on 10 July 2017.
Scharfstein v. BP West Coast Products, LLC
A purported class action lawsuit was filed against BP West Coast
Products, LLC in Oregon State Court under the Oregon Unlawful Trade
Practices Act on behalf of customers who used a debit card at ARCO
gasoline stations in Oregon during the period 1 January 2011 to
30 August 2013, alleging that ARCO’s Oregon sites failed to provide
sufficient notice of the 35 cents per transaction debit card fee. After a
jury trial and subsequent hearing, in 2014 the jury rendered a verdict
against BP and determined that statutory damages of $200 per class
member should be awarded. On 25 August 2015, the court determined
the size of the class to be slightly in excess of two million members. BP
intends to appeal. No provision has been made for damages arising out
of this class action.
See Financial statements – Note 32 for additional information on the
group’s legal proceedings.
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 and EU sanctions
and seeks to comply with applicable sanctions laws and regulations.
The US and the EU sanctions against Iran that were in place in 2015
included: in the US, sanctions against persons involved with Iran’s
energy, shipping and petrochemicals industries, and sanctions against
financial institutions that engage in significant transactions with the Iran
Central Bank; and in the EU, a prohibition on the import, purchase and
transport of Iranian-origin crude oil, petroleum products and natural gas.
Additionally, the Iran Threat Reduction and Syria Human Rights Act of
2012 (ITRA) added Section 13(r) to the Securities Exchange Act of 1934,
as amended (the Exchange Act), and requires that issuers must file
annual or quarterly reports under the Exchange Act to disclose in such
reports whether, during the period covered by the report, the registrant
or its affiliates have knowingly engaged in certain, principally Iran-related,
activities.
The US and the EU implemented temporary, limited and reversible relief
of certain sanctions related to Iran pursuant to a Joint Plan of Action
(JPOA) entered by Iran, China, France, Germany, Russia, the UK and the
US with effect from 20 January 2014 and in July 2015, these countries
agreed the Joint Comprehensive Plan of Action (JCPOA). Following the
JCPOA, BP representatives visited Iran, met Iranian government officials
and met other Iranian nationals. Such meetings were introductory in
nature with a view to considering possible future business opportunities.
Following confirmation by the International Atomic Energy Agency on
16 January 2016 (Implementation Day) that Iran had fully implemented
the JCPOA measures necessary for sanctions relief, the European Union
and the United States lifted certain nuclear related sanctions, with the EU
lifting nuclear related primary sanctions and the United States
suspending nuclear related secondary sanctions. BP will consider future
business opportunities in relation to Iran and engage in discussions with
Iranian government officials and other Iranian nationals, insofar as this is
in compliance with applicable sanctions.
BP has interests in and operates the North Sea Rhum field (Rhum) and
the Azerbaijan Shah Deniz field (Shah Deniz), in which Naftiran Intertrade
Co. Limited and NICO SPV Limited (collectively, NICO) or Iranian Oil
Company (U.K.) Limited (IOC UK) have interests. Additionally, BP has
interests in a gas marketing entity and a gas pipeline entity in which
NICO or IOC UK have interests, although both entities (and their related
assets) are located outside Iran. Production was suspended at Rhum (in
which IOC UK has a 50% interest) in November 2010. On 22 October
2013, the UK government announced a temporary management scheme
(the Temporary Scheme) under The Hydrocarbon (Temporary
Management Scheme) Regulations 2013, under which the UK
government assumed control of and managed IOC UK’s interest in the
Rhum field, thereby permitting Rhum operations to recommence in
accordance with applicable EU regulations and in compliance with a
licence from OFAC. Operations at the Rhum gas field recommenced in
mid-October 2014. Following Implementation Day, the Temporary
Management Scheme will cease and BP has applied for an amended
OFAC licence. In the meantime, operations have continued at Rhum.
Shah Deniz, its gas marketing entity and the gas pipeline entity (in which
NICO has a 10% or less non-operating interest) continue in operation.
The Shah Deniz joint operation* and its gas marketing and pipeline
entities were excluded from the main operative provisions of the EU
regulations as well as from the application of the US sanctions, and fall
within the exception for certain natural gas projects under Section 603
of ITRA.
BP has no current operating activities in Iran. BP holds an interest in a
non-BP operated Indian joint venture* which sold crude oil to an Indian
entity in which NICO holds a minority, non-controlling stake. Those sales
had ceased in January 2014 but resumed in 2015.
Both the US and the EU have enacted strong sanctions against Syria,
including a prohibition on the purchase of Syrian-origin crude and a US
prohibition on the provision of services to Syria by US persons. The EU
sanctions against Syria include a prohibition on supplying certain
equipment used in the production, refining, or liquefaction of petroleum
resources, as well as restrictions on dealing with the Central Bank of
Syria and numerous other Syrian financial institutions.
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 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 prior knowledge or consent. BP has registered
and paid required fees for patents and trade marks in Sanctioned
Countries.
BP sells lubricants in Cuba through a 50:50 joint arrangement and trades
in small quantities of lubricants.
During 2014 the US and the EU imposed sanctions on certain Russian
activities, individuals and entities, including Rosneft. Certain sectoral
sanctions also apply to entities owned 50% or more by entities on the
relevant sectoral sanctions list. Ruhr Oel GmbH (ROG) is a 50:50 joint
operation with Rosneft, operated by BP, which holds interests in a
number of refineries in Germany. To date, these sanctions have had no
material adverse impact on BP or ROG. On 15 January 2016 BP
announced that it had signed definitive agreements with Rosneft to
dissolve ROG.
Disclosure pursuant to Section 219 of ITRA
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 exception:
Rhum, located in the UK sector of the North Sea, is operated by
BP Exploration Operating Company Limited (BPEOC), a non-US
subsidiary of BP. Rhum is owned under a 50:50 unincorporated joint
arrangement between BPEOC and Iranian Oil Company (U.K.) Limited
(IOC). The Rhum joint arrangement was originally formed in 1974. During
the period of production from the field, the Rhum joint arrangement
supplied natural gas and certain associated liquids to the UK. On
16 November 2010, production from Rhum was suspended in response
to relevant EU sanctions. Operations at the Rhum gas field
recommenced in mid-October 2014 in accordance with the UK
government’s Temporary Scheme (see above). During the year ended
31 December 2015, BP recorded gross revenues of $104.5 million
related to its interests in Rhum. BP had a net profit of $88.7 million for
the year ended 31 December 2015, including an impairment reversal of
$67.6 million in the fourth quarter of 2015.
BP currently intends to continue to hold its ownership stake in the Rhum
joint arrangement and act as operator.
Material contracts
On 13 March 2014, BP, BP Exploration & Production Inc., and other BP
entities entered into an administrative agreement with the US
Environmental Protection Agency, which resolved all issues related to the
suspension or debarment of BP entities arising from the 20 April 2010
explosions and fire on the semi-submersible rig Deepwater Horizon and
resulting oil spill. The administrative agreement allows BP entities to
enter into new contracts or leases with the US government. Under the
terms and conditions of this agreement, which will apply for five years,
BP has agreed to a set of safety and operations, ethics and compliance
and corporate governance requirements. The agreement is governed by
federal law.
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) entered into a proposed Consent
Decree to fully and finally resolve 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. The
United States lodged the proposed Consent Decree with the district
court in MDL 2179 on 5 October 2015.
Concurrently, BP entered into a definitive Settlement Agreement with
the Gulf states (Settlement Agreement) with respect to State claims for
economic, property and other losses.
The proposed Consent Decree and the Settlement Agreement are
conditional upon each other and neither will become effective unless
there is final court approval of the Consent Decree. BP has filed the
proposed Consent Decree and the Settlement Agreement as exhibits to
its Annual Report on Form 20-F 2015 filed with the SEC. For further
details of the proposed Consent Decree and the Settlement Agreement,
see Legal proceedings on page 238.
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 2015 and the group percentage of ordinary share
capital see Financial statements – Note 36. For information on
significant joint ventures and associates* of the group see Financial
statements – Notes 15 and 16.
Related-party transactions
Transactions between the group and its significant joint ventures and
associates are summarized in Financial statements – Note 15 and
Note 16. In the ordinary course of its business, the group enters into
transactions with various organizations with which some of its directors
* Defined on page 256.
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or executive officers are associated. Except as described in this report,
the group did not have material transactions or transactions of an
unusual nature with, and did not make loans to, related parties in the
period commencing 1 January 2015 to 16 February 2016.
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.
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
BP has adopted a robust set of board governance principles, which
reflect the UK Corporate Governance Code and its principles-based
approach to corporate governance. As such, the way in which BP makes
determinations of directors’ independence differs from the NYSE rules.
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 chairman’s (rather than executive)
committee, nomination (rather than nominating/corporate governance)
committee and remuneration (rather than 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 68-75). BP has not, therefore, adopted
separate charters for each committee.
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, re-appointment or removal of the
independent auditors – instead, it follows the UK Companies Act 2006 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 possessed 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 68). 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
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Code of ethics
The company has adopted a code of ethics for its group chief executive,
chief financial officer, group controller, general auditor 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, if any, within the company have been
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 cost-benefit relationship of possible controls
and procedures. Also, we have investments in certain 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 2015 fiscal year, management conducted an
assessment of the effectiveness of internal control over financial
reporting in accordance with the UK Financial Reporting Council’s
Guidance on Risk Management, Internal Control and Related Financial
and Business Reporting. Based on this assessment, management has
determined that BP’s internal control over financial reporting as of
31 December 2015 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 2015 has been
audited by Ernst & Young, an independent registered public accounting
firm, as stated in their report appearing on page 101 of BP Annual Report
and Form 20-F 2015.
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 controls over financial reporting.
Principal accountants’ fees and services
The audit committee has established policies and procedures for the
engagement of the independent registered public accounting firm,
Ernst & Young LLP, to render audit and certain assurance and tax
services. The policies provide for pre-approval by the audit committee of
specifically defined audit, audit-related, tax and other services that are not
prohibited by regulatory or other professional requirements. Ernst &
Young are engaged for these services when its expertise and experience
of BP are important. Most of this work is of an audit nature. Tax services
were awarded either through a full competitive tender process or
following an assessment of the expertise of Ernst & Young relative to
that of other potential service providers. These services are for a fixed
term.
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); due diligence
in connection with acquisitions, disposals and joint arrangements*
(excluding valuation or involvement in prospective financial information);
income tax and indirect tax compliance and advisory services; employee
tax services (excluding tax services that could impair independence);
provision of, or access to, Ernst & Young publications, workshops,
seminars and other training materials; provision of reports from data
gathered on non-financial policies and information; 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,
including tax 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. 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 auditors each
year. The audit fees payable to Ernst & Young 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 auditors.
External regulation and BP policy requires the auditors to rotate their lead
audit partner every five years. (See Financial statements – Note 35 and
Audit committee report on page 68 for details of fees for services
provided by auditors.)
Directors’ report information
This section of BP Annual Report and Form 20-F 2015 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 2015. During the year, a review of the terms
and scope of the policy was undertaken. The policy was renewed during
2015 and continued into 2016. 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.
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 Our
management of risk on page 51-52, Liquidity and capital resources on
page 219 and Financial statements – Notes 28 and 29.
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 28.
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 of the business is
included in the Strategic report.
Research and development
An indication of the activities of the company in the field of research and
development is included in Our business model and strategy on
pages 12-17.
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
The disclosures concerning policies in relation to the employment of
disabled persons and employee involvement are included in Corporate
responsibility – Employees on pages 49-50.
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.
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. The proposed Consent Decree
* Defined on page 256.
BP Annual Report and Form 20-F 2015
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and the Settlement Agreement are conditional upon each other and
neither will become effective unless there is final court approval of the
Consent Decree. The United States is expected to file a motion with the
court to enter the Consent Decree as a final settlement around the end of
March, which the court will then consider. 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 proposed
Consent Decree and the Settlement Agreement, see Legal proceedings
on page 238.
Greenhouse gas emissions
The disclosures in relation to greenhouse gas emissions are included in
Corporate responsibility – Environment and society on page 46.
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) – (11)
(12), (13) Dividend waivers
(14)
Page
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Not applicable
245
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Cautionary statement
In order to utilize the ‘safe harbor’ provisions of the United States Private
Securities Litigation Reform Act of 1995 (the ‘PSLRA’), 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 – 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 6-7),
the Group chief executive’s letter (pages 8-9), the Strategic report (pages 1-
54), Additional disclosures (pages 215-246) and Shareholder information
(pages 247-258), including but not limited to statements under the headings
‘Our market outlook’, ‘Our business model and strategy’, ‘Beyond 2035’, ‘Our
distinctive capabilities’ and ‘Lower oil and gas prices’ and including but not
limited to statements regarding plans and prospects relating to future value
creation, long-term growth, capital discipline and growth in sustainable free
cash flow and shareholder distributions; future dividend and optional scrip
dividend payments; expectations regarding the effective tax rate in 2016;
future working capital and cash management and the net debt ratio; our
intention to maintain a strong cash position; expected payments under
contractual and commercial commitments and purchase obligations; our aim
to rebalance our sources and uses of cash by 2017; expectations regarding our
ability to respond to the current low oil price environment; plans and
expectations regarding capital expenditure, reduction in our cost base and
cash costs, divestments and gearing in 2016 and beyond; plans to reduce our
workforce and third-party spend in the near term; expectations regarding
underlying production and capital investment in 2016; plans to invest in a
balanced range of resources and geographies; plans and expectations
regarding the settlement of legal exposures relating to the Deepwater Horizon
incident and the court approval thereof; plans regarding production and value
creation from new projects including at Shah Deniz 2 in Azerbaijan and
Khazzan in Oman; expectations regarding the future level of oil and gas prices
and industry product supply, demand and pricing in the near and long term,
demographic changes and their effect on demand for energy and our outlook
and projections of future energy trends, including the role of oil, gas and
renewables therein; plans to strengthen our portfolio of high-return and longer-
life assets and improve operations; plans to form key partnerships and
relationships with governments, customers, partners, communities, suppliers
and other institutions; expectations regarding advances in technology including
from research at the BP International Centre for Advanced Materials; plans to
undertake joint exploration with Rosneft including in East Siberia, the West
Siberian and Yenisey-Khatanga basins and the Volga-Urals region of Russia;
expectations regarding future managed base decline and the current and
future prospects of our discoveries, resources, reserves and positions; plans
and expectations regarding the timing and composition of future projects,
including with regard to the Atoll discovery in Egypt; expectations regarding
the 2016 environment for refining and refinery turnarounds; plans to dissolve
our German joint operation with Rosneft, to dispose of our Amsterdam oil
terminal and to enter into joint ventures on certain midstream assets in North
American and Australia; plans to roll out BP fuels with ACTIVE technology in
Spain and additional markets in 2016; plans and expectations with regard to
the strategic aims of Air BP and our lubricants business; expectations
regarding improvements in operating performance and efficiency in the
petrochemicals business; expectations regarding future safety performance
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and plans to enhance safety, cybersecurity, compliance and risk management;
the future strategy for and planned investments in renewable energy including
investment in biobutanol; plans and expectations regarding the annual charges
of Other business and corporate for 2016, the introduction of 28 deep-sea oil
tankers and six LNG tankers into the BP-operated fleet between 2016 and
2019 and improvements in production, revenue and life of fields from
investment in equipment and maintenance; expectations regarding the actions
of contractors and partners and their terms of service; expectations regarding
future environmental regulations and policy, their impact on our business and
plans to reduce our environmental impact; our plans to work collaboratively
with government regulators in planning for oil spill response and to implement
its human rights policy; our planned disclosures regarding payments to
governments in compliance with the EU Accounting Directive; plans to reduce
activity and simplify processes in response to the current low oil price
environment; our aim to develop the capabilities of its workforce with a focus
on maintaining safe and reliable operations; our aim to maintain a diverse
workforce, create an inclusive environment and ensure equal opportunity,
including for women to represent 25% of group leaders by 2020; policies and
goals related to risk management; expectations regarding future Upstream
operations, including agreements or contracts with or relating to the Clair field,
the Gulf of Mexico, Canada and the Canadian Beaufort Sea, Nova Scotia and
Newfoundland; our joint ownership interests in exploration concessions and
plans to drill therein; plans to transfer operatorship of certain fields; plans
related to the Loyal field, the Culzean field, the North Sea and Alaska; plans
and expectations regarding our equity interests and partnerships in Angola,
Algeria, Libya and Egypt; plans and expectations regarding Western Indonesia,
China, Azerbaijan, Oman, Abu Dhabi, India, Iraq and Russia; plans and
expectations regarding our activities in Australia and Eastern Indonesia;
projections regarding oil and gas reserves, including recovery and turnover
time thereof; plans regarding compliance with environmental regulation; our
plans and expectations regarding settlement of claims related to the
Deepwater Horizon incident and related legal proceedings; and 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 risks associated with such proceedings and our intentions in
respect thereof; and (ii) certain statements in Corporate governance (pages 55-
75) and the Directors’ remuneration report (pages 76-92) with regard to the
anticipated future composition of the board of directors; the board’s goals and
areas of focus stemming from the board’s annual evaluation; plans regarding
review of our governance policies in 2016, the timing of future audit contract
tendering and areas of focus for the audit committee; and goals and areas of
focus of board committees, including the Safety, ethics and environment
assurance committee, the Geopolitical committee and the Chairman’s and
nomination 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 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
fields onstream; the timing, quantum and nature of certain 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; 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; the timing
and amount of future 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; our access to future credit resources; business
disruption and crisis management; the impact on our reputation of ethical
misconduct and non-compliance 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; wars and acts of terrorism; cyberattacks or sabotage; and other
factors discussed elsewhere in this report including under Risk factors (pages 53-
54). 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 our 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 our internal assessments
of market share based on publicly available information about the financial
results and performance of market participants.
Shareholder
information
248 Share prices and listings
248 Dividends
249 UK foreign exchange controls on dividends
249 Shareholder taxation information
251 Major shareholders
251 Annual general meeting
251 Memorandum and Articles of Association
253 Purchases of equity securities by the issuer and
affiliated purchasers
254 Fees and charges payable by ADSs holders
254 Fees and payments made by the Depositary to the
issuer
254 Documents on display
255 Shareholding administration
255 Exhibits
255 Abbreviations, glossary and trade marks
BP Annual Report and Form 20-F 2015
247
Share prices and listings
Markets and market prices
The primary market for BP’s ordinary shares is the London Stock
Exchange (LSE). BP’s ordinary shares are a constituent element of the
Financial Times Stock Exchange 100 Index. BP’s ordinary shares are
also traded on the Frankfurt Stock Exchange in Germany.
Trading of BP’s shares on the LSE is primarily through the use of the
Stock Exchange Electronic Trading Service (SETS), introduced in 1997
for the largest companies in terms of market capitalization whose
primary listing is the LSE. Under SETS, buy and sell orders at specific
prices may be sent electronically to the exchange by any firm that is a
member of the LSE, on behalf of a client or on behalf of itself acting as
a principal. The orders are then anonymously displayed in the order
book. When there is a match on a buy and a sell order, the trade is
executed and automatically reported to the LSE. Trading is continuous
from 8.00am to 4.30pm UK time but, in the event of a 20% movement
in the share price either way, the LSE may impose a temporary halt in
the trading of that company’s shares in the order book to allow the
market to re-establish equilibrium. Dealings in ordinary shares may also
take place between an investor and a market-maker, via a member firm,
outside the electronic order book.
In the US, BP’s securities are traded on the New York Stock Exchange
(NYSE) in the form of ADSs, for which JPMorgan Chase Bank, N.A. is
the depositary (the Depositary) and transfer agent. The Depositary’s
principal office is 4 New York Plaza, Floor 12, New York, NY, 10004, US.
Each ADS represents six ordinary shares. ADSs are listed on the NYSE.
ADSs are evidenced by American depositary receipts (ADRs), which
may be issued in either certificated or book entry form.
The following table sets forth, for the periods indicated, the highest and
lowest middle market quotations for BP’s ordinary shares and ADSs for
the periods shown. These are derived from the highest and lowest
intra-day sales prices as reported on the LSE and NYSE, respectively.
Year ended 31 December
2011
2012
2013
2014
2015
Year ended 31 December
2014: First quarter (January-March)
Second quarter (April-June)
Third quarter (July-September)
Fourth quarter (October-December)
2015: First quarter (January-March)
Second quarter (April-June)
Third quarter (July-September)
Fourth quarter (October-December)
2016: First quarter (to 16 February)
Month of
September 2015
October 2015
November 2015
December 2015
January 2016
February 2016 (to 16 February)
Pence
Dollars
Ordinary shares
American depositary sharesa
High
Low
High
Low
514.90
512.00
494.20
526.80
484.15
510.00
526.80
525.80
455.45
457.10
484.15
437.40
403.25
376.10
355.85
391.70
403.25
384.55
376.10
366.95
361.25
388.56
426.50
364.40
322.90
462.64
467.10
440.72
364.40
382.15
420.15
322.90
329.30
310.25
322.90
342.25
364.50
329.30
323.10
310.25
49.50
48.34
48.65
53.48
43.60
51.02
53.48
53.48
44.14
41.93
43.60
41.29
37.23
32.37
32.41
35.96
37.23
34.77
32.37
31.70
33.62
36.25
39.99
34.88
29.38
45.83
47.14
43.80
34.88
35.67
39.50
29.38
30.13
27.64
29.38
30.96
33.38
30.13
28.46
27.64
a One ADS is equivalent to six 25 cent ordinary shares.
Source: Thomson Reuters Datastream.
Market prices for the ordinary shares on the LSE and in after-hours
trading off the LSE, in each case while the NYSE is open, and the
market prices for ADSs on the NYSE, are closely related due to
arbitrage among the various markets, although differences may exist
from time to time.
On 16 February 2016, 893,653,858.5 ADSs (equivalent to approximately
5,361,923,151 ordinary shares or some 29.01% of the total issued
share capital, excluding shares held in treasury) were outstanding and
were held by approximately 92,375 ADS holders. Of these, about
91,266 had registered addresses in the US at that date. One of the
registered holders of ADSs represents some 999,817 underlying
holders.
On 16 February 2016, there were approximately 262,938 ordinary
shareholders. Of these shareholders, around 1,577 had registered
addresses in the US and held a total of some 4,108,986 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 of their respective
country of residence.
248
BP Annual Report and Form 20-F 2015
Dividends
BP’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 BP ordinary
shares will be paid in sterling and on BP 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 9.
A Scrip Dividend Programme (Scrip Programme) was approved by
shareholders in 2010 and was renewed for a further three years at the
2015 AGM. It enables BP ordinary shareholders and ADS holders to
elect to receive dividends by way of new fully paid BP 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. Should the directors decide not to offer the Scrip Programme
in respect of any particular dividend, cash will be paid automatically
instead.
Future dividends will be dependent on future earnings, the financial
condition of the group, the Risk factors set out on page 53 and other
matters that may affect the business of the group set out in Our strategy
on page 13 and in Liquidity and capital resources on page 219.
The following table shows dividends announced and paid by the
company per ADS for the past five years.
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.
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.
Dividends per ADSa
2011
2012
2013
2014
2015
UK pence
US cents
UK pence
US cents
UK pence
US cents
UK pence
US cents
UK pence
US cents
March
26.02 25.68
42
June September December
25.90
42
Total
26.82 104.42
168
42
42
48
54
30.57 30.90
48
36.01 35.01
54
34.24 34.84
58.5
40.00 39.18
60
60
57
30.10
48
34.58
54
35.76
58.5
39.29
60
54
57
33.53 125.10
198
34.80 140.40
219
38.26 143.10
234
39.81 158.28
240
60
60
a Dividends announced and paid by the company on ordinary and preference shares are provided
in Financial statements – Note 9.
UK foreign exchange controls on dividends
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 voting stock,
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 (i) a citizen or resident of the US, (ii) a US
domestic corporation, (iii) an estate whose income is subject to US
federal income taxation regardless of its source, or (iv) 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 in the Deposit Agreement 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
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 but until 5 April 2016, is 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.
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 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
advisor 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.
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.
BP Annual Report and Form 20-F 2015
249
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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.
US Medicare Tax
A US holder that is an individual or estate, or a trust that does not fall into
a special class of trusts that is exempt from such tax, is subject to a
3.8% tax on the lesser of (1) the US holder’s ‘net investment income’ (or
‘undistributed net investment income’ in the case of an estate or trust)
for the relevant taxable year and (2) the excess of the US holder’s
modified adjusted gross income for the taxable year over a certain
threshold (which in the case of individuals is between $125,000 and
$250,000, depending on the individual’s circumstances). A holder’s net
investment income generally includes its dividend income and its net
gains from the disposition of shares or ADSs, unless such dividend
income or net gains are derived in the ordinary course of the conduct of a
trade or business (other than a trade or business that consists of certain
passive or trading activities). If you are a US holder that is an individual,
estate or trust, you are urged to consult your tax advisors regarding the
applicability of the Medicare tax to your income and gains in respect of
your investment in the shares or ADSs.
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 (i) resident for
tax purposes in the United Kingdom at the date of disposal, (ii) if he 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, (iii) a
US domestic corporation resident in the UK by reason of its business
being managed or controlled in the UK or (iv) 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.
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.
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, or 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
The company has an optional Scrip Programme, wherein holders of BP
ordinary shares or ADSs may 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.
250
BP Annual Report and Form 20-F 2015
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 and Transparency Rules (DTR)
and the US Securities Exchange Act of 1934.
Register of members holding BP ordinary shares as at
31 December 2015
Range of holdings
1-200
201-1,000
1,001-10,000
10,001-100,000
100,001-1,000,000
Over 1,000,000a
Totals
Number of ordinary
shareholders
55,102
91,461
104,537
10,801
761
650
Percentage of total
ordinary shareholders
20.93
34.73
39.70
4.10
0.29
0.25
Percentage of total
ordinary share capital
excluding shares
held in treasury
0.01
0.27
1.75
1.19
1.55
95.23
263,312
100.00
100.00
a Includes JPMorgan Chase Bank, N.A. holding 29.04% 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 2015a
Range of holdings
1-200
201-1,000
1,001-10,000
10,001-100,000
100,001-1,000,000
Over 1,000,000b
Totals
Number of
ADS holders
54,200
24,782
13,097
662
9
1
92,751
Percentage of total
ADS holders
58.44
26.73
14.12
0.71
0.00
0.00
Percentage of total
ADSs
0.34
1.33
3.84
1.23
0.16
93.10
100.00
100.00
a One ADS represents six 25 cent ordinary shares.
b One holder of ADSs represents 991,246 underlying shareholders, as at 11 January 2016.
As at 31 December 2015, there were also 1,436 preference
shareholders. Preference shareholders represented 0.46% and ordinary
shareholders represented 99.54% of the total issued nominal share
capital of the company (excluding shares held in treasury) as at that date.
In accordance with DTR 5, we have received notification that as at
31 December 2015 BlackRock, Inc held 6.42% and Legal & General
Group plc held 3.23% of the voting rights of the issued share capital of
the company. As at 16 February 2016 BlackRock, Inc. held 6.86% and
Legal & General Group plc held 3.21% of the voting rights of the issued
share capital of the company.
Under the US Securities Exchange Act of 1934 BP has received
notification of the following interests as at 16 February 2016:
Holder
JPMorgan Chase Bank N.A., depositary
for ADSs, through its nominee
Guaranty Nominees Limited
BlackRock, Inc.
Percentage
of ordinary
share capital
excluding
shares held
in treasury
Holding of
ordinary shares
5,361,923,151
1,269,247,291
29.01
6.86
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 16 February 2016:
Holder
The National Farmers Union Mutual
Insurance Society
M & G Investment Management Ltd.
Holding of 8%
cumulative first
preference shares
Percentage
of class
945,000
528,150
13.07
7.30
Holder
The National Farmers Union Mutual
Insurance Society
M & G Investment Management Ltd.
Bank Julius Baer
Smith & Williamson Investment
Management Ltd.
Holding of 9%
cumulative second
preference shares
Percentage
of class
987,000
644,450
294,000
18.03
11.77
5.37
279,500
5.11
In accordance with DTR 5.8.12, Smith and Williamson Holdings Limited
disposed of its interest in 32,500 8% cumulative first preference shares
during 2014.
In accordance with DTR 5.6, BlackRock, Inc. notified the company that its
indirect interest in ordinary shares decreased below 5% during 2014.
UBS Investment Bank notified the company that its indirect interest in
ordinary shares increased above 3% on 9 February 2015 and that it
decreased below the notifiable threshold on 16 February 2015.
UBS Investment Bank notified the company that its indirect interest in
ordinary shares increased above 3% on 7 May 2015 and that it decreased
below the notifiable threshold on 11 May 2015.
The Capital Group of Companies, Inc. notified the company that its
indirect interest in ordinary shares decreased below the notifiable
threshold on 21 July 2015.
UBS Investment Bank notified the company that its indirect interest in
ordinary shares increased above 3% on 4 November 2015 and that it
decreased below the notifiable threshold on 9 November 2015.
BlackRock, Inc. notified the company that its indirect interest in ordinary
shares remained above the previously disclosed threshold of 5%, on
26 November 2015, that it decreased below 5% on 4 February 2016 and
that it increased above 5% on 15 February 2016.
As at 16 February 2016, the total preference shares in issue comprised
only 0.46% of the company’s total issued nominal share capital
(excluding shares held in treasury), the rest being ordinary shares.
Annual general meeting
The 2016 AGM will be held on Thursday 14 April 2016 at 11.30am at
ExCeL London, One Western Gateway, Royal Victoria Dock, London,
E16 1XL. 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.
Ernst & Young 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 2016.
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. For information on where investors can obtain copies of the
Memorandum and Articles of Association see Documents on display on
page 254.
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 17 April 2008 shareholders voted to adopt new
Articles of Association, largely to take account of changes in UK company
law brought about by the Act. Further amendments to the Articles of
Association were approved by shareholders at the AGM held on
15 April 2010. At the AGM held on 16 April 2015 shareholders voted to
adopt new Articles of Association to reflect developments in practice and
to provide clarification and additional flexibility.
Objects and purposes
BP is 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
BP Annual Report and Form 20-F 2015
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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
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 subsidiaries.
• 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 subsidiaries.
• 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 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.
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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.
Dividend rights; other rights to share in company profits;
capital calls
If recommended by the directors of BP, BP shareholders 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 12 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 dividends or other monies unclaimed in
respect of those shares will be forfeited after a period of two years.
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 16 April 2015
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.
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.
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.
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 on page 252 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 (in England) 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.
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.
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 2015 are set out in Financial statements – Note 30. At the
AGM on 16 April 2015, authorization was given to the directors to allot
shares up to an aggregate nominal amount equal to $3,040 million.
Authority was also given to the directors to allot shares for cash and to
dispose of treasury shares, other than by way of rights issue, up to a
maximum of $228 million, without having to offer such shares to existing
shareholders. These authorities were given for the period until the next
AGM in 2016 or 16 July 2016, whichever is the earlier. These authorities
are renewed annually at the AGM.
Purchases of equity securities by the issuer
and affiliated purchasers
At the AGM on 16 April 2015, authorization was given to the company to
repurchase up to 1.8 billion ordinary shares for the period until the next
AGM in 2016 or 16 July 2016, being the latest dates by which an AGM
must be held for that year. This authorization is renewed annually at the
AGM. No ordinary shares were repurchased during 2015. The following
table provides details of ordinary share purchases made 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.
2015
January 5 – January 30
February 2 to February 5
September 21
October 29
November 3 – November 4
December 15
2016
January 1 – January 31
February 1 to February 16
Number of shares
purchased
by ESOPs or for
certain employee
share-based plansa
Average price
paid per share
$
6.19
6.50
5.22
5.99
5.94
5.16
36,600,000
6,960,000
1,132,000
2,800,000
2,700,000
950,000
Nil
Nil
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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.
BP Annual Report and Form 20-F 2015
253
Fees and charges payable by ADSs 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
Depositing or substituting the underlying
shares
Selling or exercising rights
Withdrawing an underlying share
Expenses of the Depositary
Dividend fees
Depositary actions
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.
Fee
$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.
US$0.005 per BP ADS per quarter per
cash distribution.
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 2015. The Depositary reimbursed to the company, or paid
amounts on the company’s behalf to third parties, or waived its fees and
expenses, of $11,858,206.46 for the year ended 31 December 2015.
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 2015. The Depositary has also paid
certain expenses directly to third parties on behalf of the company.
Category of expense reimbursed,
waived or paid directly to third parties
Service fees and out of pocket expenses
waiveda
Other third-party mailing costs reimbursedb
Dividend feesc
Total
Amount reimbursed, waived or paid
directly to third parties for the year
ended 31 December 2015
$
37,650
54,014.67
11,766,541.79
11,858,206.46
a Includes fees in relation to transfer agent costs and costs of the BP Scrip Dividend Programme
operated by JPMorgan Chase Bank, N.A.
b Payment of fees to Precision IR for investor support.
c Dividend fees are charged to ADS holders who receive a cash distribution, which BP uses to
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
expenses paid to or on behalf of the company during the 12-month period
prior to notice of removal or termination.
Documents on display
BP Annual Report and Form 20-F 2015 and BP Strategic Report 2015 are
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)870 241 3269 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@precisionir.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. It is
possible to read and copy documents that have been filed with the SEC
at its headquarters located at 100 F Street, NE, Washington, DC 20549,
US. You may also call the SEC at +1 800-SEC-0330. In addition, BP’s
SEC filings are available to the public at the SEC’s website. BP discloses
in this report (see Corporate governance practices (Form 20-F Item 16G)
on page 244) significant ways (if any) in which its corporate governance
practices differ from those mandated for US companies under NYSE
listing standards.
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BP Annual Report and Form 20-F 2015
Shareholding administration
If you have any queries about the administration of shareholdings, such
as change of address, change of ownership, dividend payments, the
Scrip Programme or to change the way you receive your company
documents (such as the BP Annual Report and Form 20-F, BP Strategic
Report and Notice of BP Annual General Meeting) please contact the BP
Registrar or the BP ADS Depositary.
Ordinary and preference shareholders
The BP Registrar Capita Asset Services
The Registry, 34 Beckenham Road
Beckenham, Kent BR3 4TU, UK
Freephone in UK 0800 701107
From outside the UK +44 (0)20 3170 3678
Fax +44 (0)1484 601512
ADS holders
JPMorgan Chase Bank, N.A. 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
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 4.1
Exhibit 4.2
Exhibit 4.3
Exhibit 4.4
Exhibit 4.7
Exhibit 4.10
Exhibit 7
Exhibit 8
Exhibit 11
Exhibit 12
Exhibit 13
Exhibit 15.1
Exhibit 15.2
Exhibit 15.3
Exhibit 15.4
Exhibit 15.5
Memorandum and Articles of Association of BP p.l.c.†
The BP Executive Directors’ Incentive Plan***†
Amended BP Deferred Annual Bonus Plan 2005**†
Amended Director’s Secondment Agreement for
R W Dudley******†
Amended Director’s Service Contract and Secondment
Agreement for R W Dudley*†
Director’s Service Contract for Dr B Gilvary****†
The BP Share Award Plan 2015†
Computation of Ratio of Earnings to Fixed Charges
(Unaudited)†
Subsidiaries (included as Note 36 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†
Administrative Agreement dated as of 13 March 2014
among the US Environmental Protection Agency, BP
p.l.c., and other BP subsidiaries***†
Proposed Consent Decree†
Gulf states Settlement Agreement†
* Incorporated by reference to the company’s Annual Report on Form 20-F for the year
ended 31 December 2010.
** Incorporated by reference to the company’s Annual Report on Form 20-F for the year
ended 31 December 2012.
*** 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 2011.
***** 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 2013.
# 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 the Registrant and its
subsidiaries authorized under any one instrument does not exceed 10%
of the total assets of BP p.l.c. and its subsidiaries on a consolidated basis.
The company agrees to furnish copies of any or all such instruments to
the SEC on request.
Abbreviations, glossary and trade marks
ADR
American depositary receipt.
ADS
American depositary share. 1 ADS = 6 ordinary shares.
Barrel (bbl)
159 litres, 42 US gallons.
bcf/d
Billion cubic feet per day.
bcfe
Billion cubic feet equivalent.
bcma
Billion cubic metres per annum.
b/d
Barrels per day.
boe/d
Barrels of oil equivalent per day.
DoJ
US Department of Justice.
GAAP
Generally accepted accounting practice.
Gas
Natural gas.
GHG
Greenhouse gas.
GWh
Gigawatt hour.
HSSE
Health, safety, security and environment.
IFRS
International Financial Reporting Standards.
KPIs
Key performance indicators.
LNG
Liquefied natural gas.
LPG
Liquefied petroleum gas.
mb/d
Thousand barrels per day.
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.
mmte
Million tonnes.
MW
Megawatt.
NGLs
Natural gas liquids.
PSA
Production-sharing agreement.
PTA
Purified terephthalic acid.
RC
Replacement cost.
SEC
The United States Securities and Exchange Commission.
BP Annual Report and Form 20-F 2015
255
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Glossary
Unless the context indicates otherwise, the definitions for the following
glossary terms are given below.
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.
Brent
A trading classification for North Sea crude oil that serves as a major
benchmark price for purchases of oil worldwide.
Cash costs
Non-GAAP measure. Cash costs are a subset of production and
manufacturing expenses plus distribution and administration expenses
and excludes 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 the presentation of
cash costs is a performance measure that provides investors with useful
information regarding the company’s financial condition 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.
Consolidation adjustment – UPII
Unrealized profit in inventory arising on inter-segment transactions.
Commodity trading contracts
BP’s Upstream and Downstream segments both participate 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. These
physical trading activities, together with associated incremental trading
opportunities, are discussed in Upstream on page 28 and in Downstream
on page 34. 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 arbitrage between markets.
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 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 over-
the-counter (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, products 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.
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Because the physically settled transactions are delivered by cargo, the
BFOE contract additionally specifies 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 achieved by transacting offsetting sale or
purchase contracts for the same location and delivery period that are
offset during the scheduling of delivery or dispatch. 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 often 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. 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.
Dividend yield
Sum of the four quarterly dividends announced in respect of the year as a
percentage of the year-end share price on the respective exchange. The
ordinary shareholders annual dividend yield includes an estimate of the
sterling amount expected to be paid in respect of the dividend for the
fourth quarter 2015 which was announced on 2 February 2016 in US
dollars.
Fair value accounting effects
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 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 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 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 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 and capacity contracts in question are valued
based on fair value using relevant forward prices prevailing at the end of
the period. The fair values of certain derivative instruments used to risk
manage LNG and oil and gas processing 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.
Free cash flow
Operating cash flow less net cash used in investing activities, as
presented in the group cash flow statement.
Gearing
See Net debt and net debt ratio definition.
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.
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 train
An LNG train is a processing facility used to liquefy and purify natural gas
in the formation of LNG.
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.
Net cash margin
Net cash margin is defined by Solomon Associates as the net margin
achieved after subtracting cash operating expenses and adding any
refinery revenue from other sources. Net cash margin is expressed in US
dollars per barrel of net refinery input.
Net debt and net debt ratio (gearing)
Non-GAAP measures. Net debt is calculated as gross 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. The net debt ratio
is defined as the ratio of net debt to the total of net debt plus total equity.
All components of equity are included in the denominator of the
calculation. BP believes these measures provide useful information to
investors. Net debt enables investors to see the economic effect of gross
debt, related hedges and cash and cash equivalents in total. The net debt
ratio enables investors to see how significant net debt is relative to equity
from shareholders. The derivatives are reported on the balance sheet
within the headings ‘Derivative financial instruments’. See Financial
statements – Note 26 for information on gross debt, which is the nearest
equivalent measure to net debt on an IFRS basis.
Net income per barrel
Non-GAAP measure. Net income per barrel is calculated by taking
underlying replacement cost profit before interest and tax for the
Downstream segment, deducting tax at an assumed 30% effective tax
rate on underlying replacement cost profit and then dividing this notional
post tax underlying replacement cost profit by the Downstream
segment’s total refining capacity.
Net investment (organic)
Net investment (organic) is organic capital expenditure less the value of
divestments announced in the year.
Net wind generation capacity
The sum of the rated capacities of the assets/turbines that have entered
into commercial operation, including BP’s share of equity-accounted
entities. The gross data is the equivalent capacity on a gross-joint venture
basis, which includes 100% of the capacity of equity-accounted entities
where BP has partial ownership.
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 217.
Operating capital employed
Non-GAAP measure. Total assets (excluding goodwill) less total liabilities,
excluding finance debt and current and deferred taxation.
Operating cash flow and operating cash
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 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
Excludes acquisitions, asset exchanges, and other inorganic capital
expenditure. An analysis of capital expenditure by segment and region is
shown in Financial statements – Note 5.
BP Annual Report and Form 20-F 2015
257
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Plant reliability
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 and weather.
Pre-tax returns
Non-GAAP measure. Pre-tax returns is the ratio of underlying
replacement cost profit before interest and tax to the average operating
capital employed for the period.
Production-sharing agreement (PSA)
An arrangement through which an oil 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.
Proved reserves replacement ratio
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.
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.
Refining availability
Represents Solomon Associates’ operational availability, 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 not a recognized 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. See
Financial statements – Note 5.
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.
Tier 1 process safety events
Losses of primary containment from a process of greatest consequence –
causing harm to a member of the workforce or costly damage to equipment
or exceeding defined quantities.
Tight oil and gas
Natural oil and gas reservoirs locked in hard sandstone rocks with low
permeability, making the underground formation extremely tight.
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 production
Production after adjusting for divestments and entitlement impacts in our
production-sharing agreements.
Underlying RC profit or loss
RC profit or loss after adjusting for non-operating items and fair value
accounting effects. Underlying RC profit or loss and fair value accounting
effects are not recognized GAAP measures. See pages 217 and 218 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.
Trade marks
Trade marks of the BP group appear throughout this report.
They include:
ACTIVE
Aral
ARCO
BP
Bright Water
Castrol
Independent Simultaneous
Source
Nexcel
Field of the Future
Wild Bean Cafe
Apple Pay is a registered trade mark
of Apple Inc.
M&S Simply Food is a registered
trade mark of Marks & Spencer plc.
The Directors’ report on pages 55-75, 93-94, 169-195 and 215-258 was approved by the board and signed on its behalf by David J Jackson, company
secretary on 4 March 2016.
BP p.l.c.
Registered in England and Wales No. 102498
258
BP Annual Report and Form 20-F 2015
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/ David J Jackson
Company secretary
4 March 2016
BP Annual Report and Form 20-F 2015
259
Cross reference to Form 20-F
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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
260
BP Annual Report and Form 20-F 2015
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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 2015
Details of our financial
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Published in March.
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Details of our sustainability
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An objective review of key
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Published in June.
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