20-F
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F
(Mark One)
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REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934 |
OR
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended 31 December 2015
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
OR
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SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number: 1-6262
BP p.l.c.
(Exact name of Registrant as specified in its charter)
England and Wales
(Jurisdiction of incorporation or organization)
1 St James’s Square, London SW1Y 4PD
United Kingdom
(Address
of principal executive offices)
Dr Brian Gilvary
BP p.l.c.
1 St
James’s Square, London SW1Y 4PD
United Kingdom
Tel +44 (0) 20 7496 5311
Fax +44 (0) 20 7496 4573
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(b) of the Act
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Name of each exchange on which registered |
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New York Stock Exchange* |
| Floating Rate Guaranteed Notes due 2016 |
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New York Stock Exchange |
| Floating Rate Guaranteed Notes due 2017 |
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New York Stock Exchange |
| Floating Rate Guaranteed Notes due February 2018 |
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New York Stock Exchange |
| Floating Rate Guaranteed Notes due May 2018 |
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New York Stock Exchange |
| Floating Rate Guaranteed Notes due September 2018 |
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New York Stock Exchange |
| Floating Rate Guaranteed Notes due 2019 |
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New York Stock Exchange |
| 2.248% Guaranteed Notes due 2016 |
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New York Stock Exchange |
| 3.200% Guaranteed Notes due 2016 |
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New York Stock Exchange |
| 1.375% Guaranteed Notes due 2017 |
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New York Stock Exchange |
| 1.846% Guaranteed Notes due 2017 |
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New York Stock Exchange |
| 1.375% Guaranteed Notes due 2018 |
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New York Stock Exchange |
| 1.674% Guaranteed Notes due 2018 |
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New York Stock Exchange |
| 2.241% Guaranteed Notes due 2018 |
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New York Stock Exchange |
| 4.750% Guaranteed Notes due 2019 |
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New York Stock Exchange |
| 2.237% Guaranteed Notes due 2019 |
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New York Stock Exchange |
| 2.315% Guaranteed Notes due 2020 |
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New York Stock Exchange |
| 2.521% Guaranteed Notes due 2020 |
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New York Stock Exchange |
| 4.500% Guaranteed Notes due 2020 |
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New York Stock Exchange |
| 4.742% Guaranteed Notes due 2021 |
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New York Stock Exchange |
| 3.561% Guaranteed Notes due 2021 |
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New York Stock Exchange |
| 2.500% Guaranteed Notes due 2022 |
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New York Stock Exchange |
| 3.245% Guaranteed Notes due 2022 |
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New York Stock Exchange |
| 3.062% Guaranteed Notes due 2022 |
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New York Stock Exchange |
| 2.750% Guaranteed Notes due 2023 |
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New York Stock Exchange |
| 3.994% Guaranteed Notes due 2023 |
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New York Stock Exchange |
| 3.535% Guaranteed Notes due 2024 |
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New York Stock Exchange |
| 3.814% Guaranteed Notes due 2024 |
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New York Stock Exchange |
| 3.506% Guaranteed Notes due 2025 |
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New York Stock Exchange |
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Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission |
Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
Securities for
which there is a reporting obligation pursuant to Section 15(d) of the Act.
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual
report.
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| Ordinary Shares of 25c each |
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20,108,770,973 |
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| Cumulative First Preference Shares of £1 each |
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7,232,838 |
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| Cumulative Second Preference Shares of £1 each |
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5,473,414 |
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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes x No ¨
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes ¨ No x
Note—Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 from their obligations under those Sections.
Indicate by check mark whether the Registrant (1) has
filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such
files).* Yes ¨ No ¨
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This requirement does not apply to the registrant in respect of this filing. |
Indicate by
check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated
filer x Accelerated filer ¨ Non-accelerated filer ¨
Indicate by check mark which basis of accounting the registrant has used to prepare the
financial statements included in this filing:
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| U.S. GAAP ¨ |
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International Financial Reporting Standards as issued
by the International Accounting Standards Board x |
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Other ¨ |
If “Other” has been checked in response to the previous question, indicate by check mark which
financial statement item the registrant has elected to follow.
Item 17 ¨
Item 18 ¨
If this is an annual report,
indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
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| 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.
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.
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.
t
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
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| BP Annual Report and Form 20-F 2015 |
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Information about this report
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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, 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 101-102.
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. |
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« Defined on page 256. |
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Registered office and
our worldwide headquarters: BP p.l.c.
1 St James’s Square London SW1Y
4PD UK Tel +44 (0)20 7496
4000 Registered in England and Wales No. 102498.
London Stock Exchange symbol ‘BP.’ |
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Our agent in the
US: BP America Inc.
501 Westlake Park Boulevard Houston,
Texas 77079 US Tel +1 281
366 2000 |
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BP Annual Report and Form 20-F 2015 |
BP at a glance
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BP Annual Report and Form 20-F 2015 |
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BP Annual Report and Form 20-F 2015 |
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BP around the world
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BP Annual Report and Form 20-F 2015 |
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BP Annual Report and Form 20-F 2015 |
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Chairman’s letter
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| $7.3bn dividends to BP
shareholders
7.5%
ordinary shareholders annual dividend
yield «
7.7%
ADS shareholders annual dividend
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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
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BP Annual Report and Form 20-F 2015 |
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Board performance For information about the board
and its committees see page 55.
Remuneration For information about our
directors’ remuneration see page 76.
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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 |
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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.
a See Our financial framework on page 19. |
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BP Annual Report and Form 20-F 2015 |
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Group chief executive’s letter
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| 94.7%
2015 refining availability«.
95%
Upstream BP-operated plant
reliability«. |
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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.
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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.
q
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.
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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
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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.
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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)
Source: BP Energy Outlook. |
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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. |
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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. |
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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. |
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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. |
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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. |
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BP Annual Report and Form 20-F 2015 |
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Our business model and strategy
We aim to create value for our investors and benefits for
the communities and societies where we operate.
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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. |
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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. |
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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. |
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| 12 |
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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. |
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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. |
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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. |
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| « Defined on page 256. |
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BP Annual Report and Form 20-F 2015 |
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Our strategy in action
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| 14 |
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BP Annual Report and Form 20-F 2015 |
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| How we deliver |
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How we measure |
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Strategy in action in 2015 |
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| 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. |
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Recordable injury frequency, loss of primary containment, greenhouse gas emissions, tier 1 process safety events. |
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Improving reliability Improvement
plans are increasing UK North Sea plant reliability.
See page 44. |
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20 tier 1 process
safety events 2014: 28 |
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| 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. |
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Operating cash flow, gearing, total shareholder return, underlying replacement cost profit per ordinary share. |
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Capturing value Improving the
quality of future investments.
See page 30. |
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$19.1bn
operating cash flow 2014:
$32.8bn |
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| 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. |
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Major project delivery. |
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Adapting rapidly
Using local knowledge to increase our competitiveness.
See page 29. |
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major project start-ups in Upstream
2014: 7 |
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| 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. |
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Proved reserves replacement ratio. |
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Unlocking energy potential
Investing in exploration and development in Egypt.
See page 33. |
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61%
reserves replacement ratioa
2014: 63% |
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| 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. |
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Production. |
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Optimizing our assets Using our
technical expertise to maintain a secure and reliable supply.
See page 31. |
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3.3 million
barrels of oil equivalent per daya 2014: 3.2 million |
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| 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. |
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Refining availability. |
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Improving operations Improvements
at Castellón refinery are helping to increase profitability.
See page 36. |
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94.7%
refining availability 2014:
94.9% |
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| Creating shareholder value by
generating sustainable free cash flow over the long term
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| Advanced technology |
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Strong relationships |
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Proven expertise |
| 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. |
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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. |
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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. |
a On a combined basis of subsidiaries« and equity-accounted entities.
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| « Defined on page 256. |
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15 |
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Our distinctive capabilities
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| 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. q High-speed graphics workstations in our Sunbury office use state-of-the-art
software and projection equipment to create a 3D virtual world. |
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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 |
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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.
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. |
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| 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. |
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| 16 |
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BP Annual Report and Form 20-F 2015 |
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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. |
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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. |
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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. |
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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. |
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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. |
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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. |
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| 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. |
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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. |
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BP Annual Report and Form 20-F 2015 |
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17 |
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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.
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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. t Remodelling Mad Dog
Phase 2 reduced our project cost estimate by more than half. |
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| 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. |
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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). |
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| Sources and uses of cash
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. |
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| 18 |
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| 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. |
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Our financial framework – through 2017
Underpinning our commitment to sustain the dividend for our shareholders
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Principle |
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2015 achievement |
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Looking ahead |
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Optimize capital expenditure |
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2015 organic capital expenditure was $18.7 billion.
This is 18% down from the 2011-2014 period average. |
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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. |
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Reduce cash costs |
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We made significant progress in reducing cash costs compared with 2014. |
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We anticipate the reduction in our cash costs to be close to $7 billion versus 2014 by the end of 2017. |
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Make selective divestments |
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We completed the $10-billion divestment programme announced for 2014-2015. |
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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. |
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Maintain flexibility around
gearing |
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Gearing« at the end of 2015 was 21.6% against a 2011-2014 average of 18%. |
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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%. |
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How we are putting this into action
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Upstream
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. |
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Downstream
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. |
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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. |
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Figures exclude retail staff and agricultural,
operational and seasonal workers in Brazil. |
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| « Defined on page 256. |
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BP Annual Report and Form 20-F 2015 |
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19 |
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Our key performance indicators
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| 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.
Key
KPIs used to measure progress against our
strategy.
KPIs used to determine 2015 and 2016
remuneration.
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Underlying RC
profit« per ordinary share (cents)
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. |
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Operating cash flow ($ billion)
Operating cash flow is net cash flow provided by operating
activities, as reported in the group cash flow statement. Operating activities are the principal revenue-generating activities of the group and other activities that are not investing or financing activities.
2015 performance Operating cash flow was lower in
2015, largely reflecting the impact of the lower oil price environment. |
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Gearing (net debt
ratio)« (%)
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. |
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Refining availability (%) |
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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. |
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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.
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. |
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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.
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). |
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| 20 |
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BP Annual Report and Form 20-F 2015 |
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| Total shareholder return (%) |
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Reserves replacement ratio (%) |
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Major project delivery |
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Production (mboe/d) |
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| 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. |
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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.
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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. |
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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. |
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| Tier 1 process safety events«a |
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Greenhouse gas emissionsb
(million tonnes of CO2 equivalent) |
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Group priorities indexd (%) |
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Diversity and inclusiond (%) |
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| 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. |
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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.
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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. |
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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. |
| 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. |
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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. |
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d Relates to BP employees. |
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| « Defined on page 256. |
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BP Annual Report and Form 20-F 2015 |
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21 |
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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.
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Highlights of the
year |
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Strong safety and operational performance in a
difficult environment |
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• Responded early and decisively to lower oil price environment.
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• Excellent safety standards with
continuous improvement over the past three years, leading to improvements in reliability and operations. |
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• Strong operating cash flow« and underlying replacement cost profit relative to plan. |
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• Net investment managed aggressively to reflect ‘lower for longer’ oil price environment. |
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• Executive directors’ pay outcomes reflect strong operating performance relative to
plan. |
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• Alignment between executives and shareholders with the majority of executive director
remuneration paid in equity with lengthy retention requirements. |
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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 |
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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. |
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Short-term: annual
bonus |
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Measure |
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Result |
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Target |
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Outcome |
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Safety and operational risk
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Loss of primary containment |
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Spills and leaks declined.
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£
253 events |
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208 eventsa
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Process safety tier 1 events |
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The most serious process
safety events were reduced. |
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£ 29 events |
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20 events |
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Recordable injury frequency |
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Number of work-related
recordable injuries per 200k hours fell. |
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£ 0.261/200k
hoursb |
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0.223/200k
hoursb |
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Value |
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For more information on the |
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Operating cash flow |
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Significantly ahead of plan. |
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$17.2bn |
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$19.1bn |
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| group’s key performance
indicators see page 20. |
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Underlying replacement cost
profit |
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Significantly ahead of plan. |
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$4.2bn |
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$5.9bn |
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Net investment (organic) |
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Significantly ahead of plan. |
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i18% |
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i27%
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Corporate and functional
costs |
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Significantly ahead of plan. |
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i5.9% |
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i17.6%
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Major project delivery |
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On target. |
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a Adjusted in accordance with the treatment of the loss of primary containment key performance indicator on page 20. |
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b Excludes biofuels. |
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| 22 |
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BP Annual Report and Form 20-F 2015 |
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| 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. |
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Long-term: performance share
plan |
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Measure |
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Result |
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Target |
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Outcome |
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Relative TSR |
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BP’s TSR ranked third versus other oil majors. |
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Outperform
peers |
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Third |
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Operating cash flow |
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Strong operating cash flow in 2015 relative to plan. |
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$17.7bn |
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$19.1bn |
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Strategic imperatives |
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Relative reserves replacement ratio (RRR) |
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BP’s RRR preliminary ranked first versus other oil majors.
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Outperform
peers |
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First |
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Safety and operational risk: |
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Downward trend over
the last three years. |
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• Loss of primary containment |
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£ 212 events |
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208 eventsa |
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• Process safety tier 1 events |
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£ 30 events |
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20 events |
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• Recordable injury frequency |
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£ 0.240/200k |
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0.223/200k |
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hoursb |
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hours |
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Major project delivery |
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15 major projects were commissioned. |
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11 |
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15 |
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a Adjusted in accordance with the treatment of the loss of primary containment key performance indicator on page 20.
b Excluding biofuels. |
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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.
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 |
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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.
For the single figure remuneration table see page
77. |
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Total remuneration (excluding pensions) |
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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 |
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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 |
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| « Defined on page 256. |
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BP Annual Report and Form 20-F 2015 |
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23 |
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Our markets in 2015
A snapshot of the challenging global energy market in 2015.
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| p 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)
Natural gas prices (quarterly
average)
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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. a From IEA Oil Market Report, February 2016 ©, OECD/IEA
2016, Page 4.
b BP Statistical Review of World Energy
2015. |
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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« hub price to an 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.
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.
Prices and margins See pages 29 and
35. |
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| 24 |
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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.
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| 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.
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A helicopter-sharing first t
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. |
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Easing the bottleneck q
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. |
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| Foundations for success p
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. |
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Logistics planning p
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. |
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Steam clean savings p
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. |
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Making storage simpler u
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 $32 million by selling surplus materials and scrap. |
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| « Defined on page 256. |
|
BP Annual Report and Form 20-F 2015 |
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25 |
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Group performance
A summary of our group financial and
operating performance.
p
A technician monitors
the pressure gauges in the enhanced oil recovery laboratory in Sunbury.
Financial and operating performance
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$ million |
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2015 |
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2014 |
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2013 |
|
| Profit (loss) before interest and taxation |
|
|
(7,918 |
) |
|
|
6,412 |
|
|
|
31,769 |
|
| Finance costs and net finance expense relating to pensions and other post-retirement benefits |
|
|
(1,653 |
) |
|
|
(1,462 |
) |
|
|
(1,548 |
) |
| Taxation |
|
|
3,171 |
|
|
|
(947 |
) |
|
|
(6,463 |
) |
| Non-controlling interests |
|
|
(82 |
) |
|
|
(223 |
) |
|
|
(307 |
) |
| Profit (loss) for the yeara |
|
|
(6,482 |
) |
|
|
3,780 |
|
|
|
23,451 |
|
| Inventory holding (gains) losses«, net of tax |
|
|
1,320 |
|
|
|
4,293 |
|
|
|
230 |
|
| Replacement cost profit (loss)« |
|
|
(5,162 |
) |
|
|
8,073 |
|
|
|
23,681 |
|
| Net charge (credit) for non-operating
items«, net of tax |
|
|
11,272 |
|
|
|
4,620 |
|
|
|
(10,533 |
) |
| Net (favourable) unfavourable impact of fair value accounting effects«, net of tax |
|
|
(205 |
) |
|
|
(557 |
) |
|
|
280 |
|
| Underlying replacement cost profit« |
|
|
5,905 |
|
|
|
12,136 |
|
|
|
13,428 |
|
| Dividends paid per share – cents |
|
|
40.0 |
|
|
|
39.0 |
|
|
|
36.5 |
|
|
– pence |
|
|
26.383 |
|
|
|
23.850 |
|
|
|
23.399 |
|
| Capital expenditure and acquisitions, 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.
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. |
Taxation
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%).
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.
|
|
|
| 26 |
|
BP Annual Report and Form 20-F 2015 |
Cash flow and net debt information
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
$ million |
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Net cash provided by operating activities
|
|
|
19,133 |
|
|
|
32,754 |
|
|
|
21,100 |
|
| Net cash used in investing activities |
|
|
(17,300 |
) |
|
|
(19,574 |
) |
|
|
(7,855 |
) |
| Net cash used in financing activities |
|
|
(4,535 |
) |
|
|
(5,266 |
) |
|
|
(10,400 |
) |
| Cash and cash equivalents at end of year |
|
|
26,389 |
|
|
|
29,763 |
|
|
|
22,520 |
|
| Gross debt |
|
|
53,168 |
|
|
|
52,854 |
|
|
|
48,192 |
|
| Net debt« |
|
|
27,158 |
|
|
|
22,646 |
|
|
|
25,195 |
|
| Gross debt to gross debt-plus-equity |
|
|
35.1% |
|
|
|
31.9% |
|
|
|
27.0% |
|
| Net debt to net debt-plus-equity«
|
|
|
21.6% |
|
|
|
16.7% |
|
|
|
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.
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.
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
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
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Estimated net proved reservesa
(net of
royalties) |
|
|
|
|
|
|
|
|
|
|
|
|
| Liquids« (mmb) |
|
|
9,560 |
|
|
|
9,817 |
|
|
|
10,070 |
|
| Natural gas (bcf) |
|
|
44,197 |
|
|
|
44,695 |
|
|
|
45,975 |
|
| Total hydrocarbons«
(mmboe) |
|
|
17,180 |
|
|
|
17,523 |
|
|
|
17,996 |
|
| Of which: Equity-accounted
entitiesb |
|
|
7,928 |
|
|
|
7,828 |
|
|
|
7,753 |
|
| Productiona (net of royalties) |
|
|
|
|
|
|
|
|
|
|
|
|
| Liquids (mb/d) |
|
|
2,045 |
|
|
|
1,927 |
|
|
|
2,013 |
|
| Natural gas (mmcf/d) |
|
|
7,146 |
|
|
|
7,100 |
|
|
|
7,060 |
|
| Total hydrocarbons
(mboe/d) |
|
|
3,277 |
|
|
|
3,151 |
|
|
|
3,230 |
|
| Of which: Subsidiaries« |
|
|
2,007 |
|
|
|
1,898 |
|
|
|
1,882 |
|
|
Equity-accounted
entitiesc |
|
|
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.
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.
|
|
|
|
|
|
See Oil and gas disclosures for the group on page 227. |
|
|
|
|
|
|
|
| « Defined on page 256. |
|
BP Annual Report and Form 20-F 2015 |
|
|
27 |
|
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.
p
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
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 activities efficiently; 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)
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. |
|
|
|
| 28 |
|
BP Annual Report and Form 20-F 2015 |
Financial performance
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
$ million |
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Sales and other operating revenuesa |
|
|
43,235 |
|
|
|
65,424 |
|
|
|
70,374 |
|
| RC profit before interest and tax |
|
|
(937 |
) |
|
|
8,934 |
|
|
|
16,657 |
|
| Net (favourable) unfavourable impact of non-operating items« and fair value accounting
effects« |
|
|
2,130 |
|
|
|
6,267 |
|
|
|
1,608 |
|
| Underlying RC profit before interest and tax |
|
|
1,193 |
|
|
|
15,201 |
|
|
|
18,265 |
|
| Capital expenditure and acquisitions |
|
|
17,082 |
|
|
|
19,772 |
|
|
|
19,115 |
|
| BP average realizations«b |
|
|
$ per barrel |
|
| Crude oilc |
|
|
47.78 |
|
|
|
93.65 |
|
|
|
105.38 |
|
| Natural gas liquids |
|
|
20.75 |
|
|
|
36.15 |
|
|
|
38.38 |
|
|
Liquids« |
|
|
45.63 |
|
|
|
87.96 |
|
|
|
99.24 |
|
| |
|
|
$ per thousand cubic
feet |
|
| Natural gas |
|
|
3.80 |
|
|
|
5.70 |
|
|
|
5.35 |
|
| US natural gas |
|
|
2.10 |
|
|
|
3.80 |
|
|
|
3.07 |
|
| |
|
|
$ per barrel of oil equivalent |
|
| Total hydrocarbons« |
|
|
34.78 |
|
|
|
60.85 |
|
|
|
63.58 |
|
| Average oil marker pricesd |
|
|
$ per barrel |
|
| Brent« |
|
|
52.39 |
|
|
|
98.95 |
|
|
|
108.66 |
|
| West Texas Intermediate |
|
|
48.71 |
|
|
|
93.28 |
|
|
|
97.99 |
|
| Average natural gas marker
prices |
|
|
$ per million British thermal units |
|
| Henry Hub gas price«e |
|
|
2.67 |
|
|
|
4.43 |
|
|
|
3.65 |
|
| |
|
|
pence per therm |
|
| UK National Balancing Point gas price«d |
|
|
42.61 |
|
|
|
50.01 |
|
|
|
67.99 |
|
| 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.
Brent ($/bbl)
Henry Hub ($/mmBtu)
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.
|
|
|
|
|
|
|
| « Defined on page 256. |
|
BP Annual Report and Form 20-F 2015 |
|
|
29 |
|
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« and other contractual agreements. We may do this alone or, more frequently, with
partners.
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 |
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.
Upstream reserves
Estimated net proved reservesa (net of royalties)
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Liquids |
|
|
million barrels |
|
| Crude oilb |
|
|
|
|
|
|
|
|
|
|
|
|
| Subsidiaries« |
|
|
3,560 |
|
|
|
3,582 |
|
|
|
3,798 |
|
| Equity-accounted entitiesc |
|
|
694 |
|
|
|
702 |
|
|
|
729 |
|
| |
|
|
4,254 |
|
|
|
4,283 |
|
|
|
4,527 |
|
| Natural gas liquids |
|
|
|
|
|
|
|
|
|
|
|
|
| Subsidiaries |
|
|
422 |
|
|
|
510 |
|
|
|
551 |
|
| Equity-accounted entitiesc |
|
|
13 |
|
|
|
16 |
|
|
|
16 |
|
| |
|
|
435 |
|
|
|
526 |
|
|
|
567 |
|
| Total liquids |
|
|
|
|
| Subsidiariesd |
|
|
3,982 |
|
|
|
4,092 |
|
|
|
4,349 |
|
| Equity-accounted entitiesc |
|
|
707 |
|
|
|
717 |
|
|
|
745 |
|
| |
|
|
4,689 |
|
|
|
4,809 |
|
|
|
5,094 |
|
| Natural gas |
|
|
billion cubic feet |
|
| Subsidiariese |
|
|
30,563 |
|
|
|
32,496 |
|
|
|
34,187 |
|
| Equity-accounted entitiesc |
|
|
2,465 |
|
|
|
2,373 |
|
|
|
2,517 |
|
| |
|
|
33,027 |
|
|
|
34,869 |
|
|
|
36,704 |
|
| Total hydrocarbons |
|
|
million barrels of oil equivalent |
|
| Subsidiaries |
|
|
9,252 |
|
|
|
9,694 |
|
|
|
10,243 |
|
| Equity-accounted entitiesc |
|
|
1,132 |
|
|
|
1,126 |
|
|
|
1,179 |
|
| |
|
|
10,384 |
|
|
|
10,821 |
|
|
|
11,422 |
|
| 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. |
|
|
|
|
|
|
|
| « Defined on page 256. |
|
BP Annual Report and Form 20-F 2015 |
|
|
31 |
|
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.
| • |
|
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.
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.
Production (net of royalties)a
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Liquids |
|
|
thousand barrels per day |
|
| Crude oilb |
|
|
|
|
|
|
|
|
|
|
|
|
| Subsidiaries |
|
|
971 |
|
|
|
844 |
|
|
|
789 |
|
| Equity-accounted entitiesc |
|
|
165 |
|
|
|
163 |
|
|
|
294 |
|
| |
|
|
1,137 |
|
|
|
1,007 |
|
|
|
1,083 |
|
| Natural gas liquids |
|
|
|
|
|
|
|
|
|
|
|
|
| Subsidiaries |
|
|
88 |
|
|
|
91 |
|
|
|
86 |
|
| Equity-accounted entitiesc |
|
|
7 |
|
|
|
7 |
|
|
|
8 |
|
| |
|
|
95 |
|
|
|
99 |
|
|
|
94 |
|
| Total liquids |
|
|
|
|
| Subsidiaries |
|
|
1,060 |
|
|
|
936 |
|
|
|
874 |
|
| Equity-accounted entitiesc |
|
|
172 |
|
|
|
170 |
|
|
|
302 |
|
| |
|
|
1,232 |
|
|
|
1,106 |
|
|
|
1,176 |
|
| Natural gas |
|
|
million cubic feet per day |
|
| Subsidiaries |
|
|
5,495 |
|
|
|
5,585 |
|
|
|
5,845 |
|
| Equity-accounted entitiesc |
|
|
456 |
|
|
|
431 |
|
|
|
415 |
|
| |
|
|
5,951 |
|
|
|
6,016 |
|
|
|
6,259 |
|
| Total hydrocarbons |
|
|
thousand barrels of oil equivalent per day |
|
| Subsidiaries |
|
|
2,007 |
|
|
|
1,898 |
|
|
|
1,882 |
|
| Equity-accounted entitiesc |
|
|
251 |
|
|
|
245 |
|
|
|
374 |
|
| |
|
|
2,258 |
|
|
|
2,143 |
|
|
|
2,256 |
|
| 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 |
|
|
|
Expected start-ups
2017-2020 |
| Kizomba Satellites Phase 2 |
|
Angola |
|
Deepwater |
|
|
|
|
|
Design and appraisal
phase |
|
|
|
|
|
|
| Greater Plutonio Phase 3* |
|
Angola |
|
Deepwater |
|
|
|
|
|
Angelin |
|
Trinidad |
|
LNG |
|
|
| Western Flank Phase A |
|
Australia |
|
LNG |
|
|
|
|
|
Atoll |
|
Egypt |
|
Conventional |
|
|
| Expected start-ups
2016-2020 |
|
|
|
B18 Platina* |
|
Angola |
|
Deepwater |
|
|
| Projects
currently under construction |
|
|
|
Mad Dog Phase 2* |
|
Gulf of Mexico |
|
Deepwater |
|
|
| Angola LNG |
|
Angola |
|
LNG |
|
|
|
|
|
Snadd* |
|
North Sea |
|
Conventional |
|
|
| In Amenas compression |
|
North Africa |
|
Conventional |
|
|
|
|
|
Tangguh expansion* |
|
Asia Pacific |
|
LNG |
|
|
| In Salah Southern Fieldsa |
|
North Africa |
|
Conventional |
|
|
|
|
|
Trinidad onshore compression |
|
Trinidad |
|
LNG |
|
|
| Point Thomson |
|
Alaska |
|
Conventional |
|
|
|
|
|
Trinidad offshore compression |
|
Trinidad |
|
LNG |
|
|
| Quad 204* |
|
North Sea |
|
Conventional |
|
|
|
|
|
Vorlich* |
|
North Sea |
|
Conventional |
|
|
| Thunder Horse water injection* |
|
Gulf of Mexico |
|
Deepwater |
|
|
|
|
|
|
|
|
|
|
|
|
| Clair Ridge* |
|
North Sea |
|
Conventional |
|
|
|
|
|
Beyond
2020 |
| Juniper |
|
Trinidad |
|
LNG |
|
|
|
|
|
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. |
| Oman Khazzan* |
|
Middle East |
|
Tight |
|
|
|
|
|
| Persephone |
|
Asia Pacific |
|
LNG |
|
|
|
|
|
| Thunder Horse South expansion* |
|
Gulf of Mexico |
|
Deepwater |
|
|
|
|
|
| West Nile Delta Taurus/Libra* |
|
Egypt |
|
Conventional |
|
|
|
|
|
| Culzean |
|
North Sea |
|
High pressure |
|
|
|
|
|
| Shah Deniz Stage 2* |
|
Azerbaijan |
|
Conventional |
|
|
|
|
|
| Taas-Yuryakh expansion |
|
Russia |
|
Conventional |
|
|
|
|
|
| West Nile Delta Giza/ |
|
Egypt |
|
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
| Fayoum/Raven* |
|
|
|
|
|
|
|
|
|
|
| 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.
|
|
|
|
|
|
|
|
|
Building a pipeline of future growth opportunities. |
|
|
|
|
|
|
|
| « Defined on page 256. |
|
BP Annual Report and Form 20-F 2015 |
|
|
33 |
|
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.
p
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«, with improving returns and growing operating cash flow«. Our five strategic priorities are:
• 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. |
| |
• |
|
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)
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. |
|
|
|
| 34 |
|
BP Annual Report and Form 20-F 2015 |
Financial performance
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
$ million |
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Sale of crude oil through spot and term contracts |
|
|
38,386 |
|
|
|
80,003 |
|
|
|
79,394 |
|
| Marketing, spot and term sales of refined products |
|
|
148,925 |
|
|
|
227,082 |
|
|
|
258,015 |
|
| Other sales and operating revenues |
|
|
13,258 |
|
|
|
16,401 |
|
|
|
13,786 |
|
| Sales and other operating revenuesa |
|
|
200,569 |
|
|
|
323,486 |
|
|
|
351,195 |
|
| RC profit (loss) before interest and taxb |
|
|
|
|
|
|
|
|
|
|
|
|
| Fuels |
|
|
5,858 |
|
|
|
2,830 |
|
|
|
1,518 |
|
| Lubricants |
|
|
1,241 |
|
|
|
1,407 |
|
|
|
1,274 |
|
| Petrochemicals |
|
|
12 |
|
|
|
(499 |
) |
|
|
127 |
|
| |
|
|
7,111 |
|
|
|
3,738 |
|
|
|
2,919 |
|
| Net (favourable) unfavourable impact of non-operating items« and fair value accounting effects« |
|
|
|
|
|
|
|
|
|
|
|
|
| Fuels |
|
|
137 |
|
|
|
389 |
|
|
|
712 |
|
| Lubricants |
|
|
143 |
|
|
|
(136 |
) |
|
|
(2 |
) |
| Petrochemicals |
|
|
154 |
|
|
|
450 |
|
|
|
3 |
|
| |
|
|
434 |
|
|
|
703 |
|
|
|
713 |
|
| Underlying RC profit (loss) before interest and taxb |
|
|
|
|
|
|
|
|
|
|
|
|
| Fuels |
|
|
5,995 |
|
|
|
3,219 |
|
|
|
2,230 |
|
| Lubricants |
|
|
1,384 |
|
|
|
1,271 |
|
|
|
1,272 |
|
| Petrochemicals |
|
|
166 |
|
|
|
(49 |
) |
|
|
130 |
|
| |
|
|
7,545 |
|
|
|
4,441 |
|
|
|
3,632 |
|
| Capital expenditure and acquisitions |
|
|
2,109 |
|
|
|
3,106 |
|
|
|
4,506 |
|
| 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. |
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.
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
$ per barrel |
|
| Region |
|
Crude marker |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| US North West |
|
Alaska North |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Slope |
|
|
24.0 |
|
|
|
16.6 |
|
|
|
15.2 |
|
| US Midwest |
|
West Texas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intermediate |
|
|
19.0 |
|
|
|
17.4 |
|
|
|
21.7 |
|
| Northwest Europe |
|
Brent« |
|
|
14.5 |
|
|
|
12.5 |
|
|
|
12.9 |
|
| Mediterranean |
|
Azeri Light |
|
|
12.7 |
|
|
|
10.6 |
|
|
|
10.5 |
|
| Australia |
|
Brent |
|
|
15.4 |
|
|
|
13.5 |
|
|
|
13.4 |
|
| BP RMM |
|
|
|
|
17.0 |
|
|
|
14.4 |
|
|
|
15.4 |
|
BP refining marker margin ($/bbl)
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.
|
|
|
|
|
|
|
| « Defined on page 256. |
|
BP Annual Report and Form 20-F 2015 |
|
|
35 |
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Refinery throughputsa |
|
|
thousand barrels per day |
|
| USb |
|
|
657 |
|
|
|
642 |
|
|
|
726 |
|
| Europe |
|
|
794 |
|
|
|
782 |
|
|
|
766 |
|
| Rest of worldb |
|
|
254 |
|
|
|
297 |
|
|
|
299 |
|
| Total |
|
|
1,705 |
|
|
|
1,721 |
|
|
|
1,791 |
|
| |
|
|
|
|
|
|
|
|
|
|
% |
|
| Refining availability |
|
|
94.7 |
|
|
|
94.9 |
|
|
|
95.3 |
|
| Sales volumes |
|
|
thousand barrels per day |
|
| Marketing salesc |
|
|
2,835 |
|
|
|
2,872 |
|
|
|
3,084 |
|
| Trading/supply salesd |
|
|
2,770 |
|
|
|
2,448 |
|
|
|
2,485 |
|
| Total refined product sales |
|
|
5,605 |
|
|
|
5,320 |
|
|
|
5,569 |
|
| Crude oile |
|
|
2,098 |
|
|
|
2,360 |
|
|
|
2,142 |
|
| Total |
|
|
7,703 |
|
|
|
7,680 |
|
|
|
7,711 |
|
| 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.
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
| Number of retail sites operated under a BP brand |
|
| Retail sitesf |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| US |
|
|
7,000 |
|
|
|
7,100 |
|
|
|
7,700 |
|
| Europe |
|
|
8,100 |
|
|
|
8,000 |
|
|
|
8,000 |
|
| Rest of world |
|
|
2,100 |
|
|
|
2,100 |
|
|
|
2,100 |
|
| Total |
|
|
17,200 |
|
|
|
17,200 |
|
|
|
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:
|
|
|
| 36 |
|
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). |
| • |
|
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. |
|
BP Annual Report and Form 20-F 2015 |
|
|
37 |
|
Rosneft
Rosneft is the largest oil company in Russia, with a strong portfolio of existing and future opportunities.
p
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. |
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).
|
|
|
| 38 |
|
BP Annual Report and Form 20-F 2015 |
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
$ million |
|
| |
|
|
2015a |
|
|
|
2014 |
|
|
|
2013 |
b |
| Profit before interest and taxc
d |
|
|
1,314 |
|
|
|
2,076 |
|
|
|
2,053 |
|
| Inventory holding (gains) losses« |
|
|
(4 |
) |
|
|
24 |
|
|
|
100 |
|
| RC profit before interest and tax |
|
|
1,310 |
|
|
|
2,100 |
|
|
|
2,153 |
|
| Net charge (credit) for non-operating items« |
|
|
– |
|
|
|
(225 |
) |
|
|
45 |
|
| Underlying RC profit before interest and
tax« |
|
|
1,310 |
|
|
|
1,875 |
|
|
|
2,198 |
|
| Average oil marker prices |
|
|
$ per barrel |
|
| Urals (Northwest Europe – CIF) |
|
|
50.97 |
|
|
|
97.23 |
|
|
|
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. |
| 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.
p
Rosneft’s
operations in West Siberia.
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
$ million |
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Investments in associates«e
(as at 31 December) |
|
|
5,797 |
|
|
|
7,312 |
|
|
|
13,681 |
|
|
|
|
|
| Production and reserves |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
2015a |
|
|
|
2014 |
|
|
|
2013f |
|
| Production (net of royalties)
(BP share)c |
|
|
|
|
|
|
|
|
|
|
|
|
| Liquids« (mb/d) |
|
|
|
|
|
|
|
|
|
|
|
|
| Crude oilg |
|
|
809 |
|
|
|
816 |
|
|
|
643 |
|
| Natural gas liquids |
|
|
4 |
|
|
|
5 |
|
|
|
7 |
|
| Total liquids |
|
|
813 |
|
|
|
821 |
|
|
|
650 |
|
| Natural gas (mmcf/d) |
|
|
1,195 |
|
|
|
1,084 |
|
|
|
617 |
|
| Total hydrocarbons« (mboe/d) |
|
|
1,019 |
|
|
|
1,008 |
|
|
|
756 |
|
| Estimated net proved reservesh
(net of royalties) (BP
share) |
|
|
|
|
|
|
|
|
|
| Liquids (million barrels) |
|
|
|
|
|
|
|
|
|
|
|
|
| Crude oilg |
|
|
4,823 |
|
|
|
4,961 |
|
|
|
4,860 |
|
| Natural gas liquids |
|
|
47 |
|
|
|
47 |
|
|
|
115 |
|
| Total liquidsi |
|
|
4,871 |
|
|
|
5,007 |
|
|
|
4,975 |
|
| Natural gasj (billion cubic feet) |
|
|
11,169 |
|
|
|
9,827 |
|
|
|
9,271 |
|
| Total hydrocarbons (mmboe) |
|
|
6,796 |
|
|
|
6,702 |
|
|
|
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. |
| 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. |
|
|
|
|
|
|
|
| « Defined on page 256. |
|
BP Annual Report and Form 20-F 2015 |
|
|
39 |
|
Other businesses
and corporate
Comprises our renewables business, shipping, treasury and corporate activities including centralized functions.
p
At our Tropical
BioEnergia plant in Brazil we process sugar cane to produce biofuels.
Financial performance
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
$ million |
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Sales and other operating revenuesa |
|
|
2,048 |
|
|
|
1,989 |
|
|
|
1,805 |
|
| RC profit (loss) before interest 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« |
|
|
(1,221 |
) |
|
|
(1,340 |
) |
|
|
(1,898 |
) |
| Capital expenditure and acquisitions |
|
|
340 |
|
|
|
903 |
|
|
|
1,050 |
|
| a |
Includes sales to other segments. |
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)
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.
p
BP shipping reached a
centenary of maritime achievement in April 2015.
Gulf of Mexico oil spill
BP reached agreements resolving the largest remaining liabilities.
p
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.
|
|
|
|
|
|
|
| « Defined on page 256. |
|
BP Annual Report and Form 20-F 2015 |
|
|
41 |
|
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.
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.
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.
Financial update
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:
| • |
|
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.
|
| • |
|
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.
p
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)
Recordable injury
frequency (workforce incidents per 200,000 hours worked)
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
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Recordable injury frequency (group)b |
|
|
0.24 |
|
|
|
0.31 |
|
|
|
0.31 |
|
| Day away from work case
frequencyc
(group)b |
|
|
0.061 |
|
|
|
0.081 |
|
|
|
0.070 |
|
| Severe vehicle accident rated |
|
|
0.112 |
|
|
|
0.132 |
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Tier 1 process safety
events« |
|
|
20 |
|
|
|
28 |
|
|
|
20 |
|
| Tier 2 process safety events |
|
|
83 |
|
|
|
95 |
|
|
|
110 |
|
| Loss of primary containment – number of all incidentse |
|
|
235 |
|
|
|
286 |
|
|
|
261 |
|
| Loss of primary containment – number of oil spillsf |
|
|
146 |
|
|
|
156 |
|
|
|
185 |
|
| Number of oil spills to land and water |
|
|
55 |
|
|
|
63 |
|
|
|
74 |
|
| Volume of oil spilled (thousand litres) |
|
|
432 |
|
|
|
400 |
|
|
|
724 |
|
| Volume of oil unrecovered (thousand litres) |
|
|
142 |
|
|
|
155 |
|
|
|
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
|
|
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|
|
|
|
| « Defined on page 256. |
|
BP Annual Report and Form 20-F 2015 |
|
|
43 |
|
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
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.
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.
Upstream safety
Key safety metrics 2011-2015
Safety performance
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Recordable injury frequency |
|
|
0.21 |
|
|
|
0.23 |
|
|
|
0.32 |
|
| Day away from work case frequency |
|
|
0.034 |
|
|
|
0.051 |
|
|
|
0.068 |
|
| Loss of primary containment 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
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Recordable injury frequency |
|
|
0.26 |
|
|
|
0.34 |
|
|
|
0.25 |
|
| Day away from work case frequency |
|
|
0.092 |
|
|
|
0.121 |
|
|
|
0.063 |
|
| Severe vehicle accident rate |
|
|
0.09 |
|
|
|
0.09 |
|
|
|
0.10 |
|
| Loss of primary containment incidents – number |
|
|
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.
Safety performance
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
2013 |
|
| Recordable injury frequency |
|
|
0.29 |
|
|
|
0.44 |
|
|
|
0.47 |
|
| Day away from work case frequency |
|
|
0.077 |
|
|
|
0.067 |
|
|
|
0.092 |
|
| Severe vehicle accident rate |
|
|
0.35 |
|
|
|
0.48 |
|
|
|
0.41 |
|
| Loss of primary containment incidents – number |
|
|
16 |
|
|
|
17 |
|
|
|
17 |
|
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.
p
The Ocean Victory
drilling rig in the Juniper field, Trinidad.
|
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|
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| « Defined on page 256. |
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BP Annual Report and Form 20-F 2015 |
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Environment and society
Throughout the life cycle of our projects and operations, we aim to manage the environmental and social impacts of our presence.
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 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)
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2015 |
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2014 |
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2013 |
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| Operational controla |
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| Direct emissions |
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51.4 |
c |
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54.1 |
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– |
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| Indirect emissions |
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7.0 |
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7.5 |
d |
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– |
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| BP equity shareb |
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| Direct emissions |
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48.9 |
c |
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48.6 |
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50.3 |
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| Indirect emissions |
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6.9 |
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6.8 |
e |
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6.7 |
f |
| 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.
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BP Annual Report and Form 20-F 2015 |
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.
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« and coalbed methane. We have unconventional gas operations in Oman and the US and we are evaluating
unconventional gas opportunities in other countries.
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.
p
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.
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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:
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Development and delivery of guidance, tools and training courses to increase human rights awareness across the business. |
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Inclusion of human rights clauses in an increasing number of our supplier contracts. |
| • |
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Evaluation of our community grievance mechanisms against the Guiding Principles began at key sites to identify areas for improvement. |
| • |
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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
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.
p
Staff taking part in
BP’s code of conduct training in Brazil.
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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.
p
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
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| Number of employees at 31 Decembera |
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2015 |
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2014 |
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2013 |
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| Upstream |
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21,700 |
|
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|
24,400 |
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|
24,700 |
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| Downstream |
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44,800 |
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48,000 |
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48,000 |
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| Other businesses and corporate |
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13,300 |
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12,100 |
|
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11,200 |
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| Total |
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79,800 |
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|
84,500 |
|
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|
83,900 |
|
| Service station staff |
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|
15,600 |
|
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|
14,400 |
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|
14,100 |
|
| Agricultural, operational and seasonal workers in Brazil |
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|
4,800 |
|
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|
5,300 |
|
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|
4,300 |
|
| Total excluding service station staff and workers in Brazil |
|
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59,400 |
|
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64,800 |
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65,500 |
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| 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.
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BP Annual Report and Form 20-F 2015 |
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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
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| Numbers as at 31 December |
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Male |
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Female |
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Female % |
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| Board directors |
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12 |
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3 |
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20% |
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| Group leaders |
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350 |
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81 |
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19% |
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| Subsidiary directors |
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1,099 |
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179 |
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14% |
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| All employees |
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54,581 |
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25,234 |
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32% |
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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.
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.
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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:
| • |
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Understand the risk environment, and assess the specific risks and potential exposure for BP. |
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Determine how best to deal with these risks to manage overall potential exposure. |
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Manage the identified risks in appropriate ways. |
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Monitor and seek assurance of the effectiveness of the management of these risks and intervene for improvement where necessary. |
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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 –
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’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:
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| Executive committees |
| g Executive team meeting – for strategic and commercial risks.
g Group operations risk committee – for health, safety, security, environment and operations integrity risks.
g Group financial risk committee – for finance, treasury, trading and cyber risks.
g Group disclosure committee – for financial reporting risks.
g Group people committee – for employee risks.
g
Group ethics and compliance committee – for legal and regulatory compliance and ethics risks.
g
Resource commitment meeting – for investment decision risks. |
| Board and its committees |
| g BP board.
g
Audit committee. g Safety, ethics and environment assurance committee.
g Geopolitical committee.
g
Gulf of Mexico committee. |
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Risk governance |
| |
For further information on risk management and internal control, see board and committee reports on page 64.
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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.
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BP Annual Report and Form 20-F 2015 |
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51 |
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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.
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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. |
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.
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For more information on safety and our OMS see page 43. |
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.
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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.
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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. |
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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.
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| 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
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.
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| « Defined on page 256. |
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| 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.
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| 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
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.
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.
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| Board of directors |
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| As at 4 March 2016
See BP’s board governance principles relating to director independence on page 244. |
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Board biographies
See bp.com/governance
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| 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
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Career Bob Dudley became group
chief executive on 1 October 2010. 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
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Career Dr Brian Gilvary was
appointed chief financial officer on 1 January 2012. 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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SEEAC with that of the audit committee, to provide a cohesive and robust overview of business risks.
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. |
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| Admiral Frank Bowman
Independent non-executive director
Tenure Appointed
8 November 2010 |
