BP
Annual Report 2016

Plain-text annual report

Annual Report and Form 20-F 2016 3 The energy we produce serves to power economic growth and lift people out of poverty. In the future, the way heat, light and mobility are delivered will change. We aim to anchor our business in these changing patterns of demand, rather than in the quest for supply. We have a real contribution to make to the world’s ambition of a low carbon future. Contents Strategic report Overview BP at a glance Chairman’s letter Group chief executive’s letter The changing world of energy 2 4 6 8 10 How we run our business Strategy 14 Our strategy 18 Measuring our 2016 progress Performance 20 Challenging global energy markets 21 Group performance 24 Upstream 30 Downstream 35 Rosneft 37 Other businesses and corporate 37 Gulf of Mexico oil spill 38 Alternative energy 40 Sustainability 40 Safety 43 Climate change 44 Value to society 44 Human rights 44 Local environmental impacts 45 Ethical conduct 46 Our people 47 How we manage risk 49 Risk factors Corporate governance Additional disclosures Introduction from the chairman 51 Contents 52 Board of directors 58 Executive team 62 64 Board activity in 2016 68 Shareholder engagement 68 69 Audit committee 74 International advisory board Safety, ethics and environment assurance committee Remuneration committee 76 78 Geopolitical committee 79 Chairman’s committee 79 Nomination committee 80 Directors’ remuneration report and 2017 policy 111 Directors’ statements Financial statements 113 Contents 114 Consolidated financial statements of the BP group 126 Notes on financial statements 187 Supplementary information on oil and natural gas (unaudited) 215 Parent company financial statements of BP p.l.c. 239 Contents Including information on liquidity and capital resources, oil and gas disclosures, upstream regional analysis and legal proceedings. Shareholder information 271 Contents Including information on dividends, our annual general meeting and share prices. 280 Glossary 285 Non-GAAP measures reconciliations 288 Signatures 289 Cross-reference to Form 20-F 290 Information about this report Glossary Words with this symbol in the glossary on page 280. are defined Cautionary statement This document should be read in conjunction with the cautionary statement on page 269. For a secure, affordable and sustainable energy future. BP Annual Report and Form 20-F 2016 1 BP at a glance We are a global energy company with wide reach across the world’s energy system. We have operations in Europe, North and South America, Australasia, Asia and Africa. Scale 74,500 employees 18,000 retail sites 17,810 million barrels of oil equivalent – proved hydrocarbon reservesa 72 countries 6,000+ marine voyages completed by BP-operated and chartered vessels BP in action Some highlights of our activities around the world in 2016. Started up the Point Thomson major project . Increased the number of M&S Simply Food® and REWE® convenience stores in Europe and launched BP fuels with ACTIVE technology. Formed Aker BP, Norway’s largest independent oil and gas producer with Det norske. Signed principles of agreement on future development of the ACG oil field to 2050 in Azerbaijan. Started up two major projects in Algeria. Completed Whiting refinery’s largest turnaround. Entered into a strategic partnership with Fulcrum BioEnergy® – a company that produces sustainable jet fuel from household waste. Started up two major projects and sanctioned Mad Dog phase 2 in the Gulf of Mexico. Sanctioned our onshore compression project in Trinidad. More than doubled our production of ethanol equivalent since 2011 in renewables. Restarted Angola LNG plant. Acquired interests in gas exploration blocks in offshore Mauritania and Senegal with Kosmos Energy. BP and Rosneft separately agreed to buy interests in the Zohr gas field in Egypt from Eni. 2 BP Annual Report and Form 20-F 2016 Performance $115m Data as at or for the year ended 31 December 2016 unless otherwise stated. 3.3 16 profit attributable to BP shareholders (2015 $6.5bn loss) million barrels of oil equivalent per day – hydrocarbon productiona (2015 3.2mmboe/d) tier 1 process safety events (2015 20) $2.6bn underlying replacement cost profit (2015 $5.9bn) 109% group proved reserves replacement ratio a b (2015 61%) a On a combined basis of subsidiaries and equity-accounted entities. b Including the impact of the Abu Dhabi onshore oil concession renewal. i S t r a t e g c r e p o r t – o v e r v i e w Agreed to extend the licence area of the Khazzan gas field in Oman and renewed our interest in Abu Dhabi ADCO onshore oil concession. Completed a deal to conduct exploration in East and West Siberia with Rosneft. Announced two agreements with China National Petroleum Company for shale gas exploration in the Sichuan Basin, and launched Castrol MAGNATEC engine oil with DUALOCK technology in Downstream. Gained approval to develop the Tangguh expansion project, adding a third LNG train . Announced plans for a strategic partnership with Woolworths® to deliver fuel and convenience offers in Australia. More information Group performance Page 21 Upstream Page 24 Downstream Page 30 Rosneft Page 35 Alternative energy Page 38 See Glossary. BP Annual Report and Form 20-F 2016 3 Chairman’s letter We have shown great resilience and character: we returned to profit and maintained our dividend. We had a good year in a tough environment. We have set a new strategic direction for BP – and we have a great team carrying it out. Caption: Members of the board examine BP operations at Baku in Azerbaijan. 4 Dear fellow shareholder, 2016 was a year of change on many fronts. The global community witnessed further challenges raised by economic, political and social forces, and many nations experienced internal stresses and tensions, which remain present. In the energy world, our world, it has been a period of transition. From a 12-year low in oil prices, to digital technologies that are transforming how we work, and the drive to a lower carbon economy, our team has had to manage through a period of uncertainty, complexity and volatility. Against this backdrop, we have shown great resilience and character: we returned to profit and maintained our dividend. We had a good year in a tough environment. We have set a new strategic direction for BP – and we have a great team carrying it out. The record since 2010 BP’s performance in 2016 was based on the foundations rebuilt following the 2010 Deepwater Horizon accident – an event that could have put the very existence of our company at risk. Over the past six years, Bob Dudley and his team have steered the business through the recovery from the crisis of 2010 and then through the response to lower oil and gas prices. During that period, safety has improved significantly. The portfolio has been strengthened. Operating cash flow has remained strong. The dividend has been restored and increased. Investment for growth has continued, while capital and costs have been controlled. The relationships on which we depend have been deepened. And all of this has been done while managing a charge of $63 billion for the 2010 accident, for which the major liabilities have now been clarified and for which we have a plan to manage the remaining payments and residual litigation. All of this sets a firm base for the future, which is bound to have its own challenges. 2016 performance and shareholder distributions In 2016 the team has again focused on the careful stewardship of shareholders’ investments. We continued making progress in safety performance, with serious incidents and injury rates falling. We delivered strong cash flow, disciplined capital spending and lower costs. We met our cost reduction target a year early. New major projects took shape. And we have continued to invest in opportunities for future growth, securing a set of innovative portfolio additions as well as divesting non-strategic assets. This performance enabled us to maintain the dividend at 10 cents per ordinary share through 2016 and the board’s policy remains to grow sustainable free cash flow and distributions to shareholders. Looking ahead We can now look forward and outward, and the board and executive team have set out BP’s strategic priorities for the future. BP Annual Report and Form 20-F 2016Our refreshed strategy is designed to ensure BP is ‘good for all seasons’ in an uncertain environment. It enables us to compete in a world of volatile oil and gas prices, changing customer preferences and of course, the transition to a lower carbon future. As our BP Energy Outlook 2035 predicts, the growth in consumption of oil will gradually slow and likely peak. This is a result of slowing demand growth, not limited supply, as was once thought. In a world of longer-term abundance, oil prices are likely to remain under pressure. Focus will shift to greater efficiency and low-cost production. Gas will grow as a cleaner alternative to coal. Advanced fuels and lubricants will help motorists reduce emissions. Renewable energy will grow rapidly to become commercial at scale. As a global business, we plan to play our part in this energy transition. Our strategy provides BP with greater agility – combining lower cost oil production, increasing gas supply, greater market-led downstream activities, and growing renewables and venturing businesses. We are also proud to be playing a leading role among our peers through the Oil and Gas Climate Initiative, where Bob’s chairmanship has seen an unprecedented convergence of national and international energy companies to act on this issue. Remuneration At the 2016 AGM, we heard a clear message from shareholders on executive pay. During the past year we have sought to address these concerns, recognizing they reflect the concerns of society more broadly. The decisions we have taken, and for which we seek shareholder approval, mark a significant break from past policy. The total pay for executive directors in 2016 is much reduced compared to 2015. The policy we propose for 2017 and beyond is a simpler approach to executive remuneration and reduces the total amount executive directors can earn compared with the previous policy. Executive reward will be driven even more closely than before by the company’s performance and shareholder returns. I particularly want to emphasize that the future remuneration of senior management will be directly linked to the delivery of our new strategic priorities, including BP’s contribution to the longer-term transition in supplying lower carbon energy to drive the global economy. This new approach aims to take account of shareholder concerns on the level of executive pay while recognizing the clear need for a global business like BP to attract and retain the best talent. With those two primary considerations in mind, my fellow board members and I believe the new policy to be appropriate, balanced and responsive to all those we serve as a business. Governance and the board Today’s world presents a range of risks – operational, commercial, geopolitical, environmental and financial. On the board, we aim to maintain the breadth and depth of experience needed to fulfil our critical role of monitoring and managing those risks, working with the executive team. In 2016 Nils Andersen joined us as a non-executive director, bringing considerable insight gained in the See Glossary. energy, shipping and consumer goods industries. He has led major companies, including as chief executive of A.P. Møller-Mærsk A/S and Carlsberg A/S. Cynthia Carroll and Andrew Shilston are standing down as directors at the forthcoming AGM. On behalf of the board I thank them for the substantial contributions they have made to our work both in the board and its committees over the years in some difficult times. The board is proposing that Melody Meyer is elected as a director at the AGM. Melody has had an extensive career in the global oil and gas industry with Chevron and will bring experience of safe and efficient operations and world class projects. We continue to work to increase the diversity of the board as this enhances independent thinking and healthy challenge. Conclusion BP is a global business operating in over 70 countries. To do this effectively over the long term, we need the trust of our shareholders that we will deliver value, but also the trust of the societies where we work – both at home and across the world. I believe this report, along with our Sustainability Report, demonstrates BP’s progress in working for all stakeholders, shareholders, customers, partners, governments, employees and communities. Bob and his team have guided BP from a time of crisis in 2010 to a position where we have sound prospects for greater value creation and growth in the years ahead. Please join me in thanking Bob and his team for their exceptional stewardship of BP. Thank you to the board and to all our employees – and thank you all for your continued support. We are now beginning a new journey. Carl-Henric Svanberg Chairman 6 April 2017 $7.5bn total dividends distributed to BP shareholders 6.0% ordinary shareholders annual dividend yield 6.4% ADS shareholders annual dividend yield Caption: Meeting employees in Brazil. More information Corporate governance Page 51 5 BP Annual Report and Form 20-F 2016Strategic report – overviewGroup chief executive’s letter Since 2010, BP’s story has been one of recovery, rebuilding and resilience. Now we are looking ahead with a spirit of purpose and invention. From 2017, you can expect a story of growth. Caption: The BP Energy Outlook launch at our headquarters in London, UK. 6 Dear fellow shareholder, In 2016 BP started to look forward again. It may have been one of the toughest years we have yet seen in the business environment, with oil prices the lowest since 2004. But it was a year when we turned the challenges into opportunities, finding new ways to compete and grow in a fast-changing industry. Over the last six years, we have been making BP safer, stronger and more resilient. And in 2016 we once again began building for growth and setting a course for a low cost, lower carbon future. Our results Our top priority is always safety and in 2016 we continued the progress made in recent years, with 80% fewer serious incidents and a 40% lower injury rate than in 2011. A good safety record is one sign of disciplined operations. Another sign is reliability – and here too we have seen improvement, with upstream plant reliability of 95% – up from 86% in 2011 – and refining availability of 95.3%, maintaining our strong record in recent years. The good progress that the team made was reflected in the financial results – with a return to headline profit in 2016 compared with a significant headline loss in 2015, which reflected our provisioning for Gulf of Mexico settlements. Our underlying replacement cost profit represents resilient performance given the environment of low oil and gas prices and weak refining margins. Importantly, operating cash flow in 2016 was robust at $17.6 billion, excluding the Gulf of Mexico oil spill payments.a Net cash provided by our operating activities was $10.7 billion after payments for the oil spill of $6.9 billion. The work we have done to reduce capital spending and costs played a large part in these results. More than two years ago we recognized that energy prices could be ‘lower for longer’. Since then, we have been dedicated to changing the way we work, putting in place cost savings and efficiencies that can be sustained. As a result, our 2016 capital spend was significantly lower than peak levels in 2013. Not only did we meet our 2017 target for cash cost reduction – we did so a year ahead of schedule. Capital discipline is not only about reducing spending, but ensuring that the money we continue to invest is spent well. One example in 2016 was the sanction of the second phase of our Mad Dog operation in the US Gulf of Mexico at a budget of $9 billion – less than half the original estimate. This helps make this project highly competitive – even in a lower oil price environment. I am pleased to report that the major liabilities from the Deepwater Horizon accident have been resolved – with most of the outstanding governmental and commercial claims clarified. Cash payments were around $7 billion in 2016 which we expect to fall to $4.5-5.5 billion in 2017, $2 billion in 2018 and a little over $1 billion per year thereafter. Our disciplined financial framework can accommodate these outflows and, with this resolution, our management team can focus with greater confidence on the future. a This sentence does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016Our portfolio We started the year with a goal to increase production from new projects by 800,000 barrels a day by 2020. During 2016 we remained on track for that goal, and we have increased our ambition to over a million barrels a day by 2021. Given the competitive environment, this goal goes hand in hand with a disciplined focus on costs. In the Upstream, we launched six major project start-ups, from Algeria to the Gulf of Mexico, and made final investment decisions on a further five. We are maintaining that momentum in 2017 with more significant start-ups scheduled – including the Quad 204 development in the UK, the giant Khazzan field in Oman and the West Nile Delta project in Egypt. These projects bring us significant reserves, flowing supplies and lower our per unit cost structure. They reposition our portfolio for the future. The Downstream has continued to improve performance and grow with earnings up more than 25% compared with 2014, despite lower industry refining margins. We have enhanced our retail offer to customers – rolling out our new fuels with ACTIVE technology in 13 countries and building great retail partnerships such as with M&S in the UK, REWE in Germany and, subject to regulatory approvals, Woolworths in Australia. Plus, our partnership with Fulcrum BioEnergy should help bring low carbon jet fuel to the market at scale. We have announced a number of strategic additions to our portfolio. We broadened our positions in world- class gas fields: in the West African basin through an agreement with Kosmos Energy; in Egypt’s Zohr field, thought to be the largest discovered in the Mediterranean; and in Oman’s Khazzan development, a giant project that has now become even bigger. These underline our focus on gas, the fastest growing hydrocarbon fuel with the lowest carbon content. We have also been innovative in terms of business models. In Abu Dhabi, we concluded an agreement to renew an onshore oil concession, stretching to 2050, in exchange for a 2% stake in BP. We have operated there for 75 years and this transaction underscores the value of long-term relationships. In Norway, we combined Det norske’s nimble business practices, Aker’s industrial experience and our global scale expertise to form Aker BP – the country’s largest independent oil company. This gives us access to substantive offshore oil and gas resources as well as dividends for shareholders. Putting all these initiatives together, we are creating a substantial core of long-term, cost-efficient major projects that can deliver material operating cash flow and earnings for decades to come. See Glossary. Our future This was also a year when we set out our strategic priorities for the longer term. They are rooted in society’s need to use more energy – bringing heat, light and mobility to millions of people – while positioning BP for a lower carbon world. These priorities will help us drive progress and respond with agility to external changes – whether in supply and demand, oil and gas prices, in environmental policy or in technology. Competitive upstream portfolio: we will expand the gas portfolio alongside lower cost oil production, managing these cost-effectively. Market-led Downstream: we will provide a range of fuels and lubricants that help make vehicles more efficient and grow our fuels marketing and lubricants businesses. Low carbon and venturing: we will broaden our renewable energy and low carbon businesses through reinvestment in the current portfolio, build a dynamic venturing arm, and further our work in tackling climate change. Modernizing the whole group: we will be deploying advanced technologies such as robotics and big data analytics to improve and simplify our processes – as well as using our trading expertise to maximize the value from our assets. I am extremely proud of the global BP team. Without the women and men of BP, we would not have been able to preserve and transform the business over the past six years. I am grateful to our partners, host governments, and other stakeholders who have stood by us as we have stabilized BP and built up our resilience. And I say thank you, to you, our shareholders who have afforded us the time and support to take the actions needed to restore BP to a position of strength from which we can grow and prosper in the years ahead. Since 2010, BP’s story has been one of recovery, rebuilding and resilience. Now we are increasingly looking ahead with a spirit of purpose and invention. From 2017, you can expect a story of growth. Bob Dudley Group chief executive 6 April 2017 95.3% 2016 refining availability 95% Upstream BP-operated plant reliability Caption: Speaking with investors at the field trip in Baku, Azerbaijan. More information Business model Page 10 Strategy Page 14 Performance Page 21 7 BP Annual Report and Form 20-F 2016Strategic report – overviewThe changing world of energy The global energy landscape is changing. Traditional centres of demand are being overtaken by fast-growing emerging markets. The energy mix is shifting, driven by technological improvements and environmental concerns. In summary World economy anticipated to almost double in next 20 years. World demand for energy expected to grow by around 30%. Market gradually readjusting, as both supply and demand respond to lower oil prices. Diverse mix of fuels and technologies needed to meet demand and climate change concerns. Lower oil price environment Oil prices have been substantially lower since 2014, primarily due to oversupply. The market is gradually readjusting, as both demand and supply respond to lower prices. However, the high level of oil inventories suggests this adjustment is likely to take some time. In line with our refreshed strategy, we test our investments against a range of oil and gas prices to check their profitability over the long term. We take into account current price levels and our long-term outlook. Importantly, the break-even price of many of our investments is going down as BP and industry suppliers reduce costs to meet market conditions. Energy consumption by region (billion tonnes of oil equivalent) 2035 2015 1995 0 3 6 9 12 15 18 Other OECD China India Other non-OECD European Union US Growing demand for energy Affordable energy is essential for economic prosperity. Energy provides heat and light for homes, fuel for transportation and power for industry. And everyday objects – from plastics to fabrics – are derived from oil. We expect world demand for energy to increase by around 30% between 2015 and 2035 – largely driven by rising incomes in emerging economies. The extent of this increase is being curbed by gains in energy efficiency, as there is greater attention around the world on using energy more sustainably. Energy mix is shifting New technologies and consumer preferences for low carbon energy are leading to changes in the fuel mix, resulting in a gradual decarbonization. Renewables are the fastest-growing energy source. They are expected to increase at around 7% a year and account for 40% of the growth in power generation over the next two decades. Renewables currently contribute around 3% of total global energy demand, and we estimate that, as a result of rapid improvements in their competitiveness, they will contribute around 10% by 2035. Over the same period, 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. By 2035 we think oil will have around a 29% share, with annual growth slowing down over this period. Meanwhile we believe the share of gas will go up slightly to 25% of global energy, placing it ahead of coal and not far behind oil. BP is gearing up to meet this shifting demand by increasing its gas and renewables activities. Main image: Sherbino wind farm in Pecos County, Texas. Inset image: Service station in Chippenham, UK, selling our latest fuels with ACTIVE technology. 8 BP Annual Report and Form 20-F 2016 Advances in technology Emerging technologies – such as improved batteries, solar conversion, electricity storage and autonomous vehicles – are accelerating the energy transition. For example, the base case scenario in our Energy Outlook suggests that the use of electric vehicles will grow almost one hundred-fold by 2035. That means that about 6% of the cars on the road would be electric, with a reduction in total oil demand of around one million barrels a day. However, a faster mobility revolution – including car sharing, ride pooling, autonomous vehicles and electric cars – could reduce oil demand by several times that amount. Our 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. We prioritize certain new technologies for in-depth analysis – based on their fit with our strategy and how soon and likely we think they are to break through technological and commercial barriers. We also invest in start-up companies to understand and participate in these potentially transformational technologies. See page 12. Emerging greenhouse gas policy and regulation Governments are putting in place taxes, carbon trading schemes and other measures to limit greenhouse gas (GHG) emissions. We expect around two-thirds of BP’s direct emissions will be in countries subject to emissions and carbon policies by 2020. To help anticipate greater regulatory requirements for GHG emissions, we factor a carbon cost into our own investment decisions and engineering designs for large new projects and those for which emissions costs would be a material part of the project. In industrialized countries, this is currently $40 per tonne of carbon dioxide equivalent, and we also stress test at a carbon price of $80 per tonne. Our carbon cost, along with energy efficiency considerations, encourages projects to be set up in a way that will have lower GHG emissions. BP Energy Outlook provides our projections of future energy trends and factors that could affect them out to 2035. See bp.com/energyoutlook See bp.com/technologyoutlook More information Challenging global energy markets Page 20 Our strategy Page 14 See bp.com/sustainability for performance data, case studies and information on our approach to managing our sustainability impacts. Change in CO2 emissions from 2015 32% 12% 13% A changing energy mix Energy consumption – billion tonnes of oil equivalenta 2035 Even faster transition 2035 Faster transition 2035 Base case 2015 Actual energy mix % 6 2 % 8 2 % 9 2 % 2 3 % 3 1 % 5 2 % 3 2 % 2 2 % 4 2 % 3 2 % 9 % 8 % 8 1 % 6 1 % 3 2 % 9 2 % 3 % 7 % 4 % 8 % 7 % 0 1 15 % 7 % 5 18 0 3 6 9 12 Oil Gas Coal Renewables Hydro Nuclear a The sum of the fuel shares may not equal 100% due to rounding. Energy outlook The three scenarios reflect different assumptions about the pace of the energy transition due to factors such as policy and consumer behaviour. Base case This scenario outlines our view of the most likely path for energy to 2035. The growing world economy will require more energy but consumption will increase less quickly than in the past. Faster transition This scenario sees carbon prices in leading economies rise to $100/tonne by 2035 and policy interventions encourage more rapid efficiency gains and fuel switching. Even faster transition This scenario matches the path of the International Energy Agency’s ‘450 scenario’, which aims to limit the global temperature rise to 2ºC. 9 BP Annual Report and Form 20-F 2016Strategic report – overview How we run our business From the deep sea to the desert, from rigs to retail, we deliver energy products and services to people around the world. We provide customers with fuel for transport, 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. Our diverse portfolio is balanced across businesses, resource types and geographies. Having upstream and downstream businesses, along with well-established trading capabilities, helps to mitigate the impact of lower oil and gas prices. Our geographic reach gives us access to growing markets and new resources, as well as diversifying exposure to geopolitical events. Our role in society The energy we produce helps to support economic growth and improve quality of life for millions of people. We strive to be a world-class operator, a responsible corporate citizen and a good employer. We believe that the societies and communities we work in should benefit from our presence. In supplying energy we contribute to economies around the world by employing local staff, helping to develop national and local suppliers, and through the taxes we pay to governments. Additionally, we aim to create meaningful and sustainable impacts in those communities through our social investments. $11.2bn employee wages and benefits $2.2bn taxes paid to governments – comprising income and production taxes $7.5bn total dividends distributed to BP shareholders bp.com/sustainability 10 10 BP Annual Report and Form 20-F 2016 Enabling our business model Safe and reliable operations Talented people We strive to create and maintain a safe operating culture where safety is front and centre. This is not only safer for people and the environment – it also improves the reliability of our assets. We work to attract, motivate, develop and retain the best talent the world offers – our performance and ability to thrive globally depends on it. See Safety on page 40. See People on page 46. Finding oil and gas Developing and extracting oil and gas Creating shareholder value Finding oil and gas New access allows us to renew our portfolio, discover additional resources and replenish our development options. We focus our exploration activities in the areas that are competitive in the portfolio. We develop and use technology to reduce costs and risks. Developing and extracting oil and gas We create value by seeking to progress hydrocarbon resources and turn them into proved reserves, or sell them on if they do not fit with our strategic priorities. We develop and produce the resources that meet our return threshold, which we then sell to the market or distribute to our downstream facilities. Our upstream pipeline of future projects gives us choice about which we pursue – see page 28. We also seek to grow or extend the life of existing fields and are using new business models to increase value. Our US Lower 48 onshore business and Aker BP in Norway (see page 26) are two examples of how we’ve used innovative new business models in response to the competitive environment. Transporting and trading We move oil and gas through pipelines and by ship, truck and rail. We also trade a variety of products including oil, natural gas, liquefied natural gas, power and currencies. Our traders complete around 550,000 transactions and serve more than 12,000 customers across some 140 countries in a year. BP Annual Report and Form 20-F 2016Technology, innovation and venturing Partnerships and collaboration Governance and oversight New technologies are enabling us to produce energy safely and more efficiently. We selectively research and invest in areas with the potential to add greatest value to our business now and in the future. We aim to build enduring relationships with governments, customers, partners, suppliers and communities in the countries where we operate. Our risk management systems and policy provide a consistent and clear framework for managing and reporting risks. The board regularly reviews how we identify, evaluate and manage risks. See Using technology on page 12. See Rosneft on page 35. See How we manage risk on page 47. i i S S t t r r a a t t e e g g c c r r e e p p o o r r t t – – o o v v e r v i e w Transporting and trading Manufacturing Marketing fuels and products Generating renewable energy We use our market intelligence to analyse supply and demand for commodities across our global network. This helps us deliver what the market needs, when it needs it, identify the best markets for BP’s crude oil, source optimal raw materials for our refineries and provide competitive supply for our marketing businesses. Manufacturing and marketing fuels and products We produce refined petroleum products at our refineries and supply distinctive fuel and convenience retail services to consumers. Our advantaged infrastructure, logistics network and key partnerships help us to have differentiated fuels businesses and deliver compelling customer offers. Our lubricants business has premium brands and access to growth markets. It also leverages technology and customer relationships, all of which we believe gives us competitive advantage. We serve automotive, industrial, marine and energy markets across the world. And in petrochemicals our proprietary technology solutions deliver leading cost positions compared to our competitors. In addition to our own petrochemicals plants, we work with partners and license our technology to third parties. one of the world’s most sustainable and advantaged feedstocks to produce both low carbon ethanol and low carbon power. We provide renewable power through our significant interests in onshore wind energy in the US. We develop and deploy technology in our wind business to drive efficiency and capacity. Generating renewable energy More information We have the largest operated renewables business among our oil and gas peers. We operate a biofuels business in Brazil, using Upstream Page 24 Downstream Page 30 Alternative energy Page 38 BP Annual Report and Form 20-F 2016 BP Annual Report and Form 20-F 2016 11 11 Using technology Developments in technology will shape and influence the way we identify, extract, convert, store and ultimately consume energy in the future. Our approach is not about trying to do everything, but to focus on the areas that have the greatest potential value to our business now and in the future. We focus our activities on: • managing safety and operational risk • capturing business value • competitively differentiating BP from others. The right technology is central to the safety and reliability of our operations. This covers everything from assessment and management of technical risk to maximizing our businesses efficiency and performance. It helps us to grow value through innovation, acquisition of competitive new capabilities and application of best practice. In Upstream, this technology investment also supports business strategy by focusing on increased recovery and gaining new access. And in Downstream we develop and apply technology that enhances operational integrity, boosts conversion efficiency or reduces CO2 emissions in some of our operations and provides high-performance products for our customers. We have scientists and technologists at seven major technology centres in the US, UK and Germany. BP and its subsidiaries hold more than 3,800 granted patents and pending patent applications throughout the world. In 2016 we invested $400 million in research and development (2015 $418 million, 2014 $663 million). The reduction was largely due to halting major conversion technology programmes in Downstream and biofuels. Around the world, BP engineers are now using the ‘big data’ Argus platform to make critical decisions about wells, reservoirs and fields with state-of-the-art analytical tools that draw on historical and real-time data points. With these new capabilities, well-sensor data is being made available to engineers and operators within seconds for monitoring, analysis and value optimization. BP is partnering with others to understand and develop solutions for the future including sustainable mobility, carbon management, power and storage, bio-products and digital energy. Internal technology, and research and development Academic institutions Corporate venture capital including partnerships and acquisitions Strategic alliances and joint ventures Licensing Our long-term research is vital to BP’s capacity to adapt and grow. For example, the BP Institute for Multiphase Flow at the University of Cambridge has examined a range of complex and challenging problems associated with the flow of matter for the past 15 years. Our research into rock and fluid interactions has led to significant developments in the use of low salinity water to improve oil recovery from our fields. bp.com/technology 12 BP Annual Report and Form 20-F 2016 Detecting early warning signs When a facility is unexpectedly out of action, production revenues are lost and costs rise from unscheduled maintenance. But ‘plant operations advisor’, a new digital solution we are developing in collaboration with GE Oil & Gas, will help our engineers respond to issues in real time, reducing unplanned downtime and improving the reliability of operational facilities. The system 30% faster Improving seismic technology Seismic data helps us see into reservoir rock and detect where hydrocarbon potential may lie. Achieving high-quality images in difficult terrains is costly and needs many people in the field Keeping today’s engines running People are increasingly choosing to live in cities, so roads have become much busier – meaning repetitive stopping, waiting and starting again. In fact, independent global research shows that drivers spend up to a third of urban journeys idling – and slowly, but permanently, this wears away critical engine parts. That’s why we’ve launched new engine oils containing our latest patented molecules, designed for the needs of today’s engines. Castrol MAGNATEC with ! Piloting in the Gulf of Mexico identifies early warning signs of potential performance problems. It gathers machinery and plant data, analyses it and brings it all to a single screen so that engineers can troubleshoot quickly and resolve potential issues. We are now piloting the system at an offshore operating hub in the Gulf of Mexico. with existing technology. In partnership with Rosneft and Schlumberger’s WesternGeco, we are developing innovative technologies to improve our surveys with faster, better- quality data, captured at a lower cost with less risk. Our project has the potential to expand the industry’s ability to image the subsurface, especially in challenging land environments across the world – and it also offers environmental and safety benefits when working in extreme climates and areas that are difficult to access. Protecting engines for 20 years DUALOCK contains molecules that lock together to form a powerful layer of engine protection. We’ve been helping to protect engines worldwide against warm-up wear for 20 years. Now our unique DUALOCK technology builds on that by reducing both warm-up and stop-start wear by up to 50%. BP Annual Report and Form 20-F 2016 Working smarter We have been reshaping our portfolio for some years, with a focus on achieving operational excellence to grow margins. We seek to get more from our existing assets and capture value from each dollar we spend. We encourage everyone at BP to find and implement smarter ways of working, without compromising safety. From small and simple ideas to large-scale deployment of tools – like Argus, which has optimized monitoring and analysis for 99.5% of our wells (see page 12), our people are helping to make a positive difference to our operations. In the Upstream we also launched a modernization and transformation programme to find ways to improve flexibility, embrace digitization and drive capital and operational performance. This includes a series of online events to allow employees to offer ideas on how we can simplify and improve many of our processes and ways of working. i S t r a t e g c r e p o r t – o v e r v i e w A lot for less Less data, more know-how Each year we buy an annual supply of caustic soda for use at Cherry Point refinery. To help achieve competitive pricing for this product we introduced a fair and transparent reverse auction – where sellers compete to obtain our business. Compared with the standard purchase prices offered to us, the auction generated savings of more than $250,000 for this one commodity in a challenging supply market. We now aim to use reverse auctions more widely in markets where the level of competition lends itself to this approach. Before beginning seismic acquisition in the shallow water area around the Absheron Peninsula in the Azerbaijani Caspian Sea, a subsea hazard identification survey was needed. This process required a lot of data collection for analysis and processing – causing a backlog that was costing time and money. We assessed this and discovered time was being wasted gathering and analysing data, regardless of height from the seabed, when we only needed to identify targets with heights greater than half a metre. By reassessing the survey’s scope with the contractor and establishing a new process to only capture what was needed, we saved around $750,000. Improving competitiveness In the UK we have historically supplied fuels to our retail sites using our own in-house transportation fleet. After a strategic review to continue to improve competitiveness, we transferred all our UK secondary transport activities including scheduling, dispatching and delivery operations to Hoyer – a leading large-scale logistics service provider. This change further strengthens our business by giving us access to a cost-effective and flexible service from a professional international haulier with a reliable safety track record. Getting onboard savings Lightening the load To access a rig in Trinidad, operators used complex scaffolding that took around 11 days to set up. By replacing this with a fixed-structure platform we decreased set up time by nine days and reduced risk of joint failure by removing scaffolding connections. This has made significant savings in rig costs and is already being reused to achieve further savings at other facilities in Trinidad. As part of our review of rental equipment at the PSVM development in Angola, we removed a number of items – like tool boxes, gas racks and welding machines – that were being held on the vessel but not used. This has already delivered equipment savings of $750,000 in 2016 and eliminated man hours required for maintaining and inspecting the equipment. We are now looking for similar opportunities to review excess equipment and inventories elsewhere. BP Annual Report and Form 20-F 2016 BP Annual Report and Form 20-F 2016 13 13 Our strategy Fit for the future Our industry is changing at a pace not seen in decades. All forms of energy – fossil fuels and renewables – are becoming more abundant and less costly. Through new technologies, energy will be produced more efficiently and in new ways, helping to meet the expected rise in demand. And the world is working towards a lower carbon future. We are evolving our strategy – allowing us to be competitive in a time when prices, policy, technology and customer preferences are changing. Our strategic priorities help us to deliver heat, light and mobility solutions for a changing world. How we do this 2016 activities 14 BP Annual Report and Form 20-F 2016 Shift to gas and advantaged oil in the upstream Invest in new large-scale gas projects, pursue quality oil projects in core basins and seek out new opportunities in selected regions. Around 75% of our planned start-ups by 2021 are in gas projects. All of our planned oil start-ups out to 2021 are lower cost or around our existing basins. Maximize recovery, manage decline and extend the life of our existing oil and gas fields. Optimize our portfolio by making investments and divestments to deliver long-term value, with the potential to start increasing earnings or cash flow within a short time frame. We renewed our interest in the Abu Dhabi ADCO onshore concession and signed a letter of intent for the future development of the Azeri-Chirag-Gunashli field – boosting our lower-cost oil production for decades to come. We also made deals to expand our gas exposure in China, Egypt, Indonesia, Mauritania and Senegal, and Oman. Read more in Upstream on page 24. Market-led growth in the downstream Venturing and low carbon across multiple fronts Modernizing the whole group i S t r a t e g c r e p o r t – s t r a t e g y Build competitively advantaged businesses in manufacturing and expand our marketing businesses. Pursue new ventures and partnerships to meet rapidly evolving technology, consumer and policy trends, and develop cross-business solutions to create new opportunities or strengthen our existing relationships. Simplify and modernize so we can continue to compete and seize new opportunities with our partners and stakeholders in a changing world. Strengthen the competitiveness of our refineries and petrochemicals plants. Grow our fuels marketing and lubricants businesses in existing and new markets. Create new fuels, lubricants and petrochemicals offers to meet the evolving needs of our customers and partners. Develop and prove new business models through partnerships with vehicle manufacturers and others. We released BP fuels with ACTIVE technology, designed to fight engine dirt and protect against it building up. Now sold in 13 countries, this was our largest fuel launch in a decade. BP announced a strategic partnership with one of Australia’s largest supermarket retailers Woolworths to acquire, rebrand and operate their fuel and convenience sitesa. Optimize and grow our renewables activities. Partner with start-ups to broaden our options and use our ability to bring successful technologies to fruition on a large scale. Help customers offset their personal and business emissions through renewables generation or carbon trading. Deepen our understanding of future energy, technology and climate change trends through collaboration with academic and research institutions. We established a presence in China’s fast developing emissions trading market, striking the largest deal yet. And we are partnering with Fulcrum BioEnergy – a company that produces lower carbon jet fuel from household waste – to help them bring biojet to the market at scale. Simplify our organizational structures and processes. Introduce digital solutions to enhance our productivity and services for our customers. Maximize value from our assets through our oil, gas, power and renewables trading activities. Transform how it feels to work for BP – motivating our people to perform at their best. Strive for ways to continue improving the safety and reliability of our operations. We are using cloud-based platforms for rapid analysis and decision making with state-of-the-art visualization and predictive tools. We are introducing digital apps in our retail and aviation businesses that can improve customer service and convenience. Our new fleet of underwater robots are improving how we monitor the ocean environment and assess risks. And we have expanded our global business services organization, with plans to open our 10th BP centre in late 2017. Read more in Downstream on page 30. a Subject to regulatory approval. Read about our activities in Using technology on page 12 and Alternative energy on page 38. Read more in Group performance on page 21. BP Annual Report and Form 20-F 2016 15 The foundations for strong performance Safe and reliable operations, a balanced portfolio and a focus on returns provide the platform for growth which is critical to the successful delivery of our strategy. These build on our group business model: having the right people, partnerships, processes and technology in place to deliver value across all our activities. Safe, reliable and efficient execution Operational excellence is essential to our success. Good safety leads to reliable operation of our assets, greater efficiency and ultimately better financial results. Our operating management system promotes continuous improvement and systematic ways of working. And, we are using technology to produce energy more safely and efficiently. Operating reliability and availability 100% 94.8% 95% 93% 92% 88% 2012 95% Refining availability Upstream operated plant reliability 2016 Distinctive portfolio with optionality We benefit from having upstream, downstream and alternative energy businesses – challenges in one part of the group can create opportunities in another. Around the world, we are investing in upstream projects – expected to deliver operating cash marginsa 35% better than 2015 levels. We are driving sustainable competitiveness in our downstream business, with a focus on customers, cost efficiency and margin capture. Our well-established oil and gas trading function can generate value by providing the link between our businesses and third parties. And our equity interest in Rosneft gives us access to one of the largest and lowest-cost hydrocarbon resource bases in the world. a Based on 2015 oil prices. Disciplined growth 16 start-ups under construction 1 million + production of additional barrels of oil equivalent per day expected by 2021 Personal and process safety performance 2016 2021 100% 0 2012 16 BP Annual Report and Form 20-F 2016 Marketing and customer focus Retail convenience partnerships • Castrol EDGE • Castrol GTX • Castrol MAGNATEC • M&S Simply Food® • REWE to go® • Pick n Pay® Lubricants Fuels • BP • Arco • Aral • Air BP Down 40% Down 49% Process safety events Recordable injury frequency 2016 More than 50% of downstream profits are from marketing activities. i S t r a t e g c r e p o r t – s t r a t e g y Focused on delivering competitive returns In 2014 we set out our financial framework in response to the sharp decline in the oil price. The framework underpins our commitment to sustain the dividend for our shareholders. We have been meeting those expectations each year – and even reaching our cash cost reduction target a year early. We also reduced our upstream and downstream headcount by a total of 6,000 in 2016 – a reduction of 17% since 2014. We have now updated and extended the framework out to 2021. We expect our strong balance sheet to be able to deal with any near-term volatility. Beyond that, we aim to increase operating cash flow – from our planned upstream start-ups and growth in the downstream. With a constant capital frame we intend to grow sustainable free cash flow and distributions to shareholders in the long term. Principle Optimize capital expenditure Our financial framework underpins our commitment to sustain the dividend for our shareholders. Make selective divestments Payments related to the Gulf of Mexico oil spill Maintain flexibility around gearing 2016 organic capital expenditure was $16 billion* – after excluding the consideration for the renewal of 10% of the Abu Dhabi ADCO onshore oil concession. This was well below our original guidance of $17-19 billion. $3.2 billiona achieved in 2016. This was within the expected guidance of $3-5 billion for the year. 2016 payments totalled $6.9 billion, reflecting faster resolution of outstanding claims. Gearing at the end of 2016 was 26.8%**. This was within our target range of 20-30%. Looking ahead – 2018 to 2021 We expect organic capital expenditure of $15-17 billion. We expect organic capital expenditure of $15-17 billion per year. We expect divestments of $4.5-5.5 billion. $2-3 billion of divestments as a result of active portfolio management. We expect $4.5-5.5 billion of cash payments. Around $2 billion in 2018 and moving to annual payments of just over $1 billion from 2019 onwards. Within the 20-30% band. Within the 20-30% band. Group ROACE ROACE was 2.8%*** in 2016. – We are aiming to exceed 10% by 2021 at real oil prices around $55/barrel. a Includes $0.6 billion for the sale of 20% from our shareholding in Castrol India Limited. Balancing our sources and uses of cash We aim for our operating cash flow (excluding payments related to the Gulf of Mexico oil spill) to cover our dividend payments and organic capital expenditure . Nearest GAAP equivalent measures * Additions to non-current assets: $21 billion. ** Ratio of gross debt to gross debt plus equity: 37.6%. *** Numerator: Profit attributable to BP shareholders $115 million; Denominator: Average capital employed $153 billion. See Glossary. BP Annual Report and Form 20-F 2016 17 2016 achievement2017 guidance3030201525105201525105SourcesSourcesUses2016Capital investment – investing activitiesDividends paidOperating cash flow – Gulf of Mexico oil spillUsesSources2015UsesOperating cash flow – rest of groupDisposal proceeds – investing activities For the year ended 31 December ($ billion) Measuring our 2016 progress Underlying replacement cost profit ($ billion) 2016 REM Operating cash flow ($ billion) 2016 REM 2016 2015 2014 2013 2012 (6.5) 0.1 2.6 5.9 3.8 12.1 13.4 11.0 23.5 -10 -5 0 5 10 15 17.1 20 25 Profit (loss) for the year Underlying RC profit for the year 2016 2015 2014 2013 2012 10.7 17.6 20.3 19.1 32.8 32.8 21.2 21.1 22.9 20.5 5 10 15 20 25 30 35 40 Operating cash flow excluding amounts related to the Gulf of Mexico oil spilla Operating cash flow is a useful measure for investors because Underlying RC profit 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. 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. 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 . 2016 performance Profit for the year reflected lower charges for the Gulf of Mexico oil spill than 2015. The reduction in underlying RC profit compared with 2015 was mainly due to lower oil and gas prices and the weaker refining environment, see pages 24 and 30. 2016 performance Operating cash flow of $10.7 billion was lower, mainly due to higher Gulf of Mexico oil spill payments which amounted to $6.9 billion in 2016. Operating cash flow was also impacted by lower realizations, partly offset by lower costs and working capital effects. a These bars on the chart do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. Major project delivery 2016 REM Production (mboe/d) 2016 2015 2014 2013 2012 4 4 4 5 2 6 7 2016 2015 2014 2013 2012 3,141 3,268 3,239 3,230 3,331 6 8 3,100 3,200 3,300 3,400 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. 2016 performance We started up two major projects in Algeria, two in the Gulf of Mexico, and one each in Alaska and Angola. 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. A minor adjustment has been made to 2015 and 2014, see page 25 for further information. 2016 performance BP’s total reported production including Upstream and Rosneft segments was slightly higher than in 2015. Tier 1 process safety eventsb 2016 REM Loss of primary containmentb 2016 REM 2016 2015 2014 2013 2012 16 20 20 20 28 43 40 2016 2015 2014 2013 2012 233 275 208 235 246 286 261 292 300 400 60 100 200 We report tier 1 process safety events which are losses of primary containment of greatest consequence – causing harm to a member of the workforce, costly damage to equipment or exceeding defined quantities. 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. 2016 performance The number of tier 1 process safety events has decreased since 2012. 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. 2016 performance We saw an increase of LOPCs in 2016, partly due to harsher winter operating conditions in our unconventional gas operations in the US. Figures for 2014 to 2016 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 previous years’ reporting, our LOPC figure is 233 (2015 208, 2014 246). We assess our performance across a wide range of measures and indicators. Our key performance indicators (KPIs) help the board and executive management assess performance against our strategic priorities and business plans. 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 used for executive remuneration. Overall annual bonuses and performance shares for 2016 are all based on performance against measures and targets linked directly to the strategy and KPIs. Changes to KPIs We have updated some of our KPIs this year to better align to our evolved strategy and future remuneration policy. • We’ve added return on average capital employed and upstream unit production costs as these will be important measures for assessing future performance and pay outcomes. • We’re showing replacement cost profit at group level rather than on a per-share basis as this aligns with the measure used for executive remuneration. • We’ve removed gearing, or net debt ratio, as a group KPI but will continue to report it in Group performance. Looking ahead The KPIs associated with our 2017-2019 remuneration policy can be found on page 104. We’ll disclose our performance against these in our 2017 report. 2016 REM KPIs used to determine 2016 remuneration. More information Directors’ remuneration Page 80 18 BP Annual Report and Form 20-F 2016 Total shareholder return (%) Return on average capital employed (%) 2016 REM (12.8) (8.3) (16.5) (11.6) 2016 2015 2014 2013 2012 14.7 14.0 4.5 2.6 29.0 55.5 2016 2015 2014 2013 2012 2.8 5.5 9.6 10.2 5 10 13.4 15 Reserves replacement ratio (%) 2016 REM 2016 2015 2014 2013 2012 109 61 63 60 77 80 100 120 140 129 -20 0 20 40 60 ADS basis Ordinary share basis 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. 2016 performance Increased TSR reflects share price growth in 2016, as well as maintaining the dividend per share. Return on average capital employed (ROACE) gives an indication of a company’s capital efficiency, dividing the underlying RC profit after adding back net interest by average capital employed, excluding cash and goodwill. See page 285 for more information including the nearest GAAP equivalent data. For the past few years, ROACE has been lower in the oil and gas sector, due to the impact of lower oil prices on earnings and the capital overhang of investments made during the preceding period of $100 per barrel oil prices. 2016 performance The 2016 reduction in ROACE is mainly due to weaker oil and gas prices and refining margins, partly offset by lower costs. Proved reserves replacement ratio is the extent to which the year’s production has been replaced by proved reserves added to our reserve base. The ratio is expressed in oil-equivalent terms and includes changes resulting from discoveries, improved recovery and extensions and revisions to previous estimates, but excludes changes resulting from acquisitions and disposals. The ratio reflects both subsidiaries and equity-accounted entities. This measure helps to demonstrate our success in accessing, exploring and extracting resources. 2016 performance This year’s reserves replacement ratio was higher than our five-year average primarily as a result of the Abu Dhabi onshore concession renewal. See page 244 for more information. Upstream unit production costs ($/boe) Refining availability (%) Reported recordable injury frequencyb 2016 2015 2014 2013 2012 8.5 10.5 12.8 13.2 12.5 2016 2015 2014 2013 2012 95.3 94.7 94.9 95.3 94.8 2016 REM 2016 2015 2014 2013 2012 0.21 0.24 4 8 12 16 90 92 94 96 98 0.2 0.31 0.31 0.35 0.4 0.6 The upstream unit production cost indicator shows how supply chain, headcount and scope optimization impact cost efficiency. 2016 performance The lower unit production costs in 2016 reflect increased efficiency, reduced headcount, as well as deflation. This continues the cost reduction trend, down by over 35% since 2013. Greenhouse gas emissions (million tonnes of CO2 equivalent) 2016 2015 2014 2013 2012 50.1 49.0 48.7 50.3 20 20 40 40 59.8 60 80 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 for the relevant periods. Minor adjustments have been made to the 2014 and 2015 figures. See page 43. 2016 performance The increase in our reported emissions is primarily due to operational variations such as returning to normal operations after planned shutdowns and start-up activities in Canada and Angola. 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. 2016 performance Refining availability increased by 0.6% from 2015 to 95.3%, reflecting strong operational performance across our portfolio. This performance is underpinned by our global reliability improvement programme which provides our refineries with a more structured and systematic approach to improving availability. Reported recordable injury frequency (RIF) measures the number of reported work-related employee and contractor incidents that result in a fatality or injury per 200,000 hours worked. 2016 performance Our workforce RIF has improved steadily over five years and is also reflected in our other occupational safety metrics. While this is encouraging, continued vigilance is needed. For detail on employee and contractor safety against industry benchmarks, see page 40. b 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. Group priorities indexc (%) Diversity and inclusionc (%) 2016 2015 2014 2013 2012 72 69 72 72 71 20 40 60 80 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 and how it is managed in terms of leadership and standards. 2016 performance Our group priorities engagement measure increased in 2016. Confidence in the future of BP also rose to 64% (2015 58%, 2014 63%). c Relates to BP employees. 2016 2015 2014 2013 2012 5 10 15 Women Non UK/US 26 22 23 22 22 25 30 19 18 18 17 20 20 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. 2016 performance The percentage of our group leaders who are women or non-UK/US rose. We remain committed to our aim that women will represent at least 25% of our group leaders by 2020. See Glossary. 19 BP Annual Report and Form 20-F 2016Strategic report – strategyChallenging global energy markets Oil prices have been substantially lower since 2014. The market is gradually readjusting, as both demand and supply respond to lower prices. However, the high level of oil inventories suggests this adjustment is likely to take some time. Brent dated average crude oil prices ($/barrel) 2014 The world economy remained weak in 2016, with global GDP growth at 2.3%. This was significantly lower than the average of nearly 3% over the past 20 years. Economic growth in the OECD slowed to 1.7%, (2.3% 2015) – partly due to weak global trade and lower business investment in the US. In contrast, the non-OECD economy grew by 3.4% (3.3% 2015). This follows six years of declining growth and is partly driven by relative stability in China and improvements in Russia and Brazil. $98.95 Oil Crude oil prices ($/bbl – quarterly average) 150 120 90 60 07 08 09 10 11 12 13 14 15 2016 Brent dated Prices Dated Brent crude oil prices averaged $43.73 per barrel in 2016 – a further drop from the 2015 average of $52.39. But prices recovered over the year, rising from around $30 per barrel in January to nearly $54 in December. Consumption Global consumption increased by 1.6 million barrels per day (mmb/d) to 96.6mmb/d for the year (1.7%) – mostly due to continued low oil prices.a Demand grew most rapidly in Asia’s emerging economies, but OECD demand also increased for the second consecutive year. Production Strong consumption growth outpaced growth in global production. Non-OPEC production fell by 0.8mmb/d – the largest drop since 1992 – driven by the collapse of drilling in the US and a sharp decline in Chinese investment. However, OPEC production grew by 1.2mmb/d, reaching a record level of 39.3mmb/d, due to the recovery of Iranian production and large increases in Saudi Arabia and Iraq. Inventories Oil inventories remained high. And although data on global inventories is not available, OECD commercial inventories, as at 31 December, remained 290 million barrels above the five-year average, even though they had begun to reduce. 2015 $52.39 2016 $43.73 More information Prices and margins Pages 25 and 32 20 Natural gas Natural gas prices ($/mmBtu – quarterly average) 12 10 8 6 4 2 07 Henry Hub 08 09 10 11 12 13 14 15 2016 Prices Gas prices were low in all key markets in 2016 as markets continued to adjust to the oversupply that built up during 2015, with increasing trade ensuring that the effect of ample supplies was felt globally. Gas prices in the US averaged $2.46 per million British thermal units (mmBtu), slightly lower than 2015 ($2.67). The Japanese spot price fell to an average of $5.7/mmBtu in 2016 (2015 $7.4) with rising supplies in the region outpacing growth in demand, including new and emerging markets. The UK National Balancing Point hub price was 34.63 pence per therm, 19% lower than in 2015 (42.61), as higher demand was easily met by rising pipeline imports, especially from Russia. Broad differentials between regional gas prices also remained low, as US gas prices moved closer to Asian and European spot prices. Consumptionb Global consumption grew significantly faster than in 2015. The pattern of growth across markets shifted, with strong demand growth in the OECD and China offsetting weakness in other markets. Gas consumption in the power sector continued to grow globally, gaining share from coal helped by the local production curbs in China. And with coal production curbs in China taking hold, the market tightened in 2016. In addition, higher weather-related demand towards the end of the year boosted the total annual demand. Productionb Total production in 2016 was similar to 2015, with strong growth in Australia and Russia making up for declining production in Europe where existing fields are maturing and not being replaced. Global LNG supply capacity expanded strongly in 2016, following a small increase in 2015. a From IEA Oil Market Report, February 2017 ©, OECD/IEA 2017. b Based on BP estimates from the BP Energy Outlook. BP Annual Report and Form 20-F 2016 Group performance BP made good financial progress in 2016, supported by the significant and rapid changes we have made to our cost base. We reached our target of reducing controllable cash costs by $7 billion a year ahead of plan. i S t r a t e g c r e p o r t – p e r f o r m a n c e Dr Brian Gilvary Group chief financial officer In summary $2.6bn $7bn underlying replacement cost profit (2015 $5.9bn) cash cost reduction versus 2014 – the costs which we consider to be controllable $115m profit attributable to BP shareholders (2015 $6.5bn loss) $69m reduction in total costsa versus 2014 – reflects an increase in Gulf of Mexico oil spill charges of $5.9bn, and a reduction of $6.0bn in other costs, some of which are not considered controllable Segment RC profit (loss) before interest and tax ($ billion) 2016 2015 2014 (20) (15) (10) (5) 0 5 10 15 20 Rosneft Downstream Upstream Other businesses and corporate – other Other businesses and corporate – Gulf of Mexico oil spill Consolidation adjustment – UPII Group RC profit (loss) before interest and tax $ million except per share amounts 2014 6,412 2015 (7,918) (1,653) 3,171 (82) (6,482) 1,889 (569) (5,162) 15,328 (4,056) (261) 56 5,905 40.0 26.383 20,080 18,748 710 19,458 (1,462) (947) (223) 3,780 6,210 (1,917) 8,073 9,132 (4,512) (898) 341 12,136 39.0 23.850 26,492 22,892 601 23,493 2016 (430) (1,865) 2,467 (57) 115 (1,597) 483 (999) 5,661 (2,833) 1,085 (329) 2,585 40.0 29.418 21,204 18,440 939 19,379 Financial and operating performance Profit (loss) before interest and taxation Finance costs and net finance expense relating to pensions and other post-retirement benefits Taxation Non-controlling interests Profit (loss) for the yearb Inventory holding (gains) losses , before tax Taxation charge (credit) on inventory holding gains and losses Replacement cost profit (loss) Net charge (credit) for non-operating items , before tax Taxation charge (credit) on non-operating items Net (favourable) unfavourable impact of fair value accounting effects , before tax Taxation charge (credit) on fair value accounting effects Underlying replacement cost profit Dividends paid per share – cents – pence Additions to non-current assetsc Capital expenditure on an accruals basis d e Organic capital expenditure f Inorganic capital expenditure Main image: A pipe rack on board the Discoverer Luanda drill ship, off the coast of Angola. More information Upstream Page 24 Downstream Page 30 Rosneft Page 35 Other businesses and corporate Page 37 Oil and gas disclosures for the group Page 251 See Glossary. a Production and manufacturing expenses and distribution and administration expenses from the income statement. b Profit (loss) attributable to BP shareholders. c Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates. d A reconciliation to GAAP information is provided on page 285. e The definitions of capital expenditure on an accruals basis and inorganic capital expenditure have been revised to exclude asset exchanges as they are non-cash transactions. Previously reported amounts have been amended. Previously reported amounts for organic capital expenditure are unchanged. f 2016 includes amounts relating to the renewal of a 10% interest in the Abu Dhabi onshore oil concession for which new ordinary shares in BP were issued. 21 BP Annual Report and Form 20-F 2016 The profit for the year ended 31 December 2016 was $115 million, compared with a loss of $6.5 billion in 2015. Excluding inventory holding gains, replacement cost (RC) loss was $1.0 billion, compared with a loss of $5.2 billion in 2015. The net charge for non-operating items mainly relates to additional charges for the Gulf of Mexico oil spill which are partially offset by net impairment reversals. There were net unfavourable fair value accounting effects. After adjusting for non-operating items and fair value accounting effects, underlying RC profit for the year ended 31 December 2016 was $2.6 billion, a decrease of $3.3 billion compared with 2015. The reduction was predominantly due to lower results in both the Upstream and Downstream segments reflecting lower oil and gas prices and the weaker refining environment (see pages 24 and 30). Non-operating items in 2016 also include a restructuring charge of $0.8 billion (2015 $1.1 billion), cumulative restructuring charges from the beginning of the fourth quarter 2014 totalled $2.3 billion by the end of 2016. Non-operating restructuring charges are expected to continue into 2017. The loss for the year ended 31 December 2015 was $6.5 billion, compared with a profit of $3.8 billion in 2014. Excluding inventory holding losses, 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. More information on non-operating items and fair value accounting effects can be found on page 285. See Other businesses and corporate on page 37 and Financial statements – Note 2 for further information on the impact of the Gulf of Mexico oil spill on BP’s financial results. Taxation The credit for corporate income taxes in 2016 and 2015 reflects the deferred tax impact of the increased provisions in respect of the Gulf of Mexico oil spill. The effective tax rate (ETR) on the loss for the year was 107% in 2016 and 33% in 2015; the ETR on the profit for the year in 2014 was 19%. The ETR in 2016 and 2015 was impacted by various one-off items. Adjusting for inventory holding impacts, non-operating items, fair value accounting effects and the deferred tax adjustments as a result of the reductions in the UK North Sea supplementary charge in 2016 and 2015, the adjusted ETR on RC profit was 23% in 2016 (2015 31%, 2014 36%). The adjusted ETR for 2016 is lower than 2015 predominantly due to changes in the geographical mix of profits as a result of the lower oil price and the absence of foreign exchange impacts from the strengthening of the US dollar in 2015. The adjusted ETR for 2015 was lower than 2014 mainly due to changes in the geographical mix of profits. In the current environment, and reflecting the recent transaction to renew a 10% interest in the Abu Dhabi onshore oil concession, the adjusted ETR in 2017 is expected to be in the region of 40%. Cash flow and net debt information Operating cash flow excluding amounts related to the Gulf of Mexico oil spill a Operating cash flow Net cash used in investing activities Net cash provided by (used in) 2016 2015 $ million 2014 17,583 10,691 (14,753) 20,263 19,133 (17,300) 32,763 32,754 (19,574) financing activities 1,977 (4,535) (5,266) Cash and cash equivalents at end of year Gross debt Net debt Gross debt to gross debt plus equity Net debt to net 23,484 58,300 35,513 37.6% 29,763 26,389 52,854 53,168 27,158 22,646 35.1% 31.9% debt plus equity 26.8% 21.6% 16.7% a This does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. Operating cash flow Net cash provided by operating activities for the year ended 31 December 2016 was $8.4 billion lower than 2015. Of this amount, $6.0 billion was a result of higher pre-tax cash outflows associated with the Gulf of Mexico oil spill ($7.1 billion in 2016 compared with $1.1 billion in 2015). Cash flows were impacted by the continuing low oil price environment, with a lower average oil price in 2016 compared with 2015, working capital effects, and a reduction of $0.7 billion in income taxes paid. Movements in inventories and other current and non-current assets and liabilities adversely impacted cash flow in the year by $3.2 billion. There was an adverse impact from the Gulf of Mexico oil spill of $4.8 billion. Other working capital effects, arising from a variety of different factors, had a favourable impact of $1.6 billion. The group actively manages its working capital balances to optimize cash flow, particularly in the current lower oil price environment. Inventories increased during the year because volumes were increased in our trading business to benefit from market opportunities, and due to higher prices towards the end of the year. The increase in inventory was largely offset by a corresponding increase in payables, limiting the increase in working capital. There was a decrease in net cash provided by operating activities of $13.6 billion in 2015 compared with 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. Net cash used in investing activities Net cash used in investing activities for the year ended 31 December 2016 decreased by $2.5 billion compared with 2015. The decrease mainly reflected a reduction in cash outflow in respect of capital expenditure, including investment in joint ventures and associates , of $2.8 billion. The decrease of $2.3 billion in 2015 compared with 2014 reflected a reduction in cash outflow in respect of capital expenditure of $3.9 billion, partly offset by a reduction of $0.7 billion in disposal proceeds. The reductions in cash capital expenditure in both years reflect the group’s response to the lower oil price environment. There were no significant cash flows in respect of acquisitions in 2016, 2015 and 2014. The group has had significant levels of capital investment for many years. Cash flow in respect of capital investment, excluding acquisitions, was $17.5 billion in 2016 (2015 $20.2 billion and 2014 $23.1 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. 22 BP Annual Report and Form 20-F 2016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), and an increase in the total dividend paid in cash of $0.8 billion – see below for further information. Total dividends distributed to shareholders in 2016 were 40 cents per share, the same as 2015 on a US dollar basis and up 11.5% in sterling terms. This amounted to a total distribution to shareholders of $7.5 billion (2015 $7.3 billion, 2014 $7.2 billion), of which shareholders elected to receive $2.9 billion (2015 $0.6 billion, 2014 $1.3 billion) in shares under the scrip dividend programme. The total amount distributed in cash amounted to $4.6 billion during the year (2015 $6.7 billion, 2014 $5.9 billion). Net debt Gross debt at the end of 2016 increased by $5.1 billion from the end of 2015. The gross debt ratio at the end of 2016 increased by 2.5%. Net debt at the end of 2016 increased by $8.4 billion from the 2015 year-end position. The net debt ratio at the end of 2016 increased by 5.2%. We continue to target a net debt ratio in the range of 20-30%. 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. The total cash and cash equivalents at the end of 2016 were $2.9 billion lower than 2015. For information on financing the group’s activities, see Financial statements – Note 28 and Liquidity and capital resources on page 242. Group reserves and production (including Rosneft segment) 2016 2015 2014 Estimated net proved reservesa (net of royalties) Liquids (mmb) Natural gas (bcf) Total hydrocarbons (mmboe) Of which: Equity-accounted entitiesb Productiona (net of royalties) Liquids (mb/d)c Natural gas (mmcf/d) Total hydrocarbonsc (mboe/d) Of which: Subsidiaries c Equity-accounted entitiesd 10,333 43,368 17,810 9,560 44,197 17,180 9,817 44,695 17,523 8,679 7,928 7,828 2,048 7,075 3,268 1,939 2,007 7,146 3,239 1,969 1,917 7,100 3,141 1,889 1,329 1,270 1,253 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 35 and Supplementary information on oil and natural gas on page 187 for further information. c A minor adjustment has been made to comparative periods, see page 25 for further information. d Includes BP’s share of Rosneft. See Rosneft on page 35 and Oil and gas disclosures for the group on page 251 for further information. Total hydrocarbon proved reserves at 31 December 2016, on an oil-equivalent basis including equity-accounted entities, increased by 4% compared with 31 December 2015. The change includes a net increase from acquisitions and disposals of 520mmboe (decrease of 128mmboe within our subsidiaries, increase of 648mmboe within our equity- accounted entities). Acquisition activity in our subsidiaries occurred in Abu Dhabi (increase of interest in ADCO concession from 9.5% to 10%) Indonesia, the US and the UK, and divestment activity in our subsidiaries occurred in Norway, Indonesia, Australia, Trinidad and the US. In our equity-accounted entities the most significant items were purchases in Russia, Norway and Venezuela. Our total hydrocarbon production for the group was 0.9% higher compared with 2015. The increase comprised a 1.5% decrease (0.3% increase for liquids and 3.5% decrease for gas) for subsidiaries and a 4.7% increase (3.9% increase for liquids and 7.4% increase for gas) for equity-accounted entities. Driving efficiency We are simplifying and modernizing the way we work in BP to perform more efficiently in the current industry environment, and to support strong performance and growth into the long term. We now deliver many of the group’s business support activities – financial reporting, supplier payment, customer order and cash collection – from our global business services (GBS) organization. GBS develops standard processes and procedures and uses insight from data analytics, innovation and technology, to find ways to improve the way we do business. This allows us to drive efficiencies across BP, as well as offering significant economies of scale. The service offer has recently expanded to include human resources, tax, internal control and procurement activities, and we expect further growth in both existing operations and new areas. GBS has a network of nine centres, five run by BP, the others by Accenture, with about 5,500 staff around the world. We plan to open a new BP location in Szeged, Hungary in late 2017. Through operating and sourcing processes more efficiently, GBS is delivering significant value to BP. We expect organic capital expenditure on an accruals basis to be in the range of $15-17 billion in 2017. Disposal proceeds for 2016, as per the cash flow statement, were $2.6 billion (2015 $2.8 billion, 2014 $3.5 billion), including amounts received for the sale of certain midstream assets in the Downstream fuels business and our Decatur petrochemicals complex. In addition, in 2016 we also received $0.6 billion in relation to the sale of 20% from our shareholding in Castrol India Limited, shown within financing activities in the cash flow statement, giving total proceeds of $3.2 billion for the year. In 2015 disposal proceeds 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. We expect disposal proceeds to be in the range of $4.5-5.5 billion in 2017. Net cash used in financing activities Net cash provided by financing activities for the year ended 31 December 2016 was $2.0 billion, compared with $4.5 billion used in 2015. This was mainly the result of higher net proceeds from financing of $3.6 billion ($4.0 billion higher net proceeds from long-term debt offset by a decrease of $0.4 billion in short-term debt). In addition, there was a cash inflow of $0.9 billion relating to increases in non-controlling interests, including the sale of 20% from our shareholding in Castrol India Limited noted above. The total dividend paid in cash in 2016 was $2.1 billion lower than in 2015 – see below for further information. The decrease in net cash used in financing activities of $0.7 billion in 2015 compared with 2014 reflected no share repurchases in 2015, compared with $4.6 billion in 2014. This was largely offset by lower net See Glossary. 23 BP Annual Report and Form 20-F 2016Strategic report – performanceUpstream We are building a business that is safer, more modern and efficient, and delivering real value and tangible growth – to 2021 and beyond. Bernard Looney Chief executive, Upstream In summary 71,000km2 6 new exploration access (2015 8,000km2) major project start-ups (2015 3) 11 successful completion of turnarounds (2015 15) 5 final investment decisions (2015 4) 95% upstream BP-operated plant reliability (2015 95%) 2.2 million barrels of oil equivalent per day – hydrocarbon production (2015 2.2mmboe/d) Upstream profitability ($ billion) -0.5 -0.9 0.6 1.2 2016 2015 2014 2013 2012 8.9 15.2 16.7 18.3 22.5 19.4 Replacement cost (RC) profit (loss) before interest and tax Underlying RC profit (loss) before interest and tax 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 2016 our activities took place in 28 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 13 regions, with support provided by global functions in specialist areas of expertise: technology, finance, procurement and supply chain, human resources, information technology and legal. The US Lower 48 continues to operate as a separate, asset-focused, onshore business. Our strategy is to have a balanced portfolio across the world’s key oil and gas basins, while maintaining a focus on capital discipline and quality execution to deliver value. Our incumbent positions and the relationships we hold with resource owners create both stability and opportunity. Our strategy is enabled by: • A relentless focus on safety, reliability and the systematic management of risk. • The quality execution of our projects, our operations, our drilling, and managing our reservoirs – the greatest source of value and returns that we have. • Growing value through improving returns and cash flow. We actively manage our portfolio, divesting where it makes sense, and pursue acquisitions where value can be created. • The capability of our people, who are motivated and equipped to take on the world’s great oil and gas challenges. We have a global workforce that is embracing digital technology to drive improved productivity in everything we do. Our future growth includes an expected 800,000 barrels of oil equivalent per day of production from new projects by 2020, with 500,000 barrels of oil equivalent per day of this new capacity planned to be online by end of 2017. This, combined with our recent portfolio additions, is expected to increase our production by around 1 million barrels per day by 2021. Main image: Deep Blue and Grand Canyon II vessels support the Thunder Horse South expansion project in the US Gulf of Mexico. More information Upstream regional analysis Page 244 24 BP Annual Report and Form 20-F 2016We see our scale and long history in many of the great basins in the world as a differentiator for BP and believe in the strength of our incumbent positions. We are resilient and balanced – in terms of geography, hydrocarbon type and geology – and rather than being restricted by a traditional way of working, we have and will continue to use creative business models to generate value. We are also investing to modernize and transform the Upstream – embracing innovation, digitization and the adoption of big data, which we believe can drive a real step change in performance and efficiency. Financial performance Sales and other operating revenuesa RC profit (loss) before interest and tax Net (favourable) unfavourable impact of non-operating items and fair value accounting effects Underlying RC profit (loss) before interest and tax Organic capital expenditure Additions to non-current assets BP average realizationsc Crude oild e Natural gas liquids Liquids d Natural gas US natural gas Total hydrocarbons d Average oil marker pricesf Brent West Texas Intermediate Average natural gas marker prices Average Henry Hub gas priceg Average UK National Balancing 2016 2015 $ million 2014 33,188 43,235 65,424 574 (937) 8,934 (1,116) 2,130 6,267 (542) 16,048b 17,879 1,193 16,307 17,635 15,201 18,994 22,587 49.72 20.75 47.32 $ per barrel 94.74 36.15 88.88 $ per thousand cubic feet 5.70 3.80 $ per barrel of oil equivalent 61.17 3.80 2.10 35.46 39.99 17.31 38.27 2.84 1.90 28.24 43.73 43.34 2.46 $ per million British thermal units 4.43 pence per therm 2.67 Point gas price f 34.63 42.61 50.01 a Includes sales to other segments. b 2016 includes the consideration for the Abu Dhabi ADCO onshore oil concession renewal. c Realizations are based on sales by consolidated subsidiaries only, which excludes equity-accounted entities. d Production volume recognition methodology for our Technical Service Contract arrangement in Iraq has been simplified to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to comparative periods. There is no impact on the financial results. e Includes condensate and bitumen. f All traded days average. g 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) 150 120 90 60 30 2016 2015 2014 Five-year range Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec The dated Brent price in 2016 averaged $43.73 per barrel. Prices were lowest early in the year, averaging just $34 in the first quarter; rebounding to an average of about $46 in both the second and third quarters, and rising again in the fourth quarter to $49 as OPEC and non-OPEC members discussed – and ultimately agreed – co-ordinated production cuts. Henry Hub ($/mmBtu) 9 6 3 The 2016 Henry Hub First of Month Index price was slightly lower than 2015 ($2.67). The average UK National Balancing Point gas price in 2016 fell by 19% compared with 2015 (2015 a decrease of 15% on 2014). This reflected ample supplies in Europe with record Russian flows offsetting declining indigenous production. For more information on the global energy market in 2016, see page 20. Financial results Sales and other operating revenues for 2016 decreased compared with 2015, primarily reflecting lower liquids and gas realizations, and lower gas marketing and trading revenues. The decrease in 2015 compared with 2014 primarily reflected significantly lower liquids and gas realizations and lower gas marketing and trading revenues partly offset by higher production. Replacement cost loss before interest and tax for the segment included a net non-operating gain of $1,753 million. This primarily relates to the reversal of impairment charges associated with a number of assets, following a reduction in the discount rate applied and changes to future price assumptions. See Financial statements – Note 4 for further information. Fair value accounting effects had an unfavourable impact of $637 million relative to management’s view of performance. 52.39 48.71 $ per barrel 98.95 93.28 2016 2015 2014 Five-year range Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec See Glossary. 25 BP Annual Report and Form 20-F 2016Strategic report – performance The 2015 result included a net non-operating charge of $2,235 million, 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. 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. After adjusting for non-operating items and fair value accounting effects, the underlying RC result before interest and tax was a loss, compared with a profit in 2015. This lower result primarily reflected lower liquids and gas realizations, as well as adverse foreign exchange impacts and lower gas marketing and trading results. This was partly offset by lower costs including the benefits of simplification and efficiency activities, lower exploration write-offs, lower depreciation, depletion and amortization expense and lower rig cancellation charges. Compared with 2014 the 2015 result reflected significantly lower liquids and gas realizations, as well as 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. Additions to non-current assets were $17.9 billion and organic capital expenditure on an accruals basis was $16.0 billion. Excluding the Abu Dhabi onshore oil concession renewal for which shares were used as consideration, organic capital expenditure was $13.6 billion, significantly lower than the $16.3 billion in 2015. In total, disposal transactions generated $0.8 billion in proceeds in 2016, with a corresponding reduction in net proved reserves of 241mmboe within our subsidiaries. The major disposal transaction during 2016 was the transfer of our Norway assets to Aker BP. More information on disposals is provided in Upstream analysis by region on page 244 and Financial statements – Note 4. Outlook for 2017 • We expect to start up seven new major projects in 2017. • We expect underlying production to be higher than 2016. 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 expect oil prices will continue to be challenging in the near term (see page 20). Exploration The group explores for oil and natural gas under a wide range of licensing, joint arrangement may do this alone or, more frequently, with partners. and other contractual agreements. We Our exploration and new access teams work to enable us to optimize our resource base and provide us with a greater number of options. In the current environment, we are spending less on exploration and we will spend a material part of our exploration budget on lower-risk, shorter-cycle-time opportunities around our incumbent positions. 26 50+ years in the Norwegian North Sea An innovative business model BP joined forces with Det norske and Aker in 2016 to form Aker BP ASA. Listed on the Oslo stock exchange, Aker BP is now Norway’s largest independent oil and gas producer. The company’s strategy is underpinned by a blend of Det norske’s nimble business practices, Aker’s industrial experience and BP’s global scale expertise across the hydrocarbon value chain. By combining the assets of these companies, Aker BP has a strong balance sheet with the financial resources to support both ongoing investment in the business and distributions to shareholders. BP expects to apply the knowledge gained from Aker BP across its own businesses. New access in 2016 We gained access to new acreage covering almost 71,000km2 in 10 countries – Australia, Canada, China, Egypt, Ireland, Mauritania, Norway, Russia, the UK and the US. Exploration success We participated in eight potentially commercial discoveries in 2016 – Baltim SW-1, Baltim SW-2, Nooros East and Nooros West in Egypt, Gibson and Nozomi in the Gulf of Mexico, and Golfinho and Zalophus in Angola. Exploration and appraisal costs Excluding lease acquisitions, the costs for exploration and appraisal were $1,402 million (2015 $1,794 million, 2014 $2,911 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 20% of exploration and appraisal costs were directed towards appraisal activity. We participated in 40 gross (21.68 net) exploration and appraisal wells in seven countries. Exploration expense Total exploration expense of $1,721 million (2015 $2,353 million, 2014 $3,632 million) included the write-off of expenses related to unsuccessful drilling activities, lease expiration or uncertainties around development in the Gulf of Mexico ($611 million), Brazil ($601 million), and others ($167 million), partially offset by a net write-back of $103 million across several blocks in India (see Financial statements – Note 7). Reserves booking Reserves bookings 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 2016, decreased by less than 1% (a decrease of 1% for subsidiaries and an increase of 9% for equity-accounted entities) compared with reserves at 31 December 2015. BP Annual Report and Form 20-F 2016Proved reserves replacement ratio The proved reserves replacement ratio for the segment in 2016, including the impact of the Abu Dhabi onshore oil concession renewal, was 96% for subsidiaries and equity-accounted entities (2015 33%), 101% for subsidiaries alone (2015 28%) and 61% for equity-accounted entities alone (2015 76%). For more information on proved reserves replacement for the group see page 251. Invested around $30bn in Egypt Upstream proved reservesa (mmboe) Liquids 1. Subsidiaries 2. Equity-accounted entities Total Gas 3. Subsidiaries 4. Equity-accounted entities Total 4,151 787 4,938 4,981 445 5,425 3 2 Estimated net proved reservesa (net of royalties) Liquids Crude oilb Subsidiaries Equity-accounted entitiesc Natural gas liquids Subsidiaries Equity-accounted entitiesc Total liquids Subsidiariesd Equity-accounted entitiesc Natural gas Subsidiariese Equity-accounted entitiesc Total hydrocarbons Subsidiaries Equity-accounted entitiesc 2016 2015 2014 million barrels 3,778 771 4,549 373 16 389 4,151 787 4,938 28,888 2,580 31,468 9,131 1,232 10,363 3,560 694 4,254 422 13 435 3,982 707 4,689 3,582 702 4,283 510 16 526 4,092 717 4,809 billion cubic feet 32,496 2,373 34,869 30,563 2,465 33,027 million barrels of oil equivalent 9,252 1,132 10,384 9,694 1,126 10,821 a Because of rounding, some totals may not agree exactly with the sum of their component parts. b Includes condensate and bitumen. c BP’s share of reserves of equity-accounted entities in the Upstream segment. During 2016 upstream operations in Argentina, Bolivia, Russia and Norway as well as some of our operations in Angola, Abu Dhabi and Indonesia, were conducted through equity-accounted entities. d Includes 16 million barrels (19 million barrels at 31 December 2015 and 21 million barrels at 31 December 2014) in respect of the 30% non-controlling interest in BP Trinidad & Tobago LLC. e Includes 2,026 billion cubic feet of natural gas (2,359 billion cubic feet at 31 December 2015 and 2,519 billion cubic feet at 31 December 2014) in respect of the 30% non-controlling interest in BP Trinidad & Tobago LLC. 4 Increasing gas in Egypt 1 BP has a long track record in Egypt stretching back over 50 years with investments exceeding $30 billion – making us one of the largest foreign investors in the country. In addition to our strong incumbent position and progress with the West Nile Delta major project, BP purchased a 10% interest in the Zohr gas field from Eni and has plans to accelerate the development of three significant gas discoveries in the East Nile Delta area. The first of these – Atoll in the North Damietta offshore concession – has been approved for an early production scheme to bring up to 300 million standard cubic feet a day (mmscf/d) of gas to the Egyptian domestic gas market starting in the first half of 2018. And in our Nooros development, we ramped up production from zero in the first half of 2015 to 875mmscf/d gross in January 2017. We also made an important discovery in the area’s Baltim South development in 2016, which we are appraising to determine the full resource potential. If viable, we plan to utilize existing infrastructure to accelerate its development and achieve early production start-up. These achievements demonstrate our commitment to playing an ongoing role in helping to secure Egypt’s energy supply for many years to come. Developments start-ups in 2016: two in Algeria, one in We achieved six major project Alaska, one in Angola and two in the Gulf of Mexico. In addition to these, we made good progress in projects in AGT (Azerbaijan, Georgia, Turkey), the Gulf of Mexico, Oman and Egypt. • Azerbaijan, Georgia, Turkey – the Shah Deniz 2 project continues to move ahead with the award of contract for the transport and installation of the deep water subsea production systems. We also signed a letter of intent for the future development of the Azeri-Chirag- Gunashli field, covering the development of the field to the end of 2049. • Gulf of Mexico – we sanctioned the re-evaluated Mad Dog Phase 2 project, having reduced overall project cost by approximately 60% compared to initial design. • Oman – development of the Khazzan project continued, with the project being more than 92% complete as at the year-end. We also signed an agreement to extend the licence area, allowing for a second phase of development in the future. • Egypt – we sanctioned the development of the Atoll Phase 1 project and signed concession amendments in three other projects that allow for the economic development of the Nooros field. Subsidiaries’ development expenditure incurred, excluding midstream activities, was $11.1 billion (2015 $13.5 billion, 2014 $15.1 billion). See Glossary. 27 BP Annual Report and Form 20-F 2016Strategic report – performance Our project pipeline *BP operated Project 2016 start-ups Angola LNG (restart) In Amenas compression In Salah Southern Fields Point Thomson Thunder Horse water injection* Thunder Horse South expansion* Location Angola Algeria Algeria US Alaska US Gulf of Mexico US Gulf of Mexico Egypt UK North Sea Trinidad Oman Australia Azerbaijan Indonesia Trinidad Expected start-ups 2017-2021 Projects currently under constructiona Atoll Phase 1* Culzean Juniper* Oman Khazzan Phase 1* Persephone Shah Deniz Stage 2* Tangguh expansion* Trinidad onshore compression* West Nile Delta Giza/Fayoum/Raven* Egypt Egypt West Nile Delta Taurus/Libra* Australia Western Flank Phase B Egypt Zohr UK North Sea Clair Ridge* US Gulf of Mexico Constellation UK North Sea Quad 204* US Gulf of Mexico Mad Dog Phase 2* Expected start-ups 2017-2021 Design and appraisal phase Angelin* Trinidad offshore compression* KG-D6 D55 KG-D6 R-Series Oman Khazzan Phase 2* Vorlich* Trinidad Trinidad India India Oman UK North Sea West Nile Delta 2 Follow On* Egypt Alligin* Atlantis Phase 3* UK North Sea US Gulf of Mexico Gas Oil Type Production Our offshore and onshore oil and natural gas production assets 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. Our 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 2016, efficient delivery of turnarounds and strong infill drilling performance, we have flattened base decline to less than 3% on average over the last four years. Our long-term expectation for managed base decline remains at the 3-5% per annum guidance we have previously given. Production (net of royalties)a Liquids Crude oilb Subsidiariesc Equity-accounted entitiesd Natural gas liquids Subsidiaries Equity-accounted entitiesd Total liquids Subsidiariesc Equity-accounted entitiesd Natural gas Subsidiaries Equity-accounted entitiesd Total hydrocarbons Subsidiariesc Equity-accounted entitiesd 2016 2015 2014 thousand barrels per day 943 179 1,122 82 4 86 1,025 184 1,208 5,302 494 5,796 933 165 1,099 88 7 95 1,022 172 1,194 834 163 997 91 7 99 926 170 1,096 million cubic feet per day 5,585 431 6,016 5,495 456 5,951 thousand barrels of oil equivalent per day 1,939 269 2,208 1,969 251 2,220 1,889 245 2,133 a Because of rounding, some totals may not agree exactly with the sum of their component parts.. b Includes condensate and bitumen. c Production volume recognition methodology for our Technical Service Contract arrangement in Iraq has been simplified to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to comparative periods. There is no impact on the financial results. d Includes BP’s share of production of equity-accounted entities in the Upstream segment.. Beyond 2021 We have a deep hopper of projects that are currently under appraisal. Our focus here is to ensure we maximize the business opportunity and select the optimum project concept before we move it forward into design. We do not expect to progress all of the projects – only the best. This includes: • a mix of resource types: split across conventional oil, deepwater oil, conventional gas and unconventionals • geographic spread: from Alaska to Australia and Argentina to Russia • a range of development types: from exploration to brownfield and near-field. a For further information on the development of the Taas-Yuryakh oil field (also expected to start up in the period 2017-2021) see page 248. 28 BP Annual Report and Form 20-F 2016 Our total hydrocarbon production for the segment in 2016 was 0.5% lower compared with 2015. The decrease comprised a 1.5% decrease (0.3% increase for liquids and 3.5% decrease for gas) for subsidiaries and a 7.2% increase (6.7% increase for liquids and 8.3% increase for gas) for equity-accounted entities compared with 2015. For more information on production see Oil and gas disclosures for the group on page 251. In aggregate, underlying production was flat versus 2015. 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. The activity primarily takes place in North America, Europe and Asia, 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 280. Production capacity up by 50% Tangguh Expanding our Tangguh gas facility By using an LNG train to convert natural gas into liquid form we make it more practical and commercially viable to transport by sea across countries. At our Tangguh LNG facility in Indonesia, we’ve supplied natural gas to two 3.8 million tonnes per annum (mtpa) LNG trains since 2009. And in line with our shifting focus to gas in BP, we are adding a third train that will bring total plant capacity to 11.4mtpa. We received approval for this expansion project with our production-sharing agreement partners in 2016. The project will also include construction of two offshore platforms and 13 new production wells, as well as an expanded LNG loading facility and supporting infrastructure. We expect train 3 to come into operation in 2020. Through this project we are supporting the country’s growing demand for energy. Around 75% of the LNG production from train 3 will be sold to the Indonesian state electricity company. The project will also help with economic growth in the area and is expected to provide 10,000 jobs over the project period. See Glossary. 29 BP Annual Report and Form 20-F 2016Strategic report – performanceDownstream We are building a safer business and growing our earnings potential with more still to come. Tufan Erginbilgic Chief executive, Downstream In summary 95.3% 1.7 refining availability (2015 94.7%) million barrels of oil refined per day (2015 1.7mmb/d) 43% 14.2 of lubricants sales were premium grade (2015 42%) million tonnes of petrochemicals produced (2015 14.8mmte) Downstream profitability ($ billion) 2016 2015 2014 2013 2012 5.2 5.6 7.1 7.5 3.7 4.4 2.9 2.9 3.6 6.5 Replacement cost (RC) profit before interest and tax Underlying RC profit before interest and tax 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: Our strategic priorities are: • Safe and reliable operations – this remains our first priority and we continue to drive improvement in personal and process safety performance. • Fuels – includes refineries, logistic networks, fuels • Advantaged manufacturing – we continue to build a marketing and convenience retail businesses, together with global oil supply and trading activities that make up our integrated 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 cash flow . , with improving returns and growing operating , by having a competitively top-quartile refining business as measured through net cash margin per barrel 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. • Simplification and efficiency – this remains central to what we do to support performance improvement and make our businesses even more competitive. • Transition to a lower carbon and digitally enabled future – we are pursuing and developing new offers and products that support the transition to a lower carbon and digitally enabled future over the long term. Disciplined execution of our strategy is helping improve our underlying performance, capture opportunities for further growth, generate attractive returns and create a more resilient business that is better able to withstand a range of market conditions; and create opportunities for future growth. We aim to ensure Downstream remains a reliable source of cash flow growth for BP. Main image: Vaporizer towers convert liquid nitrogen to gas at our US Whiting refinery. More information Downstream plant capacity Page 249 30 BP Annual Report and Form 20-F 2016Financial performance Sale of crude oil through spot and term contracts Marketing, spot and term sales 2016 2015 $ million 2014 31,569 38,386 80,003 of refined products 126,419 148,925 227,082 Other sales and operating revenues Sales and other operating revenuesa RC profit (loss) before interest and taxb Fuels Lubricants Petrochemicals Net (favourable) unfavourable impact of non-operating items and fair value accounting effects Fuels Lubricants Petrochemicals Underlying RC profit (loss) before interest and taxb Fuels Lubricants Petrochemicals Organic capital expenditure Additions to non-current assets 9,695 13,258 16,401 167,683 200,569 323,486 3,337 1,439 386 5,162 390 84 (2) 472 3,727 1,523 384 5,634 2,141 3,109 5,858 1,241 12 7,111 137 143 154 434 5,995 1,384 166 7,545 2,101 2,130 2,830 1,407 (499) 3,738 389 (136) 450 703 3,219 1,271 (49) 4,441 2,995 3,121 a Includes sales to other segments. b Income from petrochemicals produced at our Gelsenkirchen and Mülheim sites in Germany is reported in the fuels business. Segment-level overhead expenses are included in the fuels business result. Financial results Sales and other operating revenues in 2016 and 2015 were lower due to lower crude and product prices. Replacement cost profit before interest and tax for the year ended 31 December 2016 included a net non-operating charge of $24 million, mainly relating to a gain on disposal in our fuels business which was more than offset by restructuring and other charges. The 2015 result included a net non-operating charge of $590 million, mainly relating to restructuring charges, while the 2014 result included a net non-operating charge of $1,570 million, primarily relating to impairment charges in our petrochemicals and fuels businesses. In addition, fair value accounting effects had an unfavourable impact of $448 million, compared with a favourable impact of $156 million in 2015 and $867 million in 2014. After adjusting for non-operating items and fair value accounting effects, underlying RC profit before interest and tax in 2016 was $5,634 million. Additions to non-current assets in 2016 included the asset exchange relating to the dissolution of our German refining joint operation with Rosneft as well as organic capital expenditure. Outlook for 2017 • We anticipate a gradual improvement in the refining environment, although refining margins for the year are expected to remain at the lower end of the recent historical range. • We expect the financial impact of routine refinery turnarounds to be slightly higher than 2016 as a result of increased turnaround activity, particularly in Europe. Our fuels business The fuels strategy focuses primarily on fuels value chains (FVCs). This includes building a top-quartile net cash margin 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. We continue to grow our fuels marketing businesses through differentiated marketing offers and strategic convenience partnerships. We partner with leading retailers, creating distinctive offers that aim to deliver good returns and reliable profit and cash generation. Underlying RC profit before interest and tax was lower compared with 2015 reflecting a significantly weaker refining environment and the impact from a particularly large turnaround at Whiting refinery, partially offset by lower costs reflecting the benefits from our simplification and efficiency programmes, an increased fuels marketing performance driven by retail growth and higher refining margin capture in our operations. Compared with 2014, the 2015 result was higher reflecting a strong refining environment, improved refining margin optimization and operations, and lower costs from simplification and efficiency programmes. refining availability Operational excellence at Kwinana We get the best value from our refineries when they run efficiently at full capacity. Across all of our refineries staff work hard to maintain safe and reliable operations, prevent unplanned shutdowns and optimize operational performance. Kwinana, just outside Perth in Western Australia, is the country’s largest refinery. It supplies virtually all the petrol and diesel demand in the country‘s south west and all jet fuel for Perth Airport. And for the last three years we’ve been implementing improvement works across the refinery – covering everything from sourcing good quality crude to effective planning and scheduling, and maintaining effective manufacturing operations. We are already seeing a difference at Kwinana, with the refinery improving its availability – the percentage of time process units are capable of running at full capacity – in 2016. And the refinery’s utilization – the difference between production capacity and what’s actually processed – places it in the top quartile of Asia-Pacific refineries based on the latest fuels study by Solomon Associates. See Glossary. 31 BP Annual Report and Form 20-F 2016Strategic report – performance Refining marker margin We track the margin environment by a global refining marker margin (RMM). Refining margins are a measure of the difference between the price a refinery pays for its inputs (crude oil) and the market price of its products. Although refineries produce a variety of petroleum products, we track the margin environment using a simplified indicator that reflects the margins achieved on gasoline and diesel only. The RMM may not be representative of the margin achieved by BP in any period because of BP’s particular refinery configurations and crude and product slates. In addition, the RMM does not include estimates of energy or other variable costs. Region US North West US Midwest Crude marker Alaska North Slope West Texas Intermediate Northwest Europe Brent Mediterranean Australia BP RMM Azeri Light Brent BP refining marker margin ($/bbl) 2016 2015 $ per barrel 2014 16.9 13.2 10.0 9.0 10.9 11.8 24.0 19.0 14.5 12.7 15.4 17.0 16.6 17.4 12.5 10.6 13.5 14.4 32 24 16 8 2016 2015 2014 Five-year range Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec The average global RMM in 2016 was $11.8/bbl, $5.2/bbl lower than in 2015, and the lowest since 2010. The decrease was driven by product oversupply resulting from higher refinery utilization which outstripped growth in demand. Refining At 31 December 2016 we owned or had a share in 11 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 249. In 2016 refinery operations were strong, with refining availability sustained at around 95.3% and utilization rates of 91% for the year. Overall refinery throughputs in 2016 were flat compared with 2015 with increased throughputs in our refining portfolio offset by the impact from ceasing operations at Bulwer in 2015 and the large turnaround at Whiting. In December 2016 the previously announced dissolution of our German refining joint operation with Rosneft was completed. This will simplify and refocus our refining business in the heart of Europe. 32 Refinery throughputsa US Europe Rest of worldb Total Refining availability Sales volumes Marketing salesc Trading/supply salesd Total refined product sales Crude oile Total 2016 646 803 236 1,685 95.3 2,825 2,775 5,600 2,169 7,769 2015 657 794 254 1,705 2014 thousand barrels per day 642 782 297 1,721 % 94.9 94.7 thousand barrels per day 2,872 2,835 2,448 2,770 5,320 5,605 2,360 2,098 7,680 7,703 a Refinery throughputs reflect crude oil and other feedstock volumes. b Bulwer refinery in Australia ceased refining operations in 2015. 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. 71,000 barrels per day relate to revenues reported by the Upstream segment. Marketing and logistics 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 2016 we completed the sale of our Amsterdam oil terminal and announced our intention to divest some of our fuels terminals in the UK. This reflects our continued focus on increasing our competitiveness through having an advantaged portfolio. We supply fuel and related retail services to consumers through company-owned and franchised retail sites, as well as other channels, including dealers and jobbers. We also supply commercial customers within the transport and industrial sectors. Retail sitesf US Europe Rest of world Total Number of retail sites operated under a BP brand 2014 7,100 8,000 2,900 18,000 2016 7,100 8,100 2,800 18,000 2015 7,000 8,100 2,900 18,000 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 and includes our interest in equity-accounted entities. 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 and plan to expand our networks further. Retail is a significant source of growth today and is expected to be so in the future. This year we continued the rollout of our new BP fuels with ACTIVE technology which are now sold in 13 countries globally (see page 34). We also entered into two new convenience partnerships in Europe with leading food retailing companies, REWE to go® in Germany and Albert Heijn to go® in the Netherlands. In December 2016 we announced that we will be establishing a strategic partnership with Woolworths in Australia. The agreement includes us acquiring Woolworths’ fuel and convenience sites for a total consideration of $1.3 billion and entering into a strategic convenience partnership with them. The transaction is subject to regulatory approvals. BP Annual Report and Form 20-F 2016 Aviation Air BP is one of the world’s largest global aviation fuels suppliers. Our strategic aim is to maintain a strong presence in our core locations of Europe and the US, while expanding our portfolio in airports that offer long-term competitive advantage in material growth markets such as Asia and South America. Air BP serves many major commercial airlines as well as the general aviation sector. We have marketing sales of more than 430,000 barrels per day, and in 2016 entered into two joint venture partnerships to market aviation fuels in Peru and Indonesia. We also announced a strategic partnership with Fulcrum BioEnergy® and partnered with RocketRoute® to launch a digital app that provides online fuel purchasing and payment functionality across our global network of aviation fuel locations. 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 60% 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. This year we launched Castrol MAGNATEC with DUALOCK technology, our latest premium brand lubricant, which reduces warm-up and stop-start wear by up to 50% (see page 12). 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 that was higher compared with 2015 – which in turn was higher than 2014. In fact this 2016 result was a record performance for lubricants. Both the 2016 and 2015 results reflected continued strong performance in growth markets and premium brands as well as lower costs achieved through simplification and efficiency programmes. In 2016 we sold approximately 20% from our shareholding in Castrol India Limited, reducing our shareholding to 51%. We continue to be the majority shareholder and have strategic control of the company. 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: 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 280. Low carbon energy solutions 10-year commitment to reduce emissions BP supplies fuel for more than 6,000 flights a day and we work to help our aviation customers reduce their emissions in a number of ways. At Oslo airport in Norway we helped to make biojet available through its normal supply infrastructure. As a result of Air BP’s collaboration, the airport won the 2016 Eco-Innovation environment award from Airport Carbon Accreditation. We also invested in Fulcrum BioEnergy® – a company that produces sustainable jet fuel from household waste. Our strategic partnership aims to help the company bring biojet to the market at scale. But our commitment doesn’t end there – in 2016 we achieved carbon neutrality for our into-plane fuelling services across a network of more than 200 Air BP-operated facilities. And we have made a 10- year commitment to retain our carbon neutral accreditation and aim to reduce emissions by 5% over this period. All of these changes contribute to the International Air Transport Association’s aim to achieve carbon neutral growth by 2020 and a 50% reduction in carbon emissions by 2050. See Glossary. 33 BP Annual Report and Form 20-F 2016Strategic report – performanceIn 2016 the petrochemicals business delivered a higher underlying RC profit before interest and tax compared with 2015 – which in turn was higher than 2014. The result reflected strong operations and margin capture supported by the continued rollout of our latest advanced technology, as well as benefits from a slightly improved environment particularly in olefins and derivatives. Compared with 2014, the 2015 result reflected improved operational performance and benefited from our simplification and efficiency programmes leading to lower costs. Our petrochemicals production of 14.2 million tonnes in 2016 was lower than 2015 but higher than 2014 (2015 14.8mmte, 2014 14.0mmte), due to the divestment of the Decatur petrochemicals complex in 2016 and the low margin environment in 2014 compared with 2015 driving reduced output. As part of our strategy to refocus our global petrochemicals business for long-term growth, we completed the sale of the Decatur petrochemicals complex in Alabama, US in March 2016. We completed the upgrade of our PTA plant in Geel, Belgium, using our latest proprietary technology and are continuing the upgrade at Cooper River in South Carolina, US, which is scheduled to complete in early 2017. We expect these investments to significantly increase manufacturing efficiency at both facilities. We are also leveraging our proprietary technology to offer a low carbon PTA solution to manufacturers, brand owners and their customers. In 2016 we launched PTAir, which supports a carbon footprint of around 30% lower than the average European PTA production. Our licensing business continues to be a core part of our growth strategy and in December 2016 Reliance Industries Limited successfully commissioned the first phase of its paraxylene plant in Gujarat, India using BP’s proprietary technology. The plant, with a capacity of 1.8 million tonnes, is the world’s largest paraxylene unit and is built with BP’s leading crystallization technology which delivers greater energy efficiency. Available in 13 countries Innovative fuels Engine technologies continually evolve. So we work to anticipate and understand these changes to make sure we develop fuels that complement the latest engine innovations – while continuing to benefit older engines too. We have rolled out our new BP fuels with ACTIVE technology in 13 countries including Australia, South Africa and the US. These fuels use an innovative formula designed to actively fight dirt in the car’s engine and protect against it building up. This helps keep engines running as intended by car manufacturers – smoothly and efficiently – and helps reduce the risk of unplanned maintenance. Our petrochemicals business Our petrochemicals strategy is to improve our earnings potential and make the business more resilient to a bottom-of-cycle environment. We develop proprietary technology to deliver leading cost positions compared with our competition. We manufacture and market four main product lines: • Purified terephthalic acid (PTA). • Paraxylene (PX). • Acetic acid. • Olefins and derivatives. We also produce a number of other specialty petrochemicals products. 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 two years into our strategic programme to significantly improve the resilience of the business to a bottom-of-cycle environment through: • Repositioning a significant portion of our portfolio including shutting down older capacity in the US and Asia. • Retrofitting our best technology at 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 additional value through simplification and efficiency programmes. 34 BP Annual Report and Form 20-F 2016Rosneft Rosneft is the largest oil company in Russia, with a strong portfolio of current and future opportunities. i S t r a t e g c r e p o r t – p e r f o r m a n c e 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 one of the largest and lowest cost hydrocarbon resource bases in the world and its resources play an important role in long-term energy supply to the global economy. • BP’s strategy in Russia is to support Rosneft’s overall performance and growth through collaboration on technology and best practice, and to build a material business based on standalone projects with Rosneft in Russia and internationally. BP remains committed to our strategic investment in Rosneft, while complying with all relevant sanctions. 2016 summary • Rosneft continued optimizing its portfolio and increased total hydrocarbon production by 4%. • Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is wholly owned by the Russian government. In December an agreement was signed to sell 19.5% from Rosneftegaz’s 69.5% shareholding in Rosneft to a consortium of international investors, comprising Qatar Investment Authority and Glencore. Following completion of the transaction, at the year-end Rosneftegaz’s shareholding in Rosneft was 50% plus one share. • Rosneft acquired a 50.0755% stake in Russian oil company Bashneft in October and subsequently increased its shareholding to 60.33% as a result of an offer to buy out minority shareholders. This acquisition is expected to provide Rosneft with significant synergies and additional refining throughput and liquid hydrocarbon production. BP accounts for its share of production and reserves resulting from the acquisition through its 19.75% stake in Rosneft. About Rosneft 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 Russia’s key hydrocarbon regions. Rosneft’s hydrocarbon production reached a record of 5.4mmboe/d in 2016. Gas production for the year increased by 7.3% to 67.1bcma or 6.47bcf/d compared with 2015. Rosneft is also the leading Russian refining company based on throughput. It owns and operates 13 refineries in Russia, including three recently acquired in the Bashneft transaction. Rosneft also owns and operates more than 2,950 retail service stations in Russia and abroad. These include BP-branded sites operating under a licensing agreement acquired as part of the TNK-BP acquisition in 2013, and Bashneft- branded stations. Downstream operations include jet fuel, bunkering, bitumen and lubricants. Rosneft refinery throughput in 2016 reached a record level of 2.028mmb/d versus 1.966mmb/d in 2015. BP‘s strategy in Russia Our strategy is to work in co-operation with Rosneft to increase total shareholder return and partner with it in building a material business outside of the shareholding. This strategy is implemented through our activities in four areas: • Rosneft Board of Directors: BP has two nominees on the Rosneft Board of Directors and its committees. • Technology: develop and apply technology to improve oil and gas field and refining performance in collaboration with Rosneft. • Joint ventures: partner with Rosneft to generate incremental value from joint ventures that are separate from BP’s core shareholding. • Rosneft also agreed to purchase a 49% stake in Essar Oil Limited, which owns the Vadinar refinery in India, one of the largest and most advanced refineries in the world. • Technical services: the partners collaborate on the provision of technical services on a contractual basis to improve asset performance. • In July BP received $332 million, net of withholding taxes (2015 $271 million, 2014 $693 million), representing its share of Rosneft’s dividend of 11.75 Russian roubles per share. This dividend stood at 35% of Rosneft’s 2015 IFRS net profit, an increase from the 25% paid in the previous year. • Two BP nominees, Bob Dudley and Guillermo Quintero, serve on Rosneft’s nine member Board of Directors. Bob Dudley is a member of its Strategic Planning Committee and Guillermo Quintero is a member of its HR and Remuneration Committee. The following developments and activities in 2016 have served to support and progress this strategy: • BP holds a 20% interest in Taas-Yuryakh Neftegazodobycha (Taas), a joint venture with Rosneft that is developing the Srednebotuobinskoye oil and gas condensate field in East Siberia. In October Rosneft sold a 29.9% interest in the joint venture to a consortium consisting of Oil India Limited, Indian Oil Corporation Limited and Bharat PetroResources Limited. BP’s interest in Taas is reported through the Upstream segment. • US and EU sanctions remain in place on certain Russian activities, • Rosneft and BP completed a transaction in October to create a new individuals and entities, including Rosneft. joint venture, Yermak Neftegaz LLC (Yermak). It will conduct onshore exploration in the West Siberian and Yenisei-Khatanga basins. Yermak is 51% owned by Rosneft and 49% by BP, and currently holds seven exploration and production licences. The venture will also carry out further appraisal work on the Baikalovskoye field, an existing Rosneft See Glossary. 35 BP Annual Report and Form 20-F 2016 discovery in the Yenisei-Khatanga area of mutual interest. BP’s interest in Yermak is reported through the Upstream segment. • Rosneft, BP and Schlumberger signed agreements in September for collaboration on seismic research and the development of an innovative cableless onshore seismic acquisition technology. The technology aims to revolutionize the design and acquisition of seismic surveys and increase the efficiency of exploration, appraisal and field development (see page 12). • BP and Rosneft completed the dissolution of their German refining joint operation Ruhr Oel GmbH (ROG) in December. During the year Rosneft continued actively managing its portfolio. Highlights included: • Selling a 49.9% share in its subsidiary Vankorneft (excluding infrastructure) to ONGC Videsh Limited and a consortium of Indian companies comprising Oil India Limited, Indian Oil Corporation Limited and Bharat PetroResources Limited. The base price was $4.2 billion. • Signing an agreement to sell a 20% interest in its Verkhnechonskneftegaz subsidiary to the Beijing Gas Group in November. The parties are in the process of obtaining the necessary regulatory approvals. Market price The price of Urals delivered in North West Europe (Rotterdam) averaged $41.68/bbl in 2016, $2.05/bbl below dated Brent . The differential to Brent widened from $1.42/bbl in 2015, amid 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 2016 and 2014 included non-operating gains of $23 million and $225 million respectively whereas the 2015 result did not include any non-operating items. After adjusting for non-operating items, the decrease in the underlying RC profit before interest and tax compared with 2015 primarily reflected lower oil prices and increased government take, partially offset by favourable duty lag effects. Compared with 2014, the 2015 result primarily was affected by lower oil prices and foreign exchange, partially offset by favourable duty lag effects. See also Financial statements – Notes 16 and 31 for other foreign exchange effects. Balance sheet 2016 2015 $ million 2014 • Signing an agreement for the purchase of a 49% stake in Essar Oil Investments in associates c (as at 31 December) 8,243 5,797 7,312 Production and reserves Production (net of royalties) (BP share) Liquids (mb/d) Crude oild Natural gas liquids Total liquids Natural gas (mmcf/d) Total hydrocarbons (mboe/d) Estimated net proved reservese (net of royalties) (BP share) Liquids (million barrels) Crude oild Natural gas liquids Total liquids Natural gas (billion cubic feet) Total hydrocarbons (mmboe) 2016 2015 2014 836 4 840 1,279 1,060 809 4 813 1,195 1,019 5,330 65 5,395f 11,900g 7,447 4,823 47 4,871 11,169 6,796 816 5 821 1,084 1,008 4,961 47 5,007 9,827 6,702 c See Financial statements – Note 16 for further information. d Includes condensate. e Because of rounding, some totals may not agree exactly with the sum of their component parts. f Includes 347 million barrels of crude oil in respect of the 6.58% non-controlling interest in Rosneft held assets in Russia including 28 million barrels held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha. g Includes 300 billion cubic feet of natural gas in respect of the 2.53% non-controlling interest in Rosneft held assets in Russia including 3 billion cubic feet held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha. Limited (EOL), an Indian downstream business, from the Essar group in October. As a result of this transaction, Rosneft will acquire an interest in the Vadinar refinery and related infrastructure in India, which is among the top 10 refineries in terms of scale and complexity worldwide. EOL’s business also includes a network of Essar-branded retail outlets across India. The parties are in the process of obtaining the necessary regulatory approvals. • Signing an agreement for the acquisition of 30% of the concession agreement for the development of the Zohr gas field in Egypt in December for $1.125 billion plus $450 million as reimbursement of 2016 historical expenses. The agreement also includes an option for Rosneft to acquire an additional 5% interest on the same terms. The parties are in the process of obtaining the necessary regulatory approvals. Rosneft segment performance BP’s investment in Rosneft is managed and reported as a separate segment under IFRS. The segment result includes equity-accounted earnings, representing BP’s 19.75% share of the profit or loss of Rosneft, as adjusted for the accounting required under IFRS relating to BP’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the disposal of BP’s interest in TNK-BP. See Financial statements – Note 16 for further information. Profit before interest and taxa b Inventory holding (gains) losses RC profit before interest and tax Net charge (credit) for non-operating items Underlying RC profit before interest and tax Average oil marker prices Urals (Northwest Europe – CIF) 2016 643 (53) 590 (23) 2015 1,314 (4) 1,310 $ million 2014 2,076 24 2,100 – (225) 567 1,310 1,875 41.68 50.97 $ per barrel 97.23 a 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. b Includes $3 million (2015 $16 million, 2014 $25 million) of foreign exchange losses arising on the dividend received. 36 See Glossary. BP Annual Report and Form 20-F 2016 Other businesses and corporate Comprises our alternative energy business, shipping, treasury and corporate activities, including centralized functions and the costs of the Gulf of Mexico oil spill. i S t r a t e g c r e p o r t – p e r f o r m a n c e Gulf of Mexico oil spill Following the 2015 settlements with the United States and the Gulf states, that were approved by the federal district court in 2016, further significant progress was made in 2016 towards resolving outstanding claims arising from the 2010 Deepwater Horizon accident and oil spill. This included: • Progress in resolving the outstanding business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement. • Progress in resolving economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were excluded from that settlement. • The finalization by the claims administrator of six of the claims categories under the PSC settlement, the largest of which was the seafood compensation programme. • The settlement of the class action brought by ADS holders who purchased their shares after the accident. As a result of this progress, we have clarified the remaining material uncertainties arising from the incident. The cumulative pre-tax income statement charge since the incident, in April 2010, amounted to $62.6 billion. More information Financial statements Note 2. Process safety and ethics monitors page 42. Legal proceedings page 261. Financial performance 2016 2015 $ million 2014 Sales and other operating revenuesa 1,667 2,048 1,989 RC profit (loss) before interest and tax Gulf of Mexico oil spill Other RC profit (loss) before (6,640) (11,709) (1,768) (1,517) (781) (2,010) interest and tax (8,157) (13,477) (2,791) Net unfavourable impact of non-operating items Gulf of Mexico oil spill Other Net charge (credit) for non-operating items Underlying RC profit (loss) before interest and tax Organic capital expenditure Additions to non-current 6,640 279 11,709 547 781 670 6,919 12,256 1,451 (1,238) 251 (1,221) 340 (1,340) 903 assets 216 315 784 a Includes sales to other segments. The replacement cost (RC) loss before interest and tax for the year ended 31 December 2016 was $8.2 billion (2015 $13.5 billion, 2014 $2.8 billion). The 2016 result included a net charge for non-operating items of $6,919 million primarily relating to costs for the Gulf of Mexico oil spill (2015 $12,256 million, 2014 $1,451 million). For further information, see Gulf of Mexico oil spill and Financial statements – Note 2. After adjusting for these non-operating items, the underlying RC loss before interest and tax for the year ended 31 December 2016 was $1.2 billion, similar to prior years (2015 $1.2 billion, 2014 $1.3 billion). Outlook Other businesses and corporate annual charges, excluding non-operating items, are expected to be around $1.4 billion in 2017. Main image: The fermentation tanks at our biofuels Ituiutaba sugar cane to ethanol plant in Brazil. Inset image: An engineer at the top of a wind turbine tower at Sherbino wind farm in Texas. See Glossary. 37 BP Annual Report and Form 20-F 2016 Our Tropical site achieved the Bonsucro certification for sustainability, legal compliance and production processes for the fourth consecutive year. We produced 733 million litres of ethanol equivalent and generated 562GWh of power for Brazil’s national grid. We continue to invest 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. Wind BP is among the top wind energy producers in the US. At 31 December 2016, we directly operated 14 wind farms across eight US states, while holding an interest in a separate facility in Hawaii. Our net generating capacity from this portfolio, based on our financial stake was 1,452MW of electricity. Our net share of US wind generation for 2016 was 4,389GWh. BP also runs one wind farm at our refinery sites in the Netherlands, operating on a much smaller scale and managed by our Downstream segment, with 22.5MW of generating capacity. Safety remains our number one priority and a number of sites achieved safety milestones in 2016. For example, Silver Star and Titan both achieved seven years without a recordable injury, and Fowler 1 and 3 have received awards from Vestas – a leading wind turbine manufacturer – for ‘best overall balanced scorecard’ which includes metrics for safety and availability. Alternative energy BP has the largest operated renewables business among our oil and gas peers. Renewables will play an increasingly important role in a lower carbon future. They are projected to grow seven times faster than all other energy types combined. Today, they account for around 3% of global energy demand, excluding large-scale hydroelectricity. BP has been producing renewable energy for more than a decade. Our strategy is to invest where we can build commercially viable businesses at scale. With a focus on biofuels and wind, we have the largest operated renewables business among our oil and gas peers. This means that we are directly managing these businesses – from manufacturing biofuels from sugar cane feedstock to generating and distributing wind energy. We are also evaluating other areas where we can grow our involvement in lower carbon opportunities, particularly where they may play a role in complementing existing businesses such as natural gas. Find out about the actions we are taking to address climate change including low carbon venturing on pages 12 and 43. Biofuels business model and strategy Biofuels can help reduce emissions from transportation, the fourth largest source of greenhouse gas (GHG) emissions today. They can be used in existing cars and infrastructure without major changes. 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 bioethanol sites with a combined nameplate capacity of 10 million tonnes per year. We also export 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. Caption: Producing biofuels from sugar cane at our Tropical site in Brazil. 38 More information See bp.com/renewables or our Sustainability Report. BP Annual Report and Form 20-F 2016Caption: Our British Merchant LNG tanker was built in 2003 and measures 279 metres in length. Shipping BP’s shipping and chartering activities help to ensure the safe transportation of our hydrocarbon products using a combination of BP- operated, time-chartered and spot-chartered vessels. At 31 December 2016, BP had four vessels supporting operations in Alaska, and 46 BP- operated and 28 time-chartered vessels for our international oil and gas shipping operations. In 2016 13 new oil tankers were delivered into the BP-operated fleet, a further 13 are expected in 2017, and six technically advanced LNG tankers are on order and planned for delivery into the BP- operated fleet between 2018 and 2019. As part of our fleet rejuvenation programme, the new ships will all be equipped with new technologies that help improve their safety, efficiency and emissions. For example tankers and product carriers are built with extra-long stroke engines that reduce fuel consumption with fewer revolutions per minute. And within the fleet certain ships have low enough sulphur dioxide emissions to enable us to trade in parts of the world with the most stringent regulations. All vessels conducting BP shipping activities are required to meet BP approved health, safety, security and environmental standards. 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 funding and investment, 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 or if specific circumstances require such a review. See Glossary. 39 BP Annual Report and Form 20-F 2016Strategic report – performanceSustainability We aim to create long-term value for our shareholders, partners and society by helping to meet growing energy demand in a safe and responsible way. In summary Our 2016 sustainability focus These sustainability issues are the ones that could impact our business the most and that are of greatest interest to our stakeholders. Safety Safety is one of our values and our number one priority. Our stated aim is to have no accidents, no harm to people and no damage to the environment. The fundamentals of how we deliver safe and reliable operations remain unchanged in a lower oil price environment. We are working to continuously improve personal and process safety and operational risk management across BP, with our group-wide operating management system at its core. Our approach builds on our experience, including learning from incidents, operations audits, annual risk reviews and sharing lessons learned with our industry peers. In 2016 BP reported three workforce fatalities. One contractor died following a leg injury sustained at our biofuels business in Brazil and two contractors died in a pipeline construction incident in Oman. We deeply regret the loss of these lives and continue to focus our efforts on eliminating the risk of injuries and fatalities in our work. Process safety Major accidents or spills can result in serious harm to people and the environment, which is why process safety is so important. Process safety means designing our facilities to appropriate standards and using robust engineering principles. It also underlines the importance of having capable people and rigorous operating and maintenance practices. See bp.com/sustainability for case studies, country reports and an interactive tool for health, safety and environmental data. Main image: Mad Dog platform in the Deepwater Gulf of Mexico. Inset image: Two of our wind farms achieved seven years without a recordable injury in 2016. 40 Safety Climate change Value to society Human rights Local environmental impacts Ethical conduct Our people Process safety events (number of incidents) 400 300 200 100 2012 2013 2014 2015 2016 Tier 1 Tier 2 Loss of primary containment Recordable injury frequency (workforce incidents per 200,000 hours worked) 0.8 0.6 0.4 0.2 Workforce Employees Contractors 2012 0.35 0.26 0.43 2013 0.31 0.25 0.36 2014 0.31 0.27 0.34 2015 0.24 0.20 0.28 2016 0.21 0.19 0.22 American Petroleum Institute US benchmarka International Association of Oil & Gas Producers benchmarka aAPI and OGP 2016 data reports are not available until May 2017. BP Annual Report and Form 20-F 2016Tier 1 process safety events Tier 2 process safety events Loss of primary containment – number of incidentsa Oil spills – numberb Oil spills contained Oil spills reaching land and water Oil spilled – volume (thousand litres) Oil unrecovered (thousand litres) 2016 16 84 275 149 91 58 677 311 2015 20 83 235 146 91 55 432 142 2014 28 95 286 156 93 63 400 155 a Does not include non-hazardous releases. b Number of spills greater than or equal to one barrel (159 litres, 42 US gallons). To track our safety performance we use industry metrics, such as the American Petroleum Institute recommended practice 754 and the International Association of Oil and Gas Producers recommended practice 456. These include tier 1 process safety events, which are losses of primary containment of greater consequence – such as causing harm to a member of the workforce, costly damage to equipment or exceeding defined quantities. Tier 2 events are those of lesser consequence. The overall number of process safety events decreased in 2016, continuing the downward trend of the past five years. Another metric that tracks unplanned or uncontrolled releases of our products from pipes, containers or vehicles is loss of primary containment (LOPC). This is a BP metric that includes events within our operational boundary, excluding releases of non-hazardous substances such as water. We saw an increase of LOPCs in 2016, partly due to harsher winter operating conditions in our unconventional gas operations in the US. We have seen improvements in our process safety performance over the past five years. For example, at our Rotterdam refinery the number of tier 2 events has reduced from 12 in 2012 to just one in 2016. Alongside this, the refinery’s availability has increased, with 2016 its best year in over a decade. We see examples of this right across our operations – we believe this shows that the rigour needed to produce safe operations tends also to produce reliable operations. Personal safety All members of our workforce have the responsibility and the authority to stop unsafe work. Our golden rules of safety guide our workers on staying safe while performing tasks with the potential to cause most harm. The rules are aligned with our operating management system and focus on areas such as working at heights, lifting operations and driving safety. Recordable injury frequencyc Day away from work case frequencyc d Severe vehicle accident ratee 2016 0.21 0.051 0.05 2015 0.24 0.061 0.11 2014 0.31 0.081 0.13 c Incidents per 200,000 hours worked. d Incidents that resulted in an injury where a person is unable to work for a day (shift) or more. e This figure is based on our new definition which aligns with industry practice. We estimate that based on our previous definition, the rate would have been around 0.09%. We monitor and report on key workforce personal safety metrics and include both employees and contractors in our data. We measure our workforce recordable injury frequency, which is the number of reported work-related incidents that result in a fatality or injury per 200,000 hours worked. We also measure our day away from work case frequency, which is the number of incidents per 200,000 hours worked that resulted in an injury where a person is unable to work for a day (or shift) or more. Our recordable injury frequency and our day away from work rates have reduced across BP in 2016. This continues a pattern of improvement in personal safety over a number of years, which is encouraging. However we know we must maintain our efforts to continue improving safety in our operations. Caption: Using technology to monitor conditions on board our Thunder Horse platform in the Gulf of Mexico. Managing safety BP-operated businesses are responsible for identifying and managing operating risks and bringing together people with the right skills and competencies to address them. 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 How we manage risk on page 47 and SEEAC’s report on page 74. 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. 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 42 for information about contractors and joint arrangements . See Glossary. 41 BP Annual Report and Form 20-F 2016Strategic report – performance Technology New technologies are helping us increase the amount and quality of data we gather from our operations and speed up our analysis, allowing us to act more quickly. For example, we are piloting software that identifies early warning signs of potential performance problems by gathering machinery and plant data, analysing it and bringing it all to a single screen so engineers can more quickly troubleshoot and resolve potential issues. See page 12 for more information. We are also testing magnetic crawler robots to inspect the pipelines that connect our deepwater wells with our platforms in the Gulf of Mexico. The robots use lasers to identify corrosion or damage. This can provide us with earlier warnings of potential safety issues. Emergency preparedness and response The scale and spread of BP’s operations means we must be prepared to respond to a range of possible disruptions and emergency events. We maintain disaster recovery, crisis and business continuity management plans and work to build day-to-day response capabilities to support local management of incidents. Working with contractors and partners With more than half the hours worked in BP carried out by contractors, our ability to be a safe operator depends in part on the capability and performance of those who help us carry out our work. We seek to set clear and consistent expectations of our contractors. Our standard model contracts include health, safety, security, human rights and environmental 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. We expect and encourage our contractors and their employees to act in a way that is consistent with our code of conduct and we take appropriate actions where we believe they have not met our expectations or their contractual obligations. Our OMS includes requirements and practices for working with contractors. Our partners in joint arrangements In joint arrangements where we are the operator, our OMS, code of conduct and other policies apply. We aim to report on all aspects of our business where we are the operator – as we directly manage the performance of these operations. Security BP monitors for hostile actions that could cause harm to our people or disrupt our operations. We assess risk on an ongoing basis in those areas that are affected by political and social unrest, terrorism, armed conflict or criminal activity. Our central security team provides guidance and support to our businesses through a network of regional security advisers. Oil spill response Our requirements for oil spill preparedness and response planning incorporate what we have learned over many years of operations. We take steps to improve our ability to respond to spills. For example, we used satellite technology to enhance our response in the UK North Sea in 2016. Where we are not the operator, our OMS is available as a reference point for BP businesses when engaging with operators and co-venturers. We monitor performance and how risk is managed in our joint arrangements, whether we are the operator or not. For example, in Canada we have 50% ownership of the Sunrise oil sands project but it is operated by another company. We benchmark the operator’s safety, financial and environmental performance against our expectations. And BP representatives on the venture’s governance committee are responsible for confirming that activities are consistent with our investment requirements and code of conduct. We have a group framework to assess BP’s exposure related to safety, operational and bribery and corruption risk from our participation in non- operated joint arrangements. Cyber security 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. See page 48. Process safety and ethics monitors Two independent monitors – an ethics monitor and a process safety monitor – were appointed under the terms of the plea agreement that BP reached with the US government in 2012, following the Deepwater Horizon accident in 2010. The ethics monitor was also appointed under the terms of an administrative agreement reached with the US Environmental Protection Agency in 2014. Under the terms of both agreements, we are taking additional actions to further enhance ethics and compliance across BP and the safety of our drilling operations in the Gulf of Mexico. The agreements have terms of five years and we are working closely with the monitors who will review ongoing progress until the agreements end. Caption: Monitoring activities at our office in Cairo, Egypt. 42 BP Annual Report and Form 20-F 2016Climate change Working with others, BP can help drive the transition to a lower carbon future. Calling for a price on carbon BP believes that carbon pricing by governments is the most comprehensive and economically efficient policy to limit GHG emissions. We assess how potential carbon policy could affect our businesses now and in the future. To help anticipate greater regulatory requirements for GHG emissions, we factor a carbon price into our own investment decisions and engineering designs for large new projects and those for which emissions costs would be a material part of the project. In industrialized countries, this is currently $40 per tonne of CO2 equivalent and we also stress test at a carbon price of $80 per tonne. Supplying natural gas Around half of BP’s upstream portfolio is currently natural gas, which produces about half as much GHG emissions as coal when burned to generate power. We have several new big gas projects coming onstream in the next few years including Khazzan in Oman, West Nile Delta and Zohr in Egypt, Juniper in Trinidad and the Southern Gas Corridor from the Caspian Sea to Europe. Providing renewable energy BP invests in renewable energy where we can build commercially viable businesses at scale. With a focus on biofuels and wind, we have the largest operated renewables business among our oil and gas peers. Pursuing efficient operations We are focusing on ways to reduce our GHG emissions. This includes looking to improve the energy efficiency of our operations and reducing flaring and methane emissions. Investing in start-ups and innovation Over the past decade, we have invested in start-up companies to help accelerate development and commercial viability of certain technologies. As at 31 December 2016, we had invested around $300 million in emerging technology companies – around half of these investments focus on low carbon solutions. Helping customers reduce their emissions BP provides an increasing number of lower carbon, energy-efficient and high-performance products to help our customers reduce their carbon footprint – from Castrol lubricants with lower viscosity, which helps manufacturers improve the efficiency of their vehicles – to PTAir – PTA with around a 30% lower carbon footprint than average European production. We are collaborating with others to help address this global challenge. As one example, the Oil and Gas Climate Initiative – currently chaired by our chief executive Bob Dudley – brings together 10 oil and gas companies working to reduce the GHG emissions from our industry’s operations and the use of our products. See bp.com/climatechange for more information. 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 emissionsab (MteCO2 equivalent) 55 50 45 49.0 0.3 G H G t c e r i d 5 1 0 2 s n o i t i s u q c A i -0.4 s t n e m t s e v D i 1.5 50.1 -0.3 s e g n a h c l a n o i t a r e p O l e b a n a t s u s i l a e R s n o i t c u d e r G H G t c e r i d 6 1 0 2 a This is based on BP’s equity share basis (excluding BP’s share of Rosneft). b A minor adjustment has been made from the reported 2015 figure of 48.9. Our direct GHG emissions are impacted year-on-year by changes in our portfolio and operations. For example, emissions can increase when we start up new projects or when we bring operations back online after planned maintenance. Both of these activities are essential for the safe performance and growth of BP’s portfolio. In 2016, the increase in our direct GHG emissions was primarily due to operational changes that include the start-up activities of the Sunrise oil sands project in Canada and the LNG plant in Angola. And one of our US refineries restarted operations following a planned shutdown for maintenance. Around a quarter of the increase is due to changes in how we calculate emissions. This increase has been partially offset by our ‘real sustainable reductions’ – these are actions taken by our businesses to permanently reduce their GHG emissions in areas such as flaring, methane and energy efficiency. We began tracking this in 2002, and the running total by the end of 2016 exceeded 9.1Mte. Greenhouse gas emissions (MteCO2e) Operational controla Direct emissions Indirect emissions BP equity sharec Direct emissions Indirect emissions 2016 2015 2014 51.4 6.2 50.1 6.2 51.2b 7.0 49.0d 6.9 54.1 7.5 48.7e 6.8 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. b A minor adjustment has been made from the reported 2015 figure of 51.4. c BP equity share comprises our share of BP’s consolidated entities and equity-accounted entities, other than BP’s share of Rosneft. d A minor adjustment has been made from the reported 2015 figure of 48.9. e A minor adjustment has been made from the reported 2014 figure of 48.6. The ratio of our total GHG emissions reported on an operational control basis to gross production was 0.24teCO2e/te production in 2016 (2015 0.24teCO2e/te, 2014 0.25teCO2e/te). Gross production comprises upstream production, refining throughput and petrochemicals produced. 43 BP Annual Report and Form 20-F 2016Strategic report – performance Value to society We aim to have a positive and enduring impact on the communities in which we operate. We contribute to economies through our core business activities, such as helping to develop the national and local supply base, and through the taxes we pay to governments. Additionally, our social investments support communities’ efforts to increase their incomes and improve standards of living. For example, in Egypt we support healthcare in the communities that are closest to our West Nile Delta project by funding emergency equipment for local hospitals. We run programmes to help build the skills of businesses and develop the local supply chain in a number of locations. In Angola, for example, we have supported the foundation of local businesses, providing community members with technical and hands-on training. Our enterprise and development programme in Azerbaijan helps local companies build their skills so that they can improve their competitiveness when bidding for work with international firms. We aim to recruit our workforce from the community or country in which we operate. At our Tangguh LNG plant in West Papua, Indonesia, more than half of our workforce is Papuan. This is a direct result of internship and apprentice programmes that focus on training graduates from Papua and Papua Barat. We are committed to reaching an 85% Papuan workforce by 2029. We contributed $61.1 million in social investment in 2016. See bp.com/society for more information on how we are maximizing value to society. Tax and financial transparency We contribute to economies around the world through the taxes that we pay. We paid $2.2 billion in income and production taxes to governments in 2016 (2015 $3.5bn, 2014 $8.0bn). BP is committed to complying with tax laws in a responsible manner and having open and constructive relationships with tax authorities. We participate in initiatives to simplify and improve tax regimes to encourage investment and economic growth. We also support efforts to increase public trust in tax systems. The Extractive Industries’ Transparency Initiative (EITI) supports disclosure of payments made to, and received by, government in relation to oil, gas and mining activity. As a member of EITI, BP works with governments, non-governmental organizations and international agencies to improve the transparency of payments to governments. BP discloses information on payments to governments for our upstream activities. We report on a country-by-country and project basis as required by UK regulation which incorporates the EU Accounting Directive. These payments could be made in the form of production entitlements, taxes, royalties, bonuses, fees and infrastructure improvements. We also make payments to governments in connection with other parts of our business – such as the transporting, trading, manufacturing and marketing of oil and gas. See bp.com/tax for our approach to tax and our payments to governments report. Human rights We strive to conduct 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 and our code of conduct. Through our code of conduct, employees are required to report any human rights abuse in either our operations or those of our business partners. 44 Caption: Operations at the Rumaila oil field in southern Iraq. We are working towards alignment with the UN Guiding Principles on Business and Human Rights by implementing our human rights policy. Our focus is on identifying and addressing human rights risks, including those associated with the recruitment and living conditions of contracted workforces on our sites, and on enhancing community grievance mechanisms and channels for workforces to raise their concerns. In 2016 our actions included: • Initiation of a review examining the risk of modern slavery, focusing on the parts of our business and supply chain where we believe there could be greater risk. • Development and piloting of a human rights due diligence process that can be used to screen suppliers in a consistent way anywhere in the world. • Evaluation of key sites’ community complaints mechanisms against the Guiding Principles to identify good practice and areas for improvement. • Continued implementation of the Voluntary Principles on Security and Human Rights, with periodic internal assessments to identify areas for improvement. See bp.com/humanrights for more information about our approach to human rights. Local environmental impacts We work to avoid, minimize and mitigate environmental impacts from our activities. We consider local conditions when determining which issues would benefit from the greatest focus. At a site close to communities, for example, the immediate concern may be air quality, whereas a remote desert site may require greater consideration of water management issues. Water BP recognizes the importance of managing freshwater use and water discharges in our operations and we review our water risks annually. We consider the local environment and quantity, quality and regulatory impacts. We assess different approaches for optimizing water consumption and wastewater treatment performance. For example, at our Khazzan operation in Oman, we treat wastewater from our sewage treatment plant and re-use it for irrigation, road construction and dust suppression, reducing freshwater demand in an area of water scarcity. BP Annual Report and Form 20-F 2016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 Germany and the US. Ethical conduct Our code of conduct defines our commitment to high ethical standards. See bp.com/water for information about our approach to water. Our values Air quality We put measures in place to manage our air emissions, in line with regulations and guidelines designed to protect the environment and the health of local communities. For example, our Whiting refinery is one of the largest refineries in the US, with the potential to have a significant impact on local air quality. We have reduced our air emissions there by more than 50% over the past five years by minimizing the amount of gas flared and emissions from process equipment. We monitor sulphur dioxide, hydrogen sulphide, benzene and other pollutants at the periphery of the refinery and make this data available on the refinery’s website. Unconventional gas and hydraulic fracturing 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 practices to mitigate these risks. For example, our wells are designed, constructed, operated and decommissioned to prevent gas and hydraulic fracturing fluids entering underground aquifers, such as drinking water sources. 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. At our Khazzan site in Oman we have built a central processing facility that reduces the need for processing equipment at each individual well site, which can be additional sources of methane emissions in gas production. 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. See bp.com/unconventionalgas for information about our approach to unconventional gas and hydraulic fracturing. Caption: Safety checks at Cherry Point refinery, US. Safety Respect Excellence Courage One Team 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 how we work at BP. It applies to all BP employees and members of the board. Employees, contractors or other third parties who have a question about our code of conduct or see something they feel is potentially unsafe, unethical or harmful can discuss these with their managers, supporting teams, works councils (where relevant) or through OpenTalk, a confidential helpline operated by an independent company. A total of 956 people contacted OpenTalk with concerns or enquiries in 2016 (2015 1,158, 2014 1,114). 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. We take steps to identify and correct areas of non-conformance and take disciplinary action where appropriate. In 2016 our businesses dismissed 109 employees for non-conformance with our code of conduct or unethical behaviour (2015 132, 2014 157). This excludes dismissals of staff employed at our retail service stations. See bp.com/codeofconduct for more information. 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 to the countries and communities in which we do business to be ethical and lawful in all our work. Our code of conduct explicitly prohibits engaging in bribery or corruption in any form. Our group-wide anti-bribery and corruption policy 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. 45 BP Annual Report and Form 20-F 2016Strategic report – performanceLobbying and political donations We prohibit the use of BP funds or resources to support any political candidate or party. We recognize the rights of our employees to participate in the political process. Their rights to do so are governed by the applicable laws in the countries in which we operate. For example, in the US we support the operation of the BP employee political action committee (PAC), which is a non-partisan committee that encourages voluntary employee participation in the political process. All BP employee PAC contributions are reviewed for compliance, comply with the law and are publicly reported in accordance with US election laws. The way in which we interact with governments depends on the legal and regulatory framework in each country. We engage across a range of issues that are relevant to our business, from regulatory compliance, to understanding our tax liabilities, to collaborating on community initiatives. Our people BP’s success depends on having a highly skilled and motivated workforce that reflects the societies where we operate. BP employees Number of employees at 31 Decembera Upstream Downstream Other businesses and corporate Total Service station staff Agricultural, operational and seasonal workers in Brazil Total excluding service station staff and workers in Brazil 2016 18,700 41,800 14,000 74,500 16,200 2015 21,700 44,800 13,300 79,800 15,600 2014 24,400 48,000 12,100 84,500 14,400 4,600 4,800 5,300 53,700 59,400 64,800 a Reported to the nearest 100. For more information see Financial Statements – Note 34. A lower oil price has meant that we have continued to adapt and reshape our organization. This has contributed to a reduction in overall headcount of 10,000 over the past two years. Our focus is on retaining the skills we require to maintain safe and reliable operations. The group people committee helps facilitate the group chief executive’s oversight of policies relating to employees. In 2016 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. Attracting and retaining the right people We prefer building capability and promoting people from within our organization and we complement this with selective external recruitment for specialist roles. We provide on-the-job learning and mentoring programmes, as well as online and classroom-based courses. Structured leadership courses help employees move into more senior positions. Our average expenditure on learning and development was around $4,000 per person in 2016 (2015 $4,000). We continued to invest in graduate recruitment and early career recruitment in 2016, albeit at a reduced level. A total of 231 global graduates joined BP in 2016 (2015 298, 2014 670). We are working to increase our visibility in the graduate job market and in 2016, students voted us the UK’s Most Popular Graduate Recruiter in the energy and utilities sector at the Target Jobs Sector Awards. Diversity We are a global company and aim for a workforce that is representative of the societies in which we operate. Our gender balance is steadily improving, with women representing 33% of BP’s population and 22% of group leaders – our most senior managers – at the end of 2016. Our aim is for women to represent at least 25% of group leaders by 2020. Following the retirement of our executive vice president of corporate business activities in 2016, we are considering how best to increase female representation at executive level. At the end of 2016 there were three female directors (2015 3, 2014 2) on our board. Our nomination committee remains mindful of diversity when considering potential candidates. For more information on the composition of our board, see page 65. Workforce by gender Numbers as at 31 December Board directors Group leaders Subsidiary directors All employees Male 11 308 1,056 50,200 Female 3 86 174 24,300 Female % 21% 22% 14% 33% We are also committed to increasing the national diversity of our workforce to reflect the countries in which we operate. A total of 26% of our group leaders came from countries other than the UK and the US in 2016 (2015 23%, 2014 22%). Inclusion Our goal is to create an environment of inclusion and acceptance, where everyone is treated equally 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, 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, training and occupational assistance where needed. 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 regularly communicate with employees on factors that affect company performance, and seek to maintain constructive relationships with labour unions formally representing our employees. Our annual employee survey found that confidence in the future of BP has risen to 64% in 2016 (2015 58%, 2014 63%), with solid improvements in pride in working for BP and trust in management. However, scores related to career opportunities, reward and recognition are not as high as we would like them to be and we will review actions to address these areas in 2017. 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. 46 BP Annual Report and Form 20-F 2016How we manage 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 49. 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: • Understand the risk environment, and assess the specific risks and potential exposure for BP. • Determine how best to deal with these risks to manage overall potential exposure. • Manage the identified risks in appropriate ways. • Monitor and seek assurance of the effectiveness of the management of these risks and intervene for improvement where necessary. • Report up the management chain and to the board on a periodic basis on how significant risks are being managed, monitored, assured and the improvements that are being made. Our risk management activities Day-to-day risk management Identify, manage and report risks Business and strategic risk management Plan, manage performance and assure Oversight and governance Set policy and monitor principal risks Facilities, assets and operations Business segments and functions Executive and corporate functions Board Day-to-day risk management – management and staff at our facilities, assets and functions seek to identify and manage risk, promoting safe, compliant and reliable operations. BP requirements, which take into account applicable laws and regulations, underpin the practical plans developed to help reduce risk and deliver 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 management into key business processes such as strategy, planning, performance management, resource and capital allocation, and project appraisal. We do this by using a standard framework for collating risk data, assessing risk management activities, making further improvements and 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 designed 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: Executive committees • Executive team meeting – for strategic and commercial risks. • Group operations risk committee – for health, safety, security, environment and operations integrity risks. • Group financial risk committee – for finance, treasury, trading and cyber risks. • Group disclosure committee – for financial reporting risks. • Group people committee – for employee risks. • Group ethics and compliance committee – for legal and regulatory compliance and ethics risks. • Resource commitment meeting – for investment decision risks. Board and its committees • BP board. • Audit committee. • Safety, ethics and environment assurance committee. • Geopolitical committee. 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 2017 are listed in this section. These may be updated throughout the year in response to changes in internal and external circumstances. The oversight and management of other risks is undertaken in the normal course of business 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 49. More information Risk management and internal control page 111. Board and committee reports page 64. See Glossary. 47 BP Annual Report and Form 20-F 2016Strategic report – performance Risks for particular oversight by the board and its committees in 2017 The risks for particular oversight by the board and its committees in 2017 have been reviewed and updated. These risks remain the same as for 2016. 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. 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. Cybersecurity The threats to the security of our digital infrastructure continue to evolve rapidly and, like many other global organizations, we rely on digital systems and network technology. 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. 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 48 continue to monitor threats globally and, in particular, the situation in the Middle East, North Africa and Europe. 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 plea agreement with the US government 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. 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. Encouraging employees to think before they click We rank cybersecurity as one of our highest priority risks. We deal with attempted cyber attacks on our business every day. Employees are our first line of defence against these attacks and we promote secure behaviours to help mitigate this growing risk. We focus on practical rules that we promote through films, e-learning and sessions delivered by senior managers and our digital security team. One of our rules addresses ‘phishing’, which is the attempt to trick people into revealing sensitive information and can involve installing malicious software to steal information without their knowledge. So we remind staff to ‘think before you click’ and be vigilant for phishing emails, calls and other suspicious requests for information and to report any such attempts to our digital security operations centre. We conduct ‘ethical phishing’ tests to educate our employees in this area. The number of employees who click on the links in the test emails has fallen by more than 70% since 2012. Over the same time, there has been a significant increase in the number of employees reporting the phishing tests. The programme is driving real change in awareness, but we remain vigilant as the threat continues to evolve. BP Annual Report and Form 20-F 2016Risk factors The risks discussed below, separately or in combination, could have a material adverse effect on the implementation of our strategy, our business, financial performance, results of operations, cash flows, liquidity, prospects, shareholder value and returns and reputation. Strategic and commercial risks Prices and markets – our financial performance is subject to fluctuating prices of oil, gas, refined products, technological change, exchange rate fluctuations, and the general macroeconomic outlook. Oil, gas and product prices are subject to international supply and demand and margins can be volatile. Political developments, increased supply from new oil and gas sources, technological change, global economic conditions and the influence of OPEC can impact supply and demand and prices for our products. Decreases in oil, gas or product prices could have an adverse effect on revenue, margins, profitability and cash flows. If significant or for a prolonged period, we may have to write down assets and re-assess the viability of certain projects, which may impact future cash flows, profit, capital expenditure and ability to maintain our long-term investment programme. Conversely, an increase in oil, gas and product prices may not improve margin performance as there could be increased fiscal take, cost inflation and more onerous terms for access to resources. The profitability of our refining and petrochemicals activities can be volatile, with periodic over-supply or supply tightness in regional markets and fluctuations in demand. Exchange rate fluctuations can create currency exposures and impact underlying costs and revenues. Crude oil prices are generally set in US dollars, while products vary in currency. Many of our major project development costs are denominated in local currencies, which may be subject to fluctuations against the US dollar. Access, renewal and reserves progression – our inability to access, renew and progress upstream resources in a timely manner could adversely affect our long-term replacement of reserves. Delivering our group strategy depends on our ability to continually replenish a strong exploration pipeline of future opportunities to access and produce oil and natural gas. Competition for access to investment opportunities, heightened political and economic risks in certain countries where significant hydrocarbon basins are located and increasing technical challenges and capital commitments may adversely affect our strategic progress. This, and our ability to progress upstream resources and sustain long-term reserves replacement, could impact our future production and financial performance. Major project delivery – failure to invest in the best opportunities or deliver major projects successfully could adversely affect our financial performance. We face challenges in developing major projects, particularly in geographically and technically challenging areas. Operational challenges and poor investment choice, efficiency or delivery at any major project that underpins production or production growth could adversely affect our financial performance. Geopolitical – we are exposed to a range of political developments and consequent changes to the operating and regulatory environment. We operate and may seek new opportunities in countries and regions where political, economic and social transition may take place. Political instability, changes to the regulatory environment or taxation, international sanctions, expropriation or nationalization of property, civil strife, strikes, insurrections, acts of terrorism and acts of war may disrupt or curtail our operations or development activities. These may in turn cause production to decline, limit our ability to pursue new opportunities, affect the recoverability of our assets or cause us to incur additional costs, particularly due to the long-term nature of many of our projects and significant capital expenditure required. Events in or relating to Russia, including further trade restrictions and other sanctions, could adversely impact our income and investment in Russia. Our ability to pursue business objectives and to recognize production and reserves relating to Russia could also be adversely impacted. Liquidity, financial capacity and financial, including credit, exposure – failure to work within our financial framework could impact our ability to operate and result in financial loss. Failure to accurately forecast, manage or maintain sufficient liquidity and credit could impact our ability to operate and result in financial loss. Trade and other receivables, including overdue receivables, may not be recovered and a substantial and unexpected cash call or funding request could disrupt our financial framework or overwhelm our ability to meet our obligations. An event such as a significant operational incident, legal proceedings or a geopolitical event in an area where we have significant activities, could reduce our credit ratings. This could potentially increase financing costs and limit 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 242 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, policies and obligations relating to climate change, including carbon pricing, could impact our assets, costs, revenue generation and strategic growth opportunities and demand for our products. 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. See Glossary. 49 BP Annual Report and Form 20-F 2016Strategic report – performance Insurance – our insurance strategy could expose the group to material uninsured losses. BP generally purchases insurance only in situations where this is legally and contractually required. Some risks are insured with third parties and reinsured by group insurance companies. Uninsured losses could have a material adverse effect on our financial position, particularly if they arise at a time when we are facing material costs as a result of a significant operational event which could put pressure on our liquidity and cash flows. Safety and operational risks Process safety, personal safety, and environmental risks – 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, extreme weather, 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 40. 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 sometimes conducted in extremely challenging environments which heighten the risks of technical integrity failure and the impact of natural disasters and extreme weather. The physical characteristics of an oil or natural gas field, and cost of drilling, completing or operating wells is often uncertain. We may be required to curtail, delay or cancel drilling operations because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions and compliance with governmental requirements. Security – hostile acts against our staff and activities could cause harm to people and disrupt our operations. Acts of terrorism, piracy, sabotage and similar activities directed against our operations and facilities, pipelines, transportation or digital infrastructure could cause harm to people and severely disrupt business and operations. Our activities could also be severely affected by conflict, civil strife or political unrest. Product quality – supplying customers with off-specification products could damage our reputation, lead to regulatory action and legal liability, and potentially impact our financial performance. Failure to meet product quality standards could cause harm to people and the environment, damage our reputation, result in regulatory action and legal liability, and impact financial performance. Compliance and control risks US government settlements – failure to comply with the terms of 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 or liabilities 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 and expose us to severe penalties, financial or otherwise, 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 imposed on similar 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. The Strategic report was approved by the board and signed on its behalf by David J Jackson, company secretary on 6 April 2017. 50 See Glossary. BP Annual Report and Form 20-F 2016Corporate governance C o r p o r a t e g o v e r n a n c e 52 Board of directors 58 Executive team 60 Executive management teams 62 Introduction from the chairman 63 Governance framework 63 Board and committee attendance 64 Board activity in 2016 64 Role of the board 65 Skills and expertise 65 Diversity 65 65 Appointment and time commitment 66 Training and induction 66 Board evaluation 67 Field visits Independence 68 Shareholder engagement Institutional investors 68 68 Private investors 68 AGM 68 UK Corporate Governance Code Compliance 68 International advisory board 69 Committee reports 69 Audit committee 74 76 Remuneration committee 78 Geopolitical committee 79 Chairman’s committee 79 Nomination committee Safety, ethics and environment assurance committee 80 Directors remuneration report 80 Letter from the remuneration committee chair 83 Summary of our pay and performance for 2016 84 Summary of our remuneration policy and approach for 2017 86 Features of 2017 policy 87 90 Single figure table for 2016 91 Pay and performance for 2016 95 Stewardship and regulatory information 101 2017 proposed policy Implementation of the 2017 policy 111 Directors’ statements 111 Statement of directors’ responsibilities 111 Risk management and internal control 112 Longer-term viability 112 Going concern 112 Fair, balanced and understandable BP Annual Report and Form 20-F 2016 51 Board of directors As at 6 April 2017 See BP’s board governance principles relating to director independence on page 266. Carl-Henric Svanberg Chairman Bob Dudley Group chief executive Dr Brian Gilvary Chief financial officer Chair of the nomination and chairman’s committees; attends SEEAa, remuneration and geopolitical committees Nils Andersen Independent non-executive director Member of the audit and chairman’s committees Paul Anderson Independent non-executive director Alan Boeckmann Independent non-executive director Admiral Frank Bowman Independent non-executive director Member of the SEEA, geopolitical and chairman’s committees Chair of SEEA committee; member of the remuneration, nomination and chairman’s committees Member of the SEEA, geopolitical and chairman’s committees Cynthia Carroll Independent non-executive director Member of the SEEA, geopolitical and chairman’s committees Ian Davis Independent non-executive director Member of the remuneration, geopolitical, nomination and chairman’s committees Professor Dame Ann Dowling Independent non-executive director Brendan Nelson Independent non-executive director Chair of the remuneration committee; member of the SEEA, nomination and chairman’s committees Chair of the audit committee; member of the chairman’s committee Paula Rosput Reynolds Independent non-executive director Member of the audit and chairman’s committees David Jackson Company secretary Sir John Sawers Independent non-executive director Chair of the geopolitical committee; member of the SEEA, nomination and chairman’s committees Andrew Shilston Senior independent non-executive director Senior independent director and member of the audit, remuneration, geopolitical, nomination and chairman’s committees 52 a Safety, ethics and environment assurance BP Annual Report and Form 20-F 2016Carl-Henric Svanberg Chairman Tenure Appointed 1 September 2009 Board and committee activities Chair of the nomination and chairman’s committees; attends the safety, ethics and environment assurance, remuneration and geopolitical committees Outside interests • Chairman of AB Volvo Age 64 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 December 2009, 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 chief executive officer and chairman to several high profile businesses, leading them through both periods of growth and restructuring. These experiences bring not only a deep understanding of international strategic and commercial issues, but the skills to co-ordinate the diverse range of knowledge and perspectives provided by the board. He therefore enables the board to present clear and united leadership on behalf of shareholders. Carl-Henric’s performance has been evaluated by the chairman’s committee, led by Andrew Shilston. Bob Dudley Group chief executive Tenure Appointed to the board 6 April 2009 Outside interests • Non-executive director of Rosneft • Member of the Tsinghua Management University Advisory Board, Beijing, China • Member of the BritishAmerican Business International Advisory Board • Member of the US Business Council • Member of the US Business Roundtable • Member of the 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 61 Nationality American and British 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 March 2013 following BP’s acquisition of a stake in Rosneft. C o r p o r a t e g o v e r n a n c e Relevant skills and experience Bob Dudley has spent his whole career in the oil and gas industry. During his tenure as group chief executive, Bob has transformed BP into a safer, stronger and simpler business. This approach, governed by a consistent set of values, has guided BP to a position of greater resilience, enabling it to continue delivering results in an uncertain economic environment. Bob has demonstrated excellent leadership and vision throughout this process and continues to develop the group’s strategy to adapt to new challenges ahead. Bob Dudley’s performance has been considered and evaluated by the chairman’s committee. Dr Brian Gilvary Chief financial officer Tenure Appointed 1 January 2012 Outside interests • Non-executive director of L’Air Liquide • Non-executive director of the Navy Board • Member of the 100 Group Committee • Visiting professor at Manchester University • GB Age Group triathlete Age 55 Nationality British Career Dr Brian Gilvary was appointed chief financial officer in January 2012. The role includes responsibility for tax, planning, treasury, mergers and acquisitions, investor relations and audit. He joined BP in 1986 after obtaining a PhD in mathematics from the University of Manchester. Following a variety of roles in 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 until 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 is also accountable for integrated supply and trading, global business services, information technology activities, procurement and shipping. 53 BP Annual Report and Form 20-F 2016 Relevant skills and experience Dr Brian Gilvary has spent his entire career with BP. His broad experience across the group has given him a deep insight into BP’s assets and businesses. This knowledge has been invaluable as BP has implemented its strategy to transform into a ‘value not volume’ based business and adapt to a low oil price environment. His strong understanding of finance and trading has been vital in adjusting capital structures and operational costs while ensuring the group continues to be capable of meeting new opportunities going forward. Brian Gilvary’s performance has been evaluated by the group chief executive and considered by the chairman’s committee. Nils Andersen Independent non-executive director Tenure Appointed 31 October 2016 Board and committee activities Member of the audit and chairman’s committees Outside interests • Non-executive director of Unilever Plc and Unilever NV • Chairman of Dansk Supermarked Group A/S Age 58 Nationality Danish Career Nils Andersen was group chief executive of A.P. Møller-Mærsk from 2007 to June 2016. Prior to this he was executive vice president of Carlsberg A/S and Carlsberg Breweries A/S from 1999 to 2001, becoming president and chief executive officer from 2001 to 2007. Previous roles include non-executive director of Inditex S.A. and William Demant A/S. He has also served as managing director of Union Cervecera, Hannen Brauerei and chief executive officer of the drinks division of the Hero Group. Nils received his graduate degree from the University of Aarhus. Relevant skills and experience Nils Andersen has extensive experience in consumer goods, retail and logistics, and leading global corporations with integrated operations worldwide. The skills and knowledge gained in these roles make him an ideal addition for the board given his experience in marketing, brand and reputation issues. His specialist logistics awareness also aligns with BP’s shipping business. His leadership in earlier roles was notable for the transformation of businesses through focused portfolios, leaner organizations and increasing competitiveness, as well as increasing transparency and communication with stakeholders. Nils’ economics and broad financial background make him well suited to his role on the audit committee. Paul Anderson Independent non-executive director Tenure Appointed 1 February 2010 Board and committee activities Member of the safety, ethics and environment assurance, geopolitical and chairman’s committees Outside interests No external appointments Age 72 Nationality American 54 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. His specific experience of driving safety-related cultural change throughout a business has been invaluable during his tenure as chair of the safety, ethics and environment assurance committee from 2012 to 2016, and he remains a valuable member of the committee. Paul’s experience of business in the US and its regulatory environment is a great asset to the geopolitical committee. Alan Boeckmann Independent non-executive director Tenure Appointed 24 July 2014 Board and committee activities Chair of the safety, ethics and environment assurance committee; member of the remuneration, nomination and chairman’s committees Outside interests • Non-executive director of Sempra Energy • Non-executive director of Archer Daniels Midland Age 68 Nationality American Career Alan Boeckmann retired as non-executive chairman of Fluor Corporation in February 2012, ending a 35-year career with the company. Between 2002 and 2011 he held the post of chairman and chief executive officer, having previously been president and chief operating officer from 2001 to 2002. His tenure with the company included responsibility for global operations. As chairman and chief executive officer, 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, the National Petroleum Council, the Eisenhower Medical Center 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 worked in a wide range of industries including engineering, construction, chemicals and in the energy sector. In his senior roles he directed the focus of global corporations towards the advanced technology needed to remain competitive in response to the growth of the internet, e-commerce and the globalization of the workforce. At the same time he actively promoted fairness, transparency, accountability and responsibility in business dealings at a time when many corporations were struggling with these issues. BP Annual Report and Form 20-F 2016 This experience as a chairman and chief executive makes Alan ideal to lead the SEEAC and brings added value to both the remuneration and nomination committees. Admiral Frank Bowman Independent non-executive director Tenure Appointed 8 November 2010 Board and committee activities Member of the safety, ethics and environment assurance, geopolitical and chairman’s committees Outside interests • President of Strategic Decisions, LLC • Director of Morgan Stanley Mutual Funds • Director of Naval and Nuclear Technologies, LLP Age 72 Nationality American Career Frank L Bowman served for more than 38 years in the US Navy, rising to the rank of Admiral. He commanded the nuclear submarine USS City of Corpus Christi and the submarine tender USS Holland. After promotion to flag officer, he served on the joint staff as director of political-military affairs and as the chief of naval personnel. He served over eight years as director of the Naval Nuclear Propulsion Program where he was responsible for the operations of more than 100 reactors aboard the US navy’s aircraft carriers and submarines. He holds two masters degrees in engineering from the Massachusetts Institute of Technology. After his retirement as an Admiral in 2004, he was president and chief executive officer of the Nuclear Energy Institute until 2008. He served on the BP Independent Safety Review Panel and was a member of the BP America External Advisory Council. He was appointed Honorary Knight Commander of the British Empire in 2005. He was elected to the US National Academy of Engineering in 2009. Frank is a member of the US CNA military advisory board and has participated in studies of climate change and its impact on national security, and on future global energy solutions and water scarcity. Additionally he was co-chair of a National Academies study investigating the implications of climate change for naval forces. Relevant skills and experience Frank Bowman’s exemplary safety record in running the US Navy’s nuclear submarine program indicates his deep understanding of process safety and its implementation in a widely dispersed workforce. Combined with his specific knowledge of BP’s safety goals from his work on the BP Independent Safety Review Panel, and his special interest in climate change, he brings a unique perspective to the board and the SEEAC. In addition, Frank’s experience of the US and global political and regulatory systems is a valuable asset to the geopolitical committee. Cynthia Carroll Independent non-executive director Tenure Appointed 6 June 2007 Board and committee activities Member of the safety, ethics and environment assurance, geopolitical and chairman’s committees Outside interests • Chair of Vedanta Resources Holding Ltd • Non-executive director of Hitachi Ltd • Advisory board member of America Securities LLC Age 60 Nationality American Career Cynthia began her career as a petroleum geologist with Amoco Production company in Denver, Colorado, after completing a masters degree in geology. In 1989 she joined Alcan (Aluminum Company of Canada) and ran a packaging company, led a global bauxite, alumina and speciality chemicals business and later was president and chief executive officer of the Primary Metal Group, responsible for operations in more than 20 countries. In 2007 she became chief executive of Anglo American plc, the global mining group, operating in 45 countries with 150,000 employees, and was chairman of De Beers s.a. and Anglo Platinum Limited. She stepped down from these roles in April 2013. Relevant skills and experience Cynthia Carroll is an experienced former chief executive who has spent all of her career in the extractive industries. Her leadership experience, related to enhancing safety in the mining industry, brings a strong contribution to the work of the SEEAC, as does her understanding of business strategy in an industry with a long capital return cycle. Her experience of leading large complex global businesses which require a high level of interaction with governments, the media and other stakeholders is an asset to both the board and the geopolitical committee. C o r p o r a t e g o v e r n a n c e Ian Davis Independent non-executive director Tenure Appointed 2 April 2010 Board and committee activities Member of the remuneration, geopolitical, nomination and chairman’s committees Outside interests • Chairman of Rolls-Royce Holdings plc • Non-executive director of Majid Al Futtaim Holding LLC • Non-executive director of Johnson & Johnson, Inc. • Non-executive director of Teach for All Age 66 Nationality British Career Ian Davis is senior partner emeritus of McKinsey & Company. He was a partner at McKinsey for 31 years until 2010 and served as chairman and managing director between 2003 and 2009. Ian has a MA in Politics, Philosophy and Economics from Balliol College, University of Oxford. Relevant skills and experience Ian Davis brings significant financial and strategic experience to the board. He has worked with and advised global organizations and companies in a wide variety of sectors including oil and gas and the public sector. This enables him to draw on knowledge of diverse issues and outcomes to assist the board and, in particular, the remuneration and nomination committees. He led the board’s oversight of the response in the Gulf and chaired the Gulf of Mexico committee from its formation until it was stood down in 2016. His previous role in the Cabinet Office gives him a unique perspective on government affairs which is an asset to both the board and the geopolitical committee. 55 Corporate governanceBP Annual Report and Form 20-F 2016 Professor Dame Ann Dowling Independent non-executive director Tenure Appointed 3 February 2012 Board and committee activities Chair of the remuneration committee; member of the safety, ethics and environment assurance, nomination and chairman’s committees Outside interests • President of the Royal Academy of Engineering • Deputy vice-chancellor and professor of Mechanical Engineering at the University of Cambridge • Member of the Prime Minister’s Council for Science and Technology • Non-executive director of the Department for Business, Energy and Industrial Strategy (BEIS) Age 64 Nationality British Career Dame Ann Dowling is a deputy vice-chancellor at the University of Cambridge where she was appointed a professor of mechanical engineering in the department of engineering in 1993. She was head of the department of engineering at the University from 2009 to 2014. Her research is in fluid mechanics, acoustics and combustion, and she has held visiting posts at MIT and at Caltech. She chairs BP’s technical advisory committee. Dame Ann is a fellow of the Royal Society and the Royal Academy of Engineering and a foreign associate of the US National Academy of Engineering and the French Academy of Sciences. She has honorary degrees from fifteen universities, including the University of Oxford, Imperial College London and the KTH Royal Institute of Technology, Stockholm. She was elected President of the Royal Academy of Engineering in September 2014 and in December 2015 was appointed to the Order of Merit. Relevant skills and experience Dame Ann is an internationally respected leader in engineering research and the practical application of new technology in industry. Her contribution in these fields has been widely recognized by universities around the world. Her academic background provides balance to the board and brings a different perspective to the SEEAC and nomination committee. Dame Ann became chair of the remuneration committee in 2015 and worked tirelessly over the past year to understand key issues with a large number of major shareholders and their advisers. Brendan Nelson Independent non-executive director Tenure Appointed 8 November 2010 Board and committee activities Chair of the audit committee; member of the chairman’s committee Outside interests • Non-executive director and chairman of the group audit committee of The Royal Bank of Scotland Group plc • Member of the Financial Reporting Review Panel Age 67 Nationality British Career Brendan Nelson is a chartered accountant. He was made a partner of KPMG in 1984. He served as a member of the UK board of KPMG from 2000 to 2006, subsequently being appointed vice chairman until his 56 retirement in 2010. At KPMG International he held a number of senior positions including global chairman, banking and global chairman, financial services. He served for six years as a member of the Financial Services Practitioner Panel and in 2013 was the president of the Institute of Chartered Accountants of Scotland. Relevant skills and experience Over the course of his career, Brendan Nelson has completed a wide variety of audit, regulatory and due-diligence engagements. He played a significant role in the development of the profession’s approach to the audit of banks in the UK with particular emphasis on establishing auditing standards. He continues to contribute in his role as a member of the Financial Reporting Review Panel. This wide experience makes him ideally suited to chair the audit committee and to act as its financial expert and he brings related input from his role as the chair of the audit committee of a major bank. His specialism in the financial services industry allows him to contribute insight into the challenges faced by global businesses by regulatory frameworks. Paula Rosput Reynolds Independent non-executive director Tenure Appointed 14 May 2015 Board and committee activities Member of the audit and chairman’s committees Outside interests • Non-executive director of BAE Systems Ltd • Non-executive director of TransCanada Corporation • Non-executive director of CBRE Group Age 60 Nationality American Career Paula Rosput Reynolds is the former chairman, president and chief executive officer of Safeco Corporation, a Fortune 500 property and casualty insurance company that was acquired by Liberty Mutual Insurance Group in 2008. She also served as Vice Chair and Chief Restructuring Officer for American International Group (AIG) for a period after the US government became the financial sponsor from 2008 to 2009. Previously, Paula was an executive in the energy industry. She was chairman, president and chief executive officer of AGL Resources Inc., an operator of natural gas infrastructure in the US, now a subsidiary of Southern Company. Prior to this, she led a subsidiary of Duke Energy Corporation that was a merchant operator of electricity generation. She commenced her energy career at PG&E Corp. Paula was awarded the National Association of Corporate Directors (US) Lifetime Achievement Award in 2014. Relevant skills and experience Paula Rosput Reynolds has had a long career leading global companies in the energy and financial sectors. Her financial background makes her ideally suited to serve on the audit committee. Her experience with international and US companies, including several restructuring processes and mergers, gives her insight into strategic and regulatory issues, which is an asset to the board. BP Annual Report and Form 20-F 2016 Sir John Sawers Independent non-executive director Tenure Appointed 14 May 2015 Board and committee activities Chair of the geopolitical committee; member of the safety, ethics and environment assurance, nomination and chairman’s committees Outside interests • Chairman and partner of Macro Advisory Partners LLP • Visiting professor at King’s College London • Governor of the Ditchley Foundation Age 61 Nationality British Career John Sawers spent 36 years in public service in the UK working on foreign policy, international security and intelligence. John was Chief of the Secret Intelligence Service, MI6, from 2009 to 2014, a period of international upheaval and growing security threats as well as closer public scrutiny of the intelligence agencies. Prior to that, the bulk of his career was in diplomacy, representing the British government around the world and leading negotiations at the UN, in the European Union and in the G8. He was the UK ambassador to the United Nations (2007-09), political director and main board member of the Foreign Office (2003-07), special representative in Iraq (2003), ambassador to Egypt (2001-03) and foreign policy advisor to the Prime Minister (1999-2001). Earlier in his career, he was posted to Washington, South Africa, Syria and Yemen. John is now chairman of Macro Advisory Partners, a firm that advises clients on the intersection of policy, politics and markets. Relevant skills and experience Sir John Sawers’ deep experience of international political and commercial matters is an asset to the board in navigating the complex issues faced by a modern global company. Sir John brings a unique perspective and broad experience which makes him ideal to lead the geopolitical committee. His knowledge and skills related to analysing and negotiating on a worldwide basis are invaluable to both the board and the SEEAC. Andrew Shilston Independent non-executive director Tenure Appointed 1 January 2012 Board and committee activities Senior independent director and member of the audit, remuneration, geopolitical, nomination and chairman’s committees Outside interests • Chairman of Morgan Advanced Materials plc • Non-executive director of Circle Holdings plc Age 61 Nationality British Career Andrew Shilston trained as a chartered accountant before joining BP as a management accountant. He subsequently joined Abbott Laboratories before moving to Enterprise Oil plc in 1984 at the time of flotation. In 1989 he became treasurer of Enterprise Oil and was appointed finance director in 1993. In 2003, after the sale of Enterprise Oil to Shell in 2002, he became finance director of Rolls-Royce plc until his retirement in December 2011. He has served as a non-executive director on the board of Cairn Energy plc where he chaired the audit committee. Relevant skills and experience Andrew Shilston is a highly knowledgeable director with wide experience in the oil and gas, energy and engineering industries. He has held several positions as a chief financial officer from which he brings detailed knowledge and skills to the audit and remuneration committees. His deep understanding of commercial issues has assisted the board in its work in overseeing the group’s strategy and his global expertise across several sectors is an asset to the geopolitical committee. As senior independent director he oversaw the evaluation of the chairman. David Jackson Company secretary Tenure Appointed 2003 David Jackson, a solicitor, is a director of BP Pension Trustees Limited. C o r p o r a t e g o v e r n a n c e The ages of the board are correct as at 6 April 2017. 57 Corporate governanceBP Annual Report and Form 20-F 2016 Executive team As at 6 April 2017 Tufan Erginbilgic Chief executive, Downstream Executive team tenure Appointed 1 October 2014 Outside interests • Independent non-executive director of GKN plc • Member of the Turkish-British Chamber of Commerce & Industry Board of Directors Age 57 Nationality British and Turkish Career Tufan Erginbilgic was appointed chief executive, Downstream on 1 October 2014. Prior to this, Tufan was the chief operating officer of the fuels business, accountable for BP’s fuels value chains worldwide, the global fuels businesses and the refining, sales and commercial optimization functions for fuels. Tufan joined Mobil in 1990 and BP in 1997 and has held a wide variety of roles in refining and marketing in Turkey, various European countries and the UK. In 2004 he became head of the European fuels business. Tufan took up leadership of BP’s lubricant business in 2006 before moving to head the group chief executive’s office. In 2009 he became chief operating officer for the eastern hemisphere fuels value chains and lubricants businesses. Bob Fryar Executive vice president, safety and operational risk Executive team tenure Appointed 1 October 2010 Outside interests No external appointments Age 53 Nationality American Career Bob Fryar is responsible for strengthening safety, operational risk management and the systematic management of operations across the BP group. He is group head of safety and operational risk, with accountability for group-level disciplines including engineering, health, safety, security, remediation management and the environment. In this capacity, he looks after the group-wide operating management system implementation and capability programmes. Bob has over 30 years’ experience in the oil and gas industry, having joined Amoco Production Company in 1985. Between 2010 and 2013, Bob was executive vice president of the production division, accountable for safe and compliant exploration and production operations and stewardship of resources across all regions. Andy Hopwood Executive vice-president, chief operating officer, strategy and regions, Upstream Executive team tenure Appointed 1 November 2010 Outside interests No external appointments Age 59 Nationality British Career Andy Hopwood is responsible for BP’s upstream strategy, portfolio and leadership of its global regional presidents. Andy joined BP in 1980, spending his first 10 years in operations in the North Sea, Wytch Farm and Indonesia. In 1989 Andy joined the corporate planning team formulating BP’s upstream strategy and subsequent portfolio rationalization. Andy held commercial leadership positions in Mexico and Venezuela before becoming the Upstream’s planning manager. Following the BP-Amoco merger, Andy spent time leading BP’s businesses in Azerbaijan, Trinidad & Tobago and onshore North America. In 2009 he joined the Upstream executive team as head of portfolio and technology and in 2010 was appointed executive vice president, exploration and production. Bernard Looney Chief executive, Upstream Executive team tenure Appointed 1 November 2010 Outside interests • Fellow of the Royal Academy of Engineering • Member of the Stanford University Graduate School of Business Advisory Council • Member of the Society of Petroleum Engineers Industry Advisory Council • Fellow of the Energy Institute Age 46 Nationality Irish Career Bernard Looney is responsible for the Upstream segment which consists of exploration, development and production. Bernard joined BP in 1991 as a drilling engineer, working in the North Sea, Vietnam and the Gulf of Mexico. In 2005 he became senior vice president for BP Alaska before becoming head of the group chief executive’s office in 2007. Prior to this, Bob was chief executive of BP Angola and also held several management positions in Trinidad, including chief operating officer for Atlantic LNG and vice president of operations. Bob has also served in a variety of engineering and management positions in onshore US and the deepwater Gulf of Mexico. In 2009 he became the managing director of BP’s North Sea business in the UK and Norway. At the same time, Bernard became a member of the Oil & Gas UK Board. He became executive vice president, developments, in October 2010, and in February 2013 became chief operating officer, production, serving in the role until April 2016. 58 BP Annual Report and Form 20-F 2016 Lamar McKay Deputy group chief executive Executive team tenure Appointed 16 June 2008 Outside interests No external appointments Age 58 Nationality American Career Lamar McKay is accountable for group strategy and long-term planning, safety and operational risk and group technology. In addition to supporting the group chief executive, he also focuses on various corporate governance activities including ethics and compliance. Lamar started his career in 1980 with Amoco and held a range of technical and leadership roles. During 1998 to 2000, he worked on the BP-Amoco merger and served as head of strategy and planning for the exploration and production business. In 2000 he became business unit leader for the central North Sea. In 2001 he became chief of staff for exploration and production, and subsequently for BP’s deputy group chief executive. Lamar became group vice president, Russia and Kazakhstan in 2003. He served as a member of the board of directors of TNK-BP between February 2004 and May 2007. In 2007 he was appointed executive vice president, BP America. In 2008 he became executive vice president, special projects where he led BP’s efforts to restructure the governance framework for TNK-BP. In 2009 Lamar was appointed chairman and president of BP America, serving as BP’s chief representative in the US. In January 2013, he became chief executive, Upstream, responsible for exploration, development and production, serving in the role until April 2016. Eric Nitcher Group general counsel Executive team tenure Appointed 1 January 2017 Outside interests No external appointments Age 54 Nationality American Career Eric Nitcher is responsible for legal matters across the BP group. Eric began his career in the late 1980s working as a litigation and regulatory lawyer in Wichita, Kansas. He joined Amoco in 1990 and over the years has held a wide variety of roles, both within and outside the US. In 2000, Eric moved to London to work in the mergers and acquisitions legal team where he played a key role in the formation of the Russian joint venture TNK-BP. Eric returned to Houston in 2007 where he served as special counsel and chief of staff to BP America’s chairman and president. Most recently he played a leading role in the settlement of the Deepwater Horizon government claims and resolution of most of the remaining private claims being litigated in New Orleans. C o r p o r a t e g o v e r n a n c e The executive team represents the principal executive leadership of the BP group. Its members include BP’s executive directors (Bob Dudley and Dr Brian Gilvary whose biographies appear on pages 53-54) and the senior management listed on these pages. The ages of the executive team are correct as at 6 April 2017. Dev Sanyal Chief executive, alternative energy and executive vice president, regions Executive team tenure Appointed 1 January 2012 Outside interests • Independent non-executive director of Man Group plc • Member of the Accenture Global Energy Board • Member of the Board of Advisors of the Fletcher School of Law and Diplomacy Age 51 Nationality British and Indian Career Dev Sanyal is responsible for alternative energy and for the Europe and Asia regions and functionally for risk management, government and political affairs, economics and policy. Dev joined BP in 1989 and has held a variety of international roles in London, Athens, Istanbul, Vienna and Dubai. He was general manager, Former Soviet Union and Eastern Europe, prior to being appointed chief executive, BP Eastern Mediterranean Fuels in 1999. In November 2003 he was appointed chief executive officer of Air BP International and in June 2006 was appointed head of the group chief executive’s office. He was appointed group vice president and group treasurer in 2007. During this period, he was also chairman of BP Investment Management Ltd and was accountable for the group’s aluminium interests. Until April 2016, Dev was executive vice president, strategy and regions. Helmut Schuster Executive vice president, group human resources Executive team tenure Appointed 1 March 2011 Outside interests • Non-executive director of Ivoclar Vivadent AG, Germany Age 56 Nationality Austrian Career Helmut Schuster became group human resources (HR) director in March 2011. In this role he is accountable for the BP human resources function. He completed his post graduate diploma in international relations and his PhD in economics at the University of Vienna and then began his career working for Henkel in a marketing capacity. Since joining BP in 1989 Helmut has held a number of leadership roles. He has worked in BP in the US, UK and continental Europe and within most parts of refining, marketing, trading and gas and power. Before taking on his current role, his portfolio of responsibilities as vice president, HR included the refining and marketing segment of BP and corporate and functions. That role saw him leading the people agenda for roughly 60,000 people across the globe that included businesses such as petrochemicals, fuels value chains, lubricants and functional experts across the group. He is also a non-executive director of BP Europa SE. 59 Corporate governanceBP Annual Report and Form 20-F 2016 Executive management teams Upstream (Pictured from left to right) James Dupree Chief operating officer, developments and technology Andy Hopwood Chief operating officer, strategy and regions Kerry Dryburgh Head of human resources Tony Brock Head of safety and operational risk Bernard Looney Chief executive (Standing, from left to right) Murray Auchincloss Chief financial officer Nigel Jones Associate general counsel Downstream (Standing, from left to right) Mike O’Sullivan Chief financial officer Mandhir Singh Chief operating officer, lubricants Paul Reed Chief executive officer, integrated supply and trading (to 31 December 2016) Rita Griffin Chief operating officer, petrochemicals Eva Bishop Associate general counsel 60 Alan Haywood Chief executive officer, integrated supply and trading (effective 1 January 2017) Doug Sparkman Chief operating officer, fuels, North America (Seated, from left to right) Angela Strank Head of technology Tufan Erginbilgic Chief executive Guy Moeyens Chief operating officer, fuels, Europe and Southern Africa Evelyn Gardiner Head of human resources Andy Holmes Chief operating officer, fuels ASPAC and Air BP BP Annual Report and Form 20-F 2016Alternative energy (Pictured from left to right) David Anderson Chief financial officer Catherine Green Human resources director Laura Folse Chief executive officer, wind Nick Wayth Chief development officer Mario Lindenhayn Chief executive officer, biofuels Joan Wales Head of safety and operational risk Dev Sanyal Chief executive C o r p o r a t e g o v e r n a n c e Functional leaders (Pictured from left to right) David Jardine Group head of audit Susan Dio Chief executive officer, shipping Ashok Pillai Vice president, group reward (Pictured from left to right) Jessica Mitchell Group head of investor relations Peter Henshaw Group head of communications and external affairs Dominic Emery Vice president, group strategic planning (Pictured from left to right) David Eyton Group head of technology Richard Hookway Chief operating officer of global business services and information technology and systems Kate Thomson Group treasurer Rahul Saxena Group ethics and compliance officer (Pictured from left to right) Eric Nitcher Group general counsel Jan Lyons Group head of tax Robert Lawson Global head of mergers and acquisitions Lucy Knight Human resources vice president, corporate business activities and functions 61 Corporate governanceBP Annual Report and Form 20-F 2016 Introduction from the chairman It is vital that we are responsive to all those with whom we come into contact through our business. Carl-Henric Svanberg Chairman can make a real difference in their home markets. The board of BP has for many years seen that its task is to create long-term value for shareholders. To do this it is vital that we are responsive to all those with whom we come into contact through our business. This includes shareholders, employees, customers and communities alike. This is a clear task of all companies and their boards. In the UK we are pleased to be able to work with the current government on their recent green paper on corporate governance reform. In 2016 the Gulf of Mexico committee met for the last time. The geopolitical committee, now chaired by Sir John Sawers, is getting into its stride and has proved its worth as the political environment has changed in a number of countries. It is important that we look to the future and ensure that how we work and what we discuss at our meetings is always directed at delivering BP’s strategy and maximizing performance in all areas. I am very grateful to Bob, his executive colleagues and my fellow directors for all the work that they have done over the year. And we are ready for what the future brings. Carl-Henric Svanberg Chairman The work of the board was challenging in 2016 as we had to focus on a number of distinct issues in a changing global environment. Despite this backdrop, it was a year however when the board continued to work well. 2015 saw the announcement of our settlement with a number of significant parties in the aftermath of the Deepwater Horizon accident. This was finally approved by the appropriate authorities in March 2016. This was a significant step that has allowed us to look forward. Your board spent significant time in 2016 in a series of briefings to understand the challenges of the transition to a lower carbon economy. And in February 2017 we communicated our refreshed strategy to investors. It defines how we see BP’s business evolving over the coming years. We are clear that a strong core business will be vital to our success in playing our part in the lower carbon transition over the coming years. The negative vote on remuneration at the 2016 AGM sent us a clear message. At that meeting Dame Ann and I said that we would listen and make further proposals for a new remuneration policy in 2017. Dame Ann and the remuneration committee have worked hard to ensure that we fully understand the views of our shareholders. They have also considered wider remuneration within BP and recognized the importance of engaging and retaining top executive talent throughout BP. We are putting forward the new policy at the 2017 AGM and believe it reflects a fair and balanced approach. The board recommends that shareholders approve it. It has been a lesson for the board and it is important for all of us that we regain the trust of shareholders and society. BP has come through many tests in the past years, and is a company with inner strength and is ready to continue playing its part in delivering light, heat and mobility to the societies in which we work. The role of business in society has become the focus of attention in many countries, not least the UK. BP is a global business. We cannot change that; indeed that is our strength. We believe that we can make a major contribution in demonstrating how global players 62 BP Annual Report and Form 20-F 2016 BP governance framework The board operates within a system of governance that is set out in the BP board governance principles. These principles define the role of the board, its processes and its relationship with executive management. This system is reflected in the governance of the group’s subsidiaries. See bp.com/governance for the board governance principles. Owners/shareholders BP board Nomination committee See page 79 Remuneration committee See page 76 Chairman’s committee See page 79 SEEAC See page 74 Geopolitical committee See page 78 Audit committee See page 69 D e l e g a t i o n Strategy/group risks/annual plan Group chief executive Group chief executive’s delegations Executive management Resource commitments meeting (RCM) Group people committee (GPC) Group disclosure committee (GDC) Group financial risk committee (GFRC) Group operations risk committee (GORC) Group ethics and compliance committee (GECC) Monitoring, information and assurance • Group audit • Finance • Safety and operational risk • Group ethics and compliance • Business integrity • External market and reputation research • Independent auditor • Independent adviser • Independent advice (if requested) y t i l i b a t n u o c c A C o r p o r a t e g o v e r n a n c e BP board governance principles: • BP goal • Governance process • Delegation model • Executive limitations Delegation Delegation of authority through policy with monitoring Accountability Assurance through monitoring and reporting Board and committee attendance in 2016 Board Audit committee SEEAC Joint audit/ SEEAC Remuneration committee Geopolitical committee Nomination committee Chairman’s committee Non-executive directors Carl-Henric Svanberg+ Nils Andersen Paul Anderson Alan Boeckmann+ Frank Bowman Antony Burgmans Cynthia Carroll Ian Davis Ann Dowling+ Brendan Nelson+ Phuthuma Nhleko Paula Rosput Reynolds John Sawers+ Andrew Shilston Executive directors Bob Dudley Brian Gilvary A 11 1 11 11 11 3 11 11 11 11 3 11 11 11 A 11 11 A 1 14 4 14 14 B 11 1 11 11 11 3 10 11 11 10 2 11 11 11 B 11 11 B A B A B A B 1 14 4 14 14 6 6 6 2 6 6 6 6 6 6 2 5 6 6 1 4 4 4 1 4 4 4 1 4 4 4 1 4 4 4 1 3 4 4 1 4 4 4 11 11 11 11 11 11 11 10 A 3 3 3 1 3 1 1 3 3 B 3 3 3 1 3 1 1 3 3 A 5 5 1 5 5 5 5 B 5 5 1 5 5 5 5 A 7 1 7 7 7 3 7 7 7 7 3 7 7 7 B 6 1 7 7 7 3 6 7 7 7 3 7 7 7 A = Total number of meetings the director was eligible to attend. B = Total number of meetings the director did attend. + Committee chair. Cynthia Carroll did not attend the board meeting on 26 May as she had to attend a family event. Brendan Nelson did not attend the board meeting on 6 December due to a conflict with an RBS board meeting. Phuthuma Nhleko did not attend the board meeting on 14 April due to urgent business in South Africa. Committee meeting attendance is noted in each committee report on pages 69-79. BP Annual Report and Form 20-F 2016 63 Board activity in 2016 Role of the board The board is responsible for the overall conduct of the group’s business. The directors have duties under both UK company law and BP’s Articles of Association. The primary tasks of the board include: Active consideration and direction of 1 long-term strategy and approval of the annual plan. Monitoring of BP’s performance against the strategy and plan. Ensuring that the principal risks and uncertainties to BP are identified and that systems of risk management and control are in place. Board and executive management succession. Strategy In 2016 the board worked with the executive team to understand the potential evolution of the markets in which the company operates. It also considered the implications of a transition to a low carbon economy. At its September meeting the board spent two days discussing with the executive team their proposals for the strategic direction of the group in the short, medium and longer term. The board discusses progress in delivering these strategic aims on a regular basis. During the year, the board has monitored the company’s performance against the annual plan for 2016 and also set the terms for the annual plan in 2017. Risk The board, either directly or through its committees, regularly reviews the processes whereby risks are identified, evaluated and managed. Activities include: • assessing the effectiveness of the group’s system of internal control and risk management • identification and allocation of risks to the board and monitoring committees (the audit, SEEA and geopolitical committees) for 2016, and confirmation of the schedule for oversight. 64 The board reviewed the BP Energy Outlook, updated in January 2017, which looks at long-term energy trends and develops projections for world energy markets over the next two decades. Following the approval of the Consent Decree order by the US court, the Gulf of Mexico committee was stood down at the end of the first quarter of 2016. Updates on the remaining proceedings are being given directly to the board or other committees as appropriate. Finally, the board has had regular discussions on the development of a new remuneration policy. Group risks reviewed by the board during 2016 included: • financial resilience (which examines how the group is able to respond to a volatile oil and gas price environment) • cybersecurity (with the audit committee and SEEAC reviewing elements of cybersecurity risk in their work over the year). These remain unchanged for 2017. The group risks allocated to the committees for review over the year are outlined in the reports of the committees on pages 69-79. Further information on BP’s system of risk management is outlined in How we manage risk on page 47. Information about BP’s system of internal control is on page 111. Performance and monitoring The board reviews financial and operational performance at each meeting. It receives regular updates on the group’s performance for the year across a range of metrics as well as the latest view on expected full-year delivery against external scorecard measures. Updates are also given on various components of value delivery for BP’s business. Regular reports presented to the board include: • Chief executive’s report • Group performance report • Group financial outlook • Effectiveness of investment review Succession The board, in conjunction with the nomination and chairman’s committees, reviews succession plans for executive and non- executive directors on a regular basis. The board needs to ensure that potential candidates are identified and evaluated as current directors reach the end of their recommended term of office, including in the event of a director needing to leave unexpectedly. The board employs executive search firms when it concludes that this is an effective way of finding suitable candidates. In 2016 we appointed Russell Reynolds Associates to assist in the search for non-executive directors. • Nils Andersen joined the board in October 2016 as a non- executive director. He is a member of the audit committee and the chairman’s committee. • Quarterly and full-year results • Shareholder distributions. The board reviews the quarterly and full-year results, including the shareholder distribution policy. Both the 2015 and 2016 annual reports were assessed in terms of the directors’ obligations and appropriate regulatory requirements. The board monitors employee opinion via an annual ’pulse‘ survey which includes measurement of how the BP values are incorporated into daily culture around our global operations. • Antony Burgmans and Phuthuma Nhleko, both non-executive directors, retired from the board at the AGM on 14 April 2016. • Sir John Sawers took the chair of the geopolitical committee following Antony Burgmans’ retirement. • Alan Boeckmann took the chair of the SEEAC, succeeding Paul Anderson who served as chair for four years. Mr Anderson continues as a member of the committee. • Ian Davis joined the geopolitical committee further to the departure of Antony Burgmans and Phuthuma Nhleko. • At the start of the year, Paul Anderson and Brendan Nelson stepped down from the nomination committee and Alan Boeckmann and Sir John Sawers joined. • Cynthia Carroll and Andrew Shilston will be standing down from the board at the 2017 AGM. • The board is proposing Melody Meyer for election as a director at the 2017 AGM. BP Annual Report and Form 20-F 2016Skills and expertise In order to carry out its duties on behalf of the shareholders, the board needs to manage its overall membership and continuously maintain its knowledge and expertise to benefit the business. It does this through four activity sets: Succession planning to ensure future diversity and balance Diversity including skills, experience, gender, ethnicity and tenure Training including site visits and induction of new directors Evaluation Background and diversity Director Background Oil & gas/ extractives/ energy Engineering/ technology Financial expertise Safety Brand/ marketing/ reputation Regulatory/ government affairs Diversity Female Non UK/US Tenure (years) C o r p o r a t e g o v e r n a n c e Nils Andersen Paul Anderson Alan Boeckmann Frank Bowman Cynthia Carroll Ian Davis Ann Dowling Brendan Nelson Paula Rosput Reynolds John Sawers Andrew Shilston Carl-Henric Svanberg 1 7 3 6 10 7 5 6 2 2 5 8 Diversity BP recognizes the importance of diversity, including gender, at the board and all levels of the group. We are committed to increasing diversity across our operations and have a wide range of activities to support the development and promotion of talented individuals, regardless of gender and ethnic background. The board operates a policy that aims to promote diversity in its composition. Under this policy, director appointments are evaluated against the existing balance of skills, knowledge and experience on the board, with directors asked to be mindful of diversity, inclusiveness and meritocracy considerations when examining nominations to the board. Implementation of this policy is monitored through agreed metrics. During its annual evaluation, the board considered diversity as part of the review of its performance and effectiveness. New diversity targets have been suggested by the Hampton-Alexander review in November 2016, to increase female representation on boards, executive committees and in the executive team direct reports by 2020. At the end of 2016, there were three female directors (2015 3, 2014 2) on our board of 14. Our nomination committee actively considers diversity in seeking potential candidates for appointment to the board. Independence Non-executive directors (NEDs) are expected to be independent in character and judgement and free from any business or other relationship that could materially interfere with exercising that judgement. It is the board’s view that all NEDs, with the exception of the chairman, are independent. The board is satisfied that there is no compromise to the independence of, and nothing to give rise to conflicts of interest for, those directors who serve together as directors on the boards of other entities or who hold other external appointments. The nomination committee keeps the other interests of the NEDs under review to ensure that the effectiveness of the board is not compromised. Appointment and time commitment The chairman and NEDs have letters of appointment. There is no term limit on a director’s service, as BP proposes all directors for annual re-election by shareholders (a practice followed since 2004). While the chairman’s appointment letter sets out the time commitment expected of him, letters of appointment for NEDs do not set a fixed- time commitment, but instead set a general guide of between 30-40 days per year. The time required of directors may fluctuate depending on demands of BP business and other events. They are expected to allocate sufficient time to BP to perform their duties effectively and make themselves available for all regular and ad hoc meetings. Executive directors are permitted to take up one external board appointment, subject to the agreement of the chairman. Fees received for an external appointment may be retained by the executive director and are reported in the annual report on remuneration (see page 97). Neither the chairman nor the senior independent director are employed as an executive of the group. 65 BP Annual Report and Form 20-F 2016 Training and induction To help develop an understanding of BP’s business, the board continues to build its knowledge through briefings and field visits. In 2016 the board received training on ethics and compliance and digital innovation. Activity following prior year audit An external evaluation was carried out at the end of 2015. Following a selection process led by the senior independent director, Bvalco was engaged as the external evaluator. The evaluation tested key areas of the board’s work including: • participation in the development of strategy • succession and composition • oversight of business performance, risk and governance processes. The effectiveness of the committees in alleviating the board’s overall oversight was also tested to establish whether this added value for the board. Results of the board evaluation and feedback from these interviews were discussed by the board at its meeting in January 2016, with the results of the chairman’s evaluation discussed by the chairman’s committee. Key conclusions of the evaluation included: • Ensuring an effective strategy process that focused on the long term and which acknowledged the important role of the board in this process. • Continued focus on succession for the board. • Building on the collaborative and inclusive environment to try and put more of the monitoring tasks into the committees to allow more time for broader discussions at the board. • Further steps should be taken to ensure that where appropriate all directors can access information and attend external visits for those committees of which they were not members. 2016 evaluation The evaluation was undertaken through a questionnaire facilitated by an external consultant (Lintstock) and individual interviews between the chairman and each director. The results of the evaluation and feedback from the interviews were collectively discussed by the board at its meeting in February 2017, with the results of the chairman’s evaluation discussed by the chairman’s committee. The evaluation concluded that the board felt its work and performance during the year had been positive. There had been an effective process to develop a refreshed strategy, and board discussions remained open and constructive. Actions arising from the evaluation in 2017 included: • Focus on implementing the strategy, in particular the opportunities relating to the transition to a lower carbon economy. • Continued emphasis on improving operational excellence. • Further examination of the financial performance of the business, in particular capital allocation and returns. • Obtaining a better understanding of the group’s ability to effectively deliver the strategy, including technology, digital and big data. • Bringing wider perspectives into the board room and gaining deeper insight into shareholder views. NEDs are expected to visit at least one business per year as part of their learning programme. In 2016 the board visited operations in Baku and Azerbaijan, and members of the SEEAC and other directors visited operations in Alaska, Colorado and Belgium. Newly appointed NEDs follow a structured induction process. This includes one-to-one meetings with management and the external auditors and also covers the board committees that they join. Director induction programme It was helpful to meet a wide range of company executives. Nils Andersen Non-executive director Nils Andersen, appointed in 2016, followed a tailored induction process, also covering the audit committee that he joined. The programme of topics included: Board and governance • BP’s board governance model, directors’ duties, interests and potential conflicts. Business introduction • BP’s business • Upstream (exploration, development, production, overview of our operations) • Downstream (refining, marketing and lubricants) • Strategy and planning • BP’s performance relative • Safety and operational risk (S&OR), BP’s operating management system (OMS) and environmental performance • Research and technology • Legal. Audit committee specific • Upstream and downstream finance • Tax • Oil and gas reserves accounting to its competitors. • Controls, accounting and Functional input • Human resources • Ethics and compliance reporting • External auditors and internal audit • Treasury and trading. Board evaluation BP undertakes an annual review of the board, its committees and individual directors. The chairman’s performance is evaluated by the chairman’s committee and his evaluation is led by the senior independent director. The evaluation operates on a three-year cycle, with one externally led evaluation followed by two subsequent years of internal evaluations carried out using a questionnaire prepared by an external facilitator. 66 BP Annual Report and Form 20-F 2016Field visits Non-executive directors are expected to visit at least one business per year, as part of their learning programme. In 2016 the board visited operations in Baku, Azerbaijan, and members of the SEEAC and other directors visited operations in Alaska, Colorado and Belgium. The board met local management during each visit, and after each one, the board or appropriate committee was briefed on the impressions gained by the directors during the visit. Lower 48, US Members of the SEEAC visited operations in Durango, Colorado in October. The visit was hosted by leadership of the Lower 48 business and included detailed reviews of production efficiency, operational management and safety and risk mitigation. Members saw the Florida gas plant and a number of well sites and a produced water storage and injection facility. There was a particular emphasis on the way in which the Lower 48 business is promoting safety through digital information sharing of incidents and leadership communications. Geel, Belgium Members of the SEEAC and other directors visited the petrochemicals plant in Geel, Belgium in December. They were shown key areas of the plant, in particular the paraxylene manufacturing facility. The visit also involved meetings with site leadership, and a review of safety-related incidents and trends. The outreach programme with the surrounding community was also discussed and commended. C o r p o r a t e g o v e r n a n c e Alaska, US Members of the SEEAC and other directors visited Anchorage and the North Slope in August. The visit to the North Slope included reviews of operations and flow stations as well as the central gas facility. They also visited pipelines and other critical infrastructure. Directors met local business and political leaders in Anchorage, as well as local BP leadership and other staff. second half of 2017. Subsequent installation and commissioning will take place at the field. Board members also met with site leadership and were given a detailed update on the Shah Deniz Stage 2 project as a whole. Baku, Azerbaijan The board visited the fabrication site for Shah Deniz Stage 2 topsides in Baku in May. Board members were given a tour of the topsides for the Shah Deniz Bravo production platform and the quarters and utilities platform. They reviewed progress of construction and discussed the safety record at the site – in particular the fact that more than 17 million safe man hours had been worked. They were informed that almost 90% of the workforce is Azerbaijani. The jackets for the platform are being constructed separately in Azerbaijan – with a projected sail away in the 67 BP Annual Report and Form 20-F 2016 Shareholder engagement Institutional investors The company operates an active investor relations programme and the board receives feedback on shareholder views through results of an anonymous investor audit and reports from management and those directors who meet with shareholders each year. In 2016 there was an enhanced programme of engagement by the chairman and the chair of the remuneration committee following the AGM. This is detailed in the remuneration committee report on page 76. Senior management regularly meets with institutional investors through roadshows, group and one-to-one meetings, events for socially responsible investors (SRIs) and oil and gas sector conferences throughout the year. In March the chairman and all board committee chairs held an annual investor event. This meeting enabled BP’s largest shareholders to hear about the work of the board and its committees and for NEDs to engage with investors. The chairman and members of the executive team met with SRIs as part of BP’s annual SRI meeting in November. The meeting examined a number of operational and strategic issues, including how the board looks at risk and strategy, the group’s approach to operational risk, context for the sector and BP in terms of oil price and energy supply and demand, operating and energy performance in the Upstream, and BP’s response to the shareholder resolution. See bp.com/investors for investor and strategy presentations, including the group’s financial results and information on the work of the board and its committees. Private investors BP held a further event for private investors in conjunction with the UK Shareholders’ Association (UKSA) in 2016. The chairman and head of investor relations made presentations on BP’s annual results, strategy and the work of the board. The shareholders asked questions on BP’s activities and performance. Shareholder engagement cycle 2016 Q1 • BP Energy Outlook presentation • Fourth quarter results • Investor roadshows with the group chief executive and chief financial officer • Chairman and board committee chairs meeting • UKSA private shareholders’ meeting • Institutional Investors Group on Climate Change (IIGCC) meeting • SRI roadshow following the launch of the BP Sustainability Report 2015, continuing into Q2 Q2 • Annual general meeting • First quarter results • Meetings with members of the Church Investors Group and Charities Responsible Investment Network • Upstream field trip to Baku, Azerbaijan • BP Statistical Review of World Energy launch • IIGCC meeting • Second quarter results • Investor roadshows with the group chief executive • Third quarter results • SRI annual meeting • IIGCC meeting More information Engagement on remuneration continued throughout the year See pages 76 and 80. Q3 Q4 68 AGM Voting levels increased slightly in 2016 to 64.28% (of issued share capital, including votes cast as withheld), compared to 62.28% in 2015 and 63.13% in 2014. All resolutions were passed at the meeting with the exception of the non-binding vote to receive the directors’ remuneration report. Each year the board receives a report after the AGM giving a breakdown of the votes and investor feedback on their voting decisions to inform the board on any issues arising. UK Corporate Governance Code compliance BP complied throughout 2016 with the provisions of the UK Corporate Governance Code except in the following aspects: B.3.2 Letters of appointment do not set out fixed-time commitments since the schedule of board and committee meetings is subject to change according to the demands of business and other events. Our letters of appointment set a general guide of a time commitment between 30-40 days per year. All directors are expected to demonstrate their commitment to the work of the board on an ongoing basis. This is reviewed by the nomination committee in recommending candidates for annual re-election. D.2.2 The remuneration of the chairman is not set by the remuneration committee. Instead the chairman’s remuneration is reviewed by the remuneration committee which makes a recommendation to the board as a whole for final approval, within the limits set by shareholders. This wider process enables all board members to discuss and approve the chairman’s remuneration, rather than solely the members of the remuneration committee. International advisory board BP’s international advisory board (IAB) advises the chairman, group chief executive and the board on geopolitical and strategic issues relating to the company. This group meets once or twice a year and between meetings IAB members remain available to provide advice and counsel when needed. The IAB is chaired by BP’s previous chairman, Peter Sutherland. Its membership in 2016 comprised Lord Patten of Barnes, Josh Bolten, President Romano Prodi, Dr Ernesto Zedillo and Dr Javier Solana. The chairman and chief executive attend meetings of the IAB. Issues discussed in 2016 included the global economy and in particular the effects of Brexit on the rest of the world, developments in political and economic reform in China, the political situation in Latin America and Turkey and the 2016 US election. BP Annual Report and Form 20-F 2016Committee reports Audit committee The committee has focused on the financial performance of the group in a challenging external environment over the year. Chairman’s introduction The committee has focused on the financial performance of the group in a challenging external environment over the year. Issues considered included the impact of weak commodity prices on oil and gas accounting judgements and asset carrying values and how changes in key long-term price assumptions impacted investment appraisals. A significant activity of the committee in 2016 was the tender of the external audit. I believe the tender process was thorough, open and transparent and I was pleased that the governance arrangements put in place enabled the committee to make a decision based on high quality proposals put forward by all the firms involved. Subject to approval by shareholders, we look forward to working with Deloitte as our new auditor from 2018. We thank EY for their strong professional standards and all they have done to provide assurance to the board during their time as BP’s auditor. Phuthuma Nhleko retired from the committee in April 2016. He brought thoughtfulness and challenge to the debate in the committee and I thank him for his contribution during his tenure. I welcome Nils Andersen who joined the committee in October 2016 and has commercial experience from a career in energy, shipping and consumer goods. I believe that the deep and varied experience of the committee members gives perspective and insight to our discussions with management. Brendan Nelson Committee chair Role of the committee The committee monitors the effectiveness of the group’s financial reporting, systems of internal control and risk management and the integrity of the group’s external and internal audit processes. Key responsibilities • Monitoring and obtaining assurance that the management or mitigation of financial risks is appropriately addressed by the group chief executive and that the system of internal control is designed and implemented effectively in support of the limits imposed by the board (‘executive limitations’) as set out in the BP board governance principles. • Reviewing financial statements and other financial disclosures and monitoring compliance with relevant legal and listing requirements. • Reviewing the effectiveness of the group audit function, BP’s internal financial controls and systems of internal control and risk management. • Overseeing the appointment, remuneration, independence and performance of the external auditor and the integrity of the audit process as a whole, including the engagement of the external auditor to supply non-audit services to BP. • Reviewing the systems in place to enable those who work for BP to raise concerns about possible improprieties in financial reporting or other issues and for those matters to be investigated. C o r p o r a t e g o v e r n a n c e Members Brendan Nelson Nils Andersen Phuthuma Nhleko Paula Reynolds Andrew Shilston Member since November 2010; chair since April 2011 Member since October 2016 Member from February 2011 to April 2016 Member since May 2015 Member since February 2012 Brendan Nelson is chair of the audit committee. He was formerly vice chairman of KPMG and president of the Institute of Chartered Accountants of Scotland. Currently he is chairman of the group audit committee of The Royal Bank of Scotland Group plc and a member of the Financial Reporting Review Panel. The board is satisfied that Mr Nelson is the audit committee member with recent and relevant financial experience as outlined in the UK Corporate Governance Code and competence in accounting and auditing as required by the FCA’s Corporate Governance Rules in DTR7. It considers that the committee as a whole has an appropriate and experienced blend of commercial, financial and audit expertise to assess the issues it is required to address, as well as competence in the oil and gas sector. The board also determined that the audit committee meets the independence criteria provisions of Rule 10A-3 of the US Securities Exchange Act of 1934 and that Mr Nelson may be regarded as an audit committee financial expert as defined in Item 16A of Form 20-F. Meetings and attendance There were 14 committee meetings in 2016, of which five were carried out by teleconference. All directors attended every meeting during the period in which they were committee members. Regular attendees at the committee meetings include the chief financial officer, group controller, chief accounting officer, group head of audit and external auditor. 69 BP Annual Report and Form 20-F 2016 proposals, the cost of capital and its application as a discount rate to evaluate long-term BP business projects, liquidity (including credit rating, hedging, long-term commercial commitments and credit risk) and the effectiveness and efficiency of the capital investment into major projects . The committee examined the group’s information technology risks and financial group risks, including taxation matters and the group’s process to assess, mitigate and monitor them. BP’s principal risks are listed on page 49. For 2017, the board has agreed that the committee will continue to monitor the same four group risks as for 2016. Other reviews Other reviews undertaken during 2016 by the committee included: • Upstream: including financial performance, strategy and how the Upstream finance function supports the segment. • Other businesses and corporate: including the various business and functional activities which constitute ‘Other businesses and corporate’ and how the group finance organization supports these activities and the broad framework of financial control. • Procurement: including BP’s procurement spend profile, key risks and controls. • Asset carrying values: insight into the group’s approach to reviewing asset carrying values for financial reporting purposes, particularly in the Upstream segment – including IFRS requirements and BP’s policies. • Financial metrics proposed for BP’s new remuneration policy: consideration of potential financial metrics for inclusion in the annual bonus and long-term incentive plan elements of the new policy. Internal control and risk management During the year the committee received quarterly reports on the findings of group audit. It reviewed the scope, activity and effectiveness of the group audit function, with a focus on how changes in the organizational structure had been implemented. In addition, the committee met privately with the group head of audit and key members of his leadership team. The audit committee also held private meetings with the group ethics and compliance officer during the year. Training The committee held learning events on the Modern Slavery Act and global trends in corporate fraud. It received technical updates from the chief accounting officer on developments in financial reporting and accounting policy, including IFRS 16, the new lease accounting standard. Activities during the year Financial disclosure The committee reviewed the quarterly, half-year and annual financial statements with management, focusing on: • Integrity and clarity of disclosure. • Compliance with relevant legal and financial reporting standards. • Application of critical accounting policies and judgements. The committee considered the BP Annual Report and Form 20-F 2016 and was delegated by the board to undertake final review and sign off of the document. The audit committee reviewed whether the Annual Report was fair, balanced and understandable Risk reviews The principal risks allocated to the audit committee for monitoring in 2016 included those associated with: Trading activities: including risks arising from shortcomings or failures in systems, risk management methodology, internal control processes or employees. In reviewing this risk, the committee focused on developments in the external market and how BP’s trading function had responded – including new areas of activity and impacts on the control environment. The committee further considered updates in the trading function’s risk management programme, including compliance with regulatory developments. Compliance with applicable laws and regulations: including ethical misconduct or breaches of applicable laws or regulations that could damage BP’s reputation, adversely affect operational results and/or shareholder value and potentially affect BP’s licence to operate. The committee reviewed key areas of BP’s ethics and compliance programme, including the integration of the 70 and provided the information necessary for shareholders to assess the group’s position and performance, business model and strategy. It made a recommendation to the board who in turn reviewed the report as a whole. The board’s review and conclusions are set out on page 112. Other disclosures reviewed included: • Oil and gas reserves. • Pensions and post-retirement benefits assumptions. • Viability statement. • Tax strategy. • Going concern. • Risk factors. • Legal liabilities. business integrity and ethics and compliance functions, development of the anti-bribery and corruption elements of the programme, enhanced policies, tools and training and strengthening of counterparty risk measures, including due diligence. Security threats against BP’s digital infrastructure: including inappropriate access to or misuse of information and systems and disruption of business activity. The committee reviewed changes in the cybersecurity landscape, including events in the energy, oil and gas industry and within BP itself. The review focused on the improvements made in managing cyber risk, including the application of the three lines of defence model and the committee examined indicators associated with risk management and barrier performance. Financial resilience: including the risk associated with external market conditions, supply and demand and prices achieved for BP’s products which could impact financial performance. The committee reviewed the key price assumptions used by the group for investment appraisal and the judgements underlying those BP Annual Report and Form 20-F 2016Accounting judgements and estimates During 2016, the committee was briefed on a quarterly basis on the group’s key accounting judgements and estimates and was also briefed in detail on various items during the course of the year. Areas of significant judgement considered by the committee during the year and how these were addressed included: Key issues/judgements in financial reporting Audit committee review and conclusions Oil and natural gas accounting BP uses judgement and estimations when accounting for oil and gas exploration, appraisal and development expenditure and in determining the group’s estimated oil and gas reserves. The committee reviewed judgemental aspects of oil and gas accounting such as intangible asset balances relating to exploration and appraisal activities and exploration write-offs as part of the company’s quarterly due-diligence process. The committee was also briefed on the year-end reserves process including governance and control activities. Recoverability of asset carrying values Determination as to whether and how much an asset is impaired involves management judgement and estimates on uncertain matters such as future pricing or discount rates. Judgements are also required in assessing the recoverability of overdue receivables and deciding whether a provision is required. The committee reviewed the discount rates for impairment testing as part of its annual process and examined the assumptions for future oil and gas prices and refining margins. The committee was briefed by management on any changes made to key assumptions during the year. The majority of the Upstream segment’s tangible assets were tested for impairment in 2016 and the group recorded a net impairment reversal of $1.9 billion for the year. The group’s long-term price assumptions for Brent National Balancing Point impairment testing was also reduced. gas were all reduced in 2016 and the discount rate used for oil, Henry Hub gas and UK Accounting for interests in other entities BP exercises judgement when assessing the level of control it has as a result of its interests in other entities and when determining the fair value of assets acquired and liabilities assumed. The committee monitored the position on any material overdue receivables and any associated provisions. The committee reviewed the judgement on whether the group has significant influence over Rosneft. The committee received reports from management and the external auditor which assessed the extent of significant influence, including BP’s participation in decision making through the election of two BP directors to the Rosneft board and ongoing work on significant transactions and projects. The committee was briefed on the accounting for transactions during the year including the dissolution of the joint operation with Rosneft and the disposal of BP’s Norwegian upstream business in exchange for an interest in Aker BP. Derivative financial instruments BP uses judgement when estimating the fair value of some derivative instruments in cases where there is an absence of liquid market pricing information – for example, relating to integrated supply and trading (IST) activities. The committee received a briefing on the group’s trading risks including the valuation of derivative instruments using models where observable market pricing is not available. The committee also visited the BP trading floor in London and received detailed presentations on the prevention of erroneous or fraudulent trades, carbon trading and BP‘s oil trading activities. Provisions and contingencies BP’s most significant provisions relate to decommissioning, the Gulf of Mexico oil spill, environmental remediation, litigation and tax. Provisioning for, and the disclosure of contingent liabilities relating to the Gulf of Mexico oil spill was discussed with the committee each quarter as part of the review of the Stock Exchange Announcement. The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. Most of these decommissioning events are in the long term and the requirements that will have to be met when a removal event occurs are uncertain. Judgement is applied by BP in relation to settlement dates, technology and legal requirements, among other factors. The committee discussed the provisions established in the second quarter as a result of the judgement that a reliable estimate could be made for all remaining material liabilities arising from the Gulf of Mexico oil spill. Revisions to existing provisions were also reviewed by the committee. The committee received briefings on the group’s decommissioning, environmental remediation and litigation provisioning, including key assumptions used, the governance framework applied (covering accountabilities and controls), discount rates and the movement in provisions over time. Pensions and other post-retirement benefits Accounting for pensions and other post-retirement benefits involves judgement about uncertain events, including discount rates, inflation and life expectancy. Taxation Computation of the group’s tax expense and liability, the provisioning for potential tax liabilities and the level of deferred tax asset recognition are underpinned by management judgement. The committee examined the assumptions used by management as part of its annual reporting process. The committee reviewed the judgements exercised on tax provisioning as part of its annual review of key provisions and was briefed on any material changes to deferred tax asset recognition. See Glossary. 71 Corporate governanceBP Annual Report and Form 20-F 2016Auditor appointment and independence The committee considers the reappointment of the external auditor each year before making a recommendation to the board. The committee assesses the independence of the external auditor on an ongoing basis and the external auditor is required to rotate the lead audit partner every five years and other senior audit staff every seven years. The current lead partner has been in place since the start of 2013. No partners or senior staff associated with the BP audit may transfer to the group. Non-audit services The audit committee is responsible for BP’s policy on non-audit services and the approval of non-audit services. Audit objectivity and independence is safeguarded through the limitation of non-audit services to tax and audit-related work which falls within defined categories. BP’s policy on non-audit services states that the auditors may not perform non-audit services that are prohibited by the SEC, Public Company Accounting Oversight Board (PCAOB), UK Auditing Practices Board (APB) and the UK Financial Reporting Council (FRC). The audit committee approves the terms of all audit services as well as permitted audit-related and non-audit services in advance. The external auditor is only considered for permitted non-audit services when its expertise and experience of the company is important. For all other services which fall under the ‘permitted services’ categories, approval above a certain financial amount must be sought on a case-by-case basis. Any proposed service not included in the permitted services categories must be approved in advance either by the audit committee chairman or the audit committee before engagement commences. The audit committee, chief financial officer and group controller monitor overall compliance with BP’s policy on audit-related and non-audit services, including whether the necessary pre-approvals have been obtained. The categories of permitted and pre-approved services are outlined in Principal accountants’ fees and services on page 268. In response to the revised regulatory guidelines of the FRC, the committee reviewed and updated its policies with effect from 1 January 2017. Changes included: • Adoption of the FRC’s prohibited non-audit services list. • Prohibition of all non-audit tax services by the audit firm from 2017 onwards. • Reduction of the pre-approval requirements for non-audit services in line with FRC guidance on how ’non-trivial‘ engagements with the audit firm should be pre-approved by the audit committee. External audit Audit risk The external auditor set out its audit strategy, identifying key risks to be monitored during the year. These included: • Determining the liabilities, contingent liabilities and disclosures arising from the Gulf of Mexico oil spill. • Estimating oil and gas reserves and resources which has significant impact on the financial statements, particularly impairment testing and the calculation of depreciation, depletion and amortization. • Monitoring for unauthorized trading activity within the trading function and its potential impact on the group’s results. • The potential of the macroeconomic environment to materially impact the carrying value of the group‘s upstream non-current assets. The committee received updates during the year on the audit process, including how the auditor had challenged the group’s assumptions on these issues. Audit fees The audit committee reviews the fee structure, resourcing and terms of engagement for the external auditor annually. Fees paid to the external auditor for the year were $47 million (2015 $51 million), of which 4% was for non-audit assurance work (see Financial statements – Note 35). The audit committee is satisfied that this level of fee is appropriate in respect of the audit services provided and that an effective audit can be conducted for this fee. Non-audit or non-audit related assurance fees were $2 million (2015 $3 million). The $1-million reduction in non-audit fees relates primarily to a reduction in the amount of fees for other assurance services and services relating to corporate finance transactions. Non-audit or non-audit related services consisted of tax compliance services and other assurance services. Audit effectiveness The effectiveness of the audit process was evaluated through separate surveys for the committee members and those BP personnel impacted by the audit, including chief financial officers, controllers, finance managers and individuals responsible for accounting policy and internal controls over financial reporting. The surveys used a set of criteria to measure the auditor’s performance against the quality commitment set out in their annual audit plan, including: • Robustness of the audit process. • Independence and objectivity. • Quality of delivery. • Quality of people and service. • Value added advice. Overall the 2016 evaluation concluded that the external auditor performance had either improved or remained largely constant in key areas compared to the previous year. Areas with high scores included quality of delivery of the audit and technical knowledge and expertise. A key area of focus from 2015 regarded liaison between BP’s own audit function and the external auditors. Actions taken over the year resulted in an improvement in scoring for the 2016 survey. Results of the annual assessment exercise were discussed with the external auditor who considered these themes for the 2016 audit service approach. The committee held private meetings with the external auditor during the year and the committee chair met separately with the external auditor and group head of audit before each meeting. 72 BP Annual Report and Form 20-F 2016Audit tendering The audit committee announced its intention to launch a competitive audit tender process in BP’s 2013 annual report. The tender process took place in 2016, with a view to appointing a new external auditor for the 2018 financial year. The new audit appointment will be with effect from 2018 to facilitate an orderly and thorough handover from the existing auditor and to ensure that the new auditor meets all relevant independence criteria before the commencement of the appointment. Governance The audit committee was responsible for the operation of the audit tender process, for making a report on the evaluation of the proposals received during the tender process to BP’s board and for recommending two firms of auditors to the board together with the audit committee’s preference between those two firms and its reasons for that preference. Evaluation Prior to the RFP being formally launched, briefing meetings were held with each firm covering key BP segments, functions and geographies; in addition the audit committee held introductory meetings with the lead and senior partners from each firm. In preparation for the tender, BP sought assurance that each firm would be capable of being independent in the time frame required by applicable law or regulation before being appointed auditor. The due-diligence activities conducted as part of the tender included a review of firm independence. The proposals from the three firms were evaluated by the audit committee against the following criteria, as well as the combined performance as a whole: • Audit quality. • Business knowledge. The governance model established by the audit committee to manage and support the tender constituted three key groups: • People, behaviours and cultural fit. Responsibility Members • Planning and project management, including transition. • Innovation and insight. • Independence. • Commercial and contractual structure. Executive advisory panel • Assess the firms’ proposals. • Investigate aspects of capability. • Present a findings report to the audit committee. Governance board • Govern the day-to-day running of the tender process. • Oversee the execution of the tender. • Ensure the goals set for the tender by the audit committee are met. • Gather information about the proposals and communicate to the committee. Tender project team • Liaison with the bidding firms. • Logistical support to the tender. • Support for executive advisory panel and governance board. Chief financial officers of BP’s business segments and heads of its financial functions and group head of audit. At the request of the audit committee chair, the commercial and contractual structure elements were assessed separately from the other aspects of the firms’ proposals. Evaluation of the proposals was conducted on a ‘fee blind’ basis. Chaired by the group controller, with representatives from internal functions including indirect procurement, legal, group control and financial reporting. Representatives from the finance and procurement functions. Following completion of the evaluation, the audit committee recommended two firms to the board for approval, with a stated preference for Deloitte. The audit committee believe that Deloitte has a strong team with the skills and experience to provide rigour and challenge in the audit. After considering the audit committee’s recommendation, the board selected Deloitte as BP’s auditor for the financial year ending 31 December 2018 subject to the approval of shareholders at the 2018 annual general meeting. BP has complied throughout 2016 with the Statutory Audit Services Order 2014, issued by the Competition and Markets Authority. Committee evaluation The audit committee undertakes an annual evaluation of its performance and effectiveness. 2016 evaluation For 2016 an internal questionnaire was used to evaluate the work of the committee. The review concluded that the committee had performed effectively. Priorities for 2017 include a review of and visit to BP’s global business service centres, focus on streamlining committee materials and further scrutiny on risk management when undertaking business or functional reviews. In delegating the day-to-day running of the tender process to the governance board, the audit committee asked that the tender be designed to implement a robust process to enable the selection of an auditor that would be the best fit for the role of external auditor based on the evaluation criteria agreed by the audit committee and provide the appropriate level of assurance to BP’s shareholders. Assessment criteria An assessment was undertaken to identify which firms would be reasonably likely to be capable of performing the audit and invited to participate in the tender; this assessment considered: • Sector experience. • Size and geographical presence. • Extent and nature of existing non-audit services work with BP. Based on this assessment, three firms were shortlisted to receive the formal tender request for proposal (RFP). EY, BP’s existing auditor was not invited to participate due to the legal requirement for BP to rotate its auditor by 2020. 73 Corporate governanceBP Annual Report and Form 20-F 2016Role of the committee The role of the SEEAC is to look at the processes adopted by BP’s executive management to identify and mitigate significant non-financial risk. This includes monitoring the management of personal and process safety and receiving assurance that processes to identify and mitigate such non-financial risks are appropriate in their design and effective in implementation. Key responsibilities The committee receives specific reports from the business segments as well as cross-business information from the functions. These include, but are not limited to, the safety and operational risk function, group audit, group ethics and compliance, business integrity and group security. The SEEAC can access any other independent advice and counsel it requires on an unrestricted basis. The SEEAC and audit committee worked together, through their chairs and secretaries, to ensure that agendas did not overlap or omit coverage of any key risks during the year. Members Alan Boeckmann Paul Anderson Frank Bowman Cynthia Carroll Ann Dowling John Sawers Member since September 2014 and chair since May 2016 Member since February 2010 Member since November 2010 Member since June 2007 Member since February 2012 Member since July 2015 Meetings and attendance There were six committee meetings in 2016. All directors attended every meeting for which they were eligible, with the exception of Cynthia Carroll who did not attend the committee meeting on 14 December due to a conflicting external board meeting. In addition to the committee members, all SEEAC meetings were attended by the group chief executive, the executive vice president for safety and operational risk (S&OR) and the head of group audit or his delegate. The external auditor attended some of the meetings and was briefed on the other meetings by the chair and secretary to the committee. The group general counsel and group ethics and compliance officer also attended some of the meetings. At the conclusion of each meeting the committee scheduled private sessions for the committee members only, without the presence of executive management, to discuss any issues arising and the quality of the meeting. Safety, ethics and environment assurance committee (SEEAC) The SEEAC has continued to monitor closely and provide constructive challenge to management in the drive for safe and reliable operations at all times. Chairman’s introduction The SEEAC has continued to monitor closely and provide constructive challenge to management in the drive for safe and reliable operations at all times. This included the committee receiving individual reports on the company’s management of highest priority group risks in marine, wells, pipelines, explosion or release at our facilities, and major security incidents. The committee also undertook a number of field visits (see page 67) as well as maintaining its schedule of regular meetings with executive management. A particular highlight was confirmation in January that all 26 of the Bly Report recommendations had been completed across the global wells organization (GWO). At the same time, we received the final report from Carl Sandlin, the independent expert we engaged in Upstream, in which he reported to the committee that such completion had occurred. Carl had provided valuable insights and advice to the GWO around safety in wells and process safety more generally, and we were grateful to him for his work. Paul Anderson stepped down as chair of the committee in May, having been the chair since 2012. I am grateful for the opportunity to chair the committee and we all wish to thank Paul for his service. Alan Boeckmann Committee chair 74 BP Annual Report and Form 20-F 2016Activities during the year System of internal control and risk management The review of operational risk and performance forms a large part of the committee’s agenda. Group audit provided reports on their assurance work on the system to inform the review. The committee also received regular reports from the group chief executive on operational risk, and from the S&OR function, including quarterly reports prepared for executive management on the group’s health, safety and environmental performance and operational integrity. These included quarter-by-quarter measures of personal and process safety, environmental and regulatory compliance and audit findings. The committee also received quarterly reports from group audit. In addition, the group ethics and compliance officer met in private with the chairman and other members of the committee over the course of the year. During the year the committee received separate reports on the company’s management of risks in: • Marine • Wells • Pipelines • Explosion or release at our facilities • Major security incidents • Cybersecurity (process control networks). The committee reviewed these risks and their management and mitigation in depth with relevant executive management. Independent expert – Upstream Mr Carl Sandlin completed his role as an independent expert in providing oversight regarding the implementation of the Bly Report recommendations. In January 2016, he reported to the committee that all 26 recommendations in the Bly Report had been completed by the end of 2015. We thank him for his work with the committee since 2012. Field trips In August the committee (and other directors) visited Alaska. The visit encompassed both the Anchorage office and a trip to review operations on the North Slope. In November they visited operations of the US Lower 48 business in Durango, Colorado. In December they visited the Geel petrochemicals facility in Belgium. In all cases, the visiting committee members and other directors received briefings Corporate reporting The committee is responsible for the overview of the BP Sustainability Report 2016. on operations, the status of conformance with the operating management system (OMS), key business and operational risks and risk management and mitigation. Committee members then reported back in detail about each visit to the committee and subsequently to the board. See page 67 for further details. The committee reviewed content and presentation, and worked with the external auditor with respect to their assurance of the report. Committee evaluation For its 2016 evaluation, the committee examined its performance and effectiveness through a questionnaire and interviews by external facilitators. Topics covered included the balance of skills and experience among its members, the quality and timeliness of information the committee receives, the level of challenge between committee members and management and how well the committee communicates its activities and findings to the board. The evaluation results continued to be generally positive. Committee members considered that they continued to possess the right mix of skills and background, had an appropriate level of support and received open and transparent briefings from management. All committee members emphasized that field trips remained an important element of its work, particularly because they gave committee members the opportunity to examine how risk management is being embedded in businesses and facilities, including management culture. Joint meetings between the committee and the audit committee were considered important in reviewing and gaining assurance around financial and operational risks where there was overlap between the committees, particularly in relation to ethics and compliance (see below). Joint meetings of the audit and safety, ethics and environment assurance committees During the year it was decided to hold standalone joint meetings of the audit committee and SEEAC on a quarterly basis in order to simplify reporting of key issues which were within the remit of both committees and make more effective use of the committees’ time. Each committee retains full discretion to require a further presentation and discussion on any joint meeting topic at their respective meeting if deemed appropriate. The committees jointly met four times during 2016, with chairmanship of the meetings alternating between the chairman of the audit committee and the chairman of the SEEAC. At these meetings the committee reviewed ethics and compliance and business integrity reports (including significant investigations and allegations), together with the annual ethics certification and the 2017 forward programmes for the group audit and ethics and compliance functions. See Glossary. 75 Corporate governanceBP Annual Report and Form 20-F 2016Remuneration committee After a comprehensive review of our directors’ remuneration and extensive shareholder engagement, we are presenting a clearer, simpler policy for shareholder approval. Chair’s introduction I am pleased to report on the work of the committee in 2016. This has been a challenging year following the loss of the vote on our remuneration report at the 2016 AGM. Since then our work has focused on engaging with shareholders, reflecting on their views, developing a new remuneration policy for the board, and on determining pay outcomes for 2016. Proposals for our new policy are set out in the Directors‘ remuneration report on pages 101-110. The policy will be put forward for approval by shareholders at the 2017 AGM. The committee’s membership and detailed activities over the year are contained in this part of the annual report. Professor Dame Ann Dowling Committee chair Role of the committee The role of the committee is to determine and recommend to the board the remuneration policy for the chairman and executive directors. In determining the policy the committee takes into account various factors, including structuring the policy to promote the long-term success of the company and linking reward and business performance. Key responsibilities The committee undertakes its tasks in accordance with applicable regulations, including those made from time to time under the Companies Act 2006, the UK Corporate Governance Code and the UK Listing Authority’s Listing Rules in relation to the remuneration of directors of quoted companies. • Determine the policy for the chairman and the executive directors (the policy) for inclusion in the remuneration policy for all directors. • Review and determine the terms of engagement, remuneration and termination of employment of the chairman and the executive directors as appropriate and in accordance with the policy, and be responsible for compliance with all remuneration issues relating to the chairman and the executive directors. 76 BP Annual Report and Form 20-F 2016 • Prepare the annual report to shareholders to show how the policy has been implemented, so far as it relates to the chairman and the executive directors. • Approve the principles of any equity plan that requires shareholder approval. • Approve the terms of the remuneration (including pension and termination arrangements) of the executive team as proposed by the group chief executive. • Approve changes to the design of remuneration, as proposed by the group chief executive, for the group leaders of the company. • Monitor implementation of remuneration for group leaders to ensure alignment and proportionality. • Engage such independent consultants or other advisers as the committee may from time to time deem necessary, at the expense of the company. Members Ann Dowling Alan Boeckmann Antony Burgmans Ian Davis Member since July 2012 and chair since May 2015 Member since May 2015 Member from May 2009 to April 2016 and chair from May 2011 to May 2015 Member since July 2010 Andrew Shilston Member since May 2015 Antony Burgmans stood down from the committee upon his retirement from the board in April 2016. Carl-Henric Svanberg and Bob Dudley attend meetings of the committee except for matters relating to their own remuneration. Bob Dudley is consulted on the remuneration of other executive directors and the executive team. Both executive directors are consulted on matters relating to the group’s performance. The group human resources director normally attends meetings and other executives may attend where necessary. The committee consults other board committees on the group’s performance and on issues relating to the exercise of judgement or discretion. Meetings and attendance The committee met 11 times during the year; twice before the AGM and on nine occasions since. All directors attended each meeting that they were eligible to attend, either in person or by telephone, with the following exceptions: • Antony Burgmans did not attend the meeting on 17 March due to a conflict with an external meeting. • Andrew Shilston did not attend the meeting on 21 June, scheduled at late notice, due to a prior commitment. Activities during the year In the months before the AGM, the committee focused on the outcomes for 2015. This involved reviewing directors’ salaries and the group’s performance outcome which in turn determined outcomes for the annual bonus and the Executive Directors’ Incentive Plan (EDIP). Following the negative vote on the Directors' remuneration report (DRR), the chairman and the chair of the remuneration committee made a commitment at the 2016 AGM to be responsive to shareholder feedback and to formulate a new policy for 2017. In all its discussions the committee has focused on the overall quantum of executive director remuneration and has sought to reflect the views of shareholders and the broader societal context in its decisions. Shareholder engagement There has been substantial engagement with shareholders during the year. This has been carried out primarily by the chair of the committee, with additional dialogue by the chairman and the company secretary. Engagement by the committee chair was aimed at understanding shareholders’ views on the company’s 2014 policy, testing proposals and seeking support for the new policy to be put to shareholders at the 2017 AGM. Meetings with proxy voting agencies have also taken place. In total, the remuneration committee chair has held 68 meetings or calls with investors and proxy advisers in the period from May 2016 to the 2017 AGM. These meetings were conducted to understand concerns, test strategic direction and present a refined policy. Committee evaluation An internally facilitated evaluation was undertaken in 2016 to examine the committee’s performance during the year. The evaluation concluded that the committee had conducted an effective review of a wide range of options when considering the new policy and was addressing effectively the balance of commercial and societal constraints. Focus areas for 2017 included maintaining oversight of stakeholder and investor views on remuneration, staying up to date with external developments and best practice, while managing the challenge of the transition between the 2014 and 2017 remuneration policies. C o r p o r a t e g o v e r n a n c e For the remainder of 2016 and into early 2017, the committee has focused on developing a new policy and then determining pay outcomes for 2016 (the final year of the 2014 policy). It examined the circumstances around the adverse vote and considered feedback from the engagement with shareholders. Committee focus after the AGM A detailed work plan for the committee was agreed for the year. The committee chair spoke to a number of the company’s larger shareholders shortly after the AGM and began a structured shareholder engagement programme in the UK and US. The committee decided that a new remuneration adviser should be appointed to assist with its work. After a competitive tender process Deloitte was appointed and has been working with the committee since May 2016. The committee, over the series of meetings: • Analysed the structure and operation of remuneration and compared it with prevailing and emerging best practice. • Considered a broad range of options in discussion with shareholders before distilling to two choices for full shareholder consultation. • Conducted a detailed review of the number, use and combination of performance measures to assess how they could be simplified while also supporting the business strategy. • Considered the quantum of incentives in the context of securing fair and commercial outcomes relative to senior colleagues. • Reviewed scenarios to improve alignment of remuneration outcomes with shareholder interests. • Conducted a final review of the proposed policy to ensure that it would continue to promote the company’s long-term business strategy. The committee has also considered the implications of the transition from the 2014 to the 2017 policies, in particular relating to share grants and pension. It also reviewed potential outcomes for 2016 at the end of the year. How did we develop the new policy? 1 2 3 4 5 Collate feedback Design and test Develop proposal Finalize policy Implement Remuneration policy review Listen Test outlines Present developing proposal Present final proposal and seek support at AGM – 17 May 2017 Shareholder dialogue throughout the whole process Spring 2016 Summer 2016 Autumn/winter 2016 AGM 2017 BP Annual Report and Form 20-F 2016 77 In 2016 Ian Davis joined the committee, Antony Burgmans and Phuthuma Nhleko left the committee on retirement from the board, and Sir John Sawers became the new chair. Carl-Henric Svanberg and Bob Dudley attend all committee meetings and the executive vice president, regions and the vice-president, government and political affairs attend as required. Meetings and attendance The committee met three times during the year. All directors attended each meeting that they were eligible to attend. Activities during the year The committee developed the work it had started in 2015 by considering issues that affect all BP’s key geographies, for example the continuing low oil price and BP’s investment approach. The implications of the UK referendum on Brexit and the US presidential election were discussed at each meeting. The committee considered the impact of geopolitical events on BP’s interests in the Middle East and in Egypt, Russia and Turkey. Committee evaluation The committee held its first review at the end of 2016, focusing on its processes and effectiveness. The review was undertaken through a questionnaire, with the committee discussing the output of the evaluation in a private session at its February 2017 meeting. The review concluded that while the committee was still evolving in terms of coverage and content, it had performed effectively. Areas of focus for 2017 included gaining greater insight and advice from advisers with direct political experience and placing emphasis on those regions and topics that would most impact BP’s business or reputation as a way of helping to ease time pressure on the committee’s agenda. Geopolitical committee Chairman’s introduction I am pleased to report on the work of the geopolitical committee in 2016. I thank Antony Burgmans for his work as chair of this committee in the first part of the year. Sir John Sawers Committee chair Role of the committee The committee monitors the company’s identification and management of geopolitical risk. Key responsibilities • Monitor the company’s identification and management of major and correlated geopolitical risk and consider reputational as well as financial consequences: – Major geopolitical risks are those brought about by social, economic or political events that occur in countries where BP has material investments that can be jeopardized. – Correlated geopolitical risks are those brought about by social, economic or political events that occur in countries where BP may or may not have a presence but that can lead to global political instability. • Review the company’s activities in the context of political and economic developments on a regional basis and advise the board on these elements in its consideration of BP’s strategy and the annual plan. Members John Sawers Paul Anderson Frank Bowman Antony Burgmans Cynthia Carroll Ian Davis Phuthuma Nhleko Member since September 2015 and chair since April 2016 Member since September 2015 Member since September 2015 Chair from September 2015 to April 2016 Member since September 2015 Member since September 2016 Member from September 2015 to April 2016 Andrew Shilston Member since September 2015 78 BP Annual Report and Form 20-F 2016Chairman’s and nomination committees Chairman’s introduction The chairman‘s and nomination committees have been actively involved in the evolution of the board and its work in 2016. Carl-Henric Svanberg Committees’ chair Chairman’s committee Role of the committee To provide a forum for matters to be discussed among the non- executive directors. Key responsibilities • Evaluate the performance and the effectiveness of the group chief executive. • Review the structure and effectiveness of the business organization. • Review the systems for senior executive development and determine succession plans for the group chief executive, executive directors and other senior members of executive management. • Determine any other matter that is appropriate to be considered by non-executive directors. • Opine on any matter referred to it by the chairman of any committees comprised solely of non-executive directors. Members The committee comprises all the non-executive directors. Directors join the committee immediately on their appointment to the board. The group chief executive attends meetings of the committee when requested. Meetings and attendance The committee met seven times in 2016. All directors attended every meeting for which they were eligible, with the exception of Cynthia Carroll who did not attend the meeting on 26 May as she had to attend a family event. The chairman did not attend the meeting on 28 January as it was for his evaluation. Activities during the year • Evaluated the performance of the chairman and the group chief executive. • Reviewed the evolution of the company’s strategy given anticipated market conditions over the coming decade and the approach adopted for the annual plan. • Assessed the prioritization of investment opportunities. • Considered succession plans for the senior executive team. Nomination committee Role of the committee The committee ensures an orderly succession of candidates for directors and the company secretary. Key responsibilities • Identify, evaluate and recommend candidates for appointment or reappointment as directors. • Identify, evaluate and recommend candidates for appointment as company secretary. • Keep the mix of knowledge, skills and experience of the board under review to ensure the orderly succession of directors. • Review the outside directorship/commitments of non-executive directors. Members Carl-Henric Svanberg Member since September 2009 and chair since January 2010 Alan Boeckmann Member since April 2016 Ann Dowling Ian Davis John Sawers Andrew Shilston Member since May 2015 Member since August 2010 Member since April 2016 Member since May 2015; attended meetings previously as senior independent director Alan Boeckmann and Sir John Sawers joined the committee in 2016. Paul Anderson and Brendan Nelson stood down, and Antony Burgmans left on his retirement from the board. Meetings and attendance The committee met five times during the year. All directors attended each meeting that they were eligible to attend. Activities during the year The committee continued to keep the composition and skills of the board under review. Cynthia Carroll and Andrew Shilston will be standing down from the board in 2017 and there will be further retirements in 2018. The committee focused on maintaining a strong group of current and former chief executives, while ensuring appropriate diversity in all forms. The committee appointed Nils Andersen, the former CEO of Maersk, to the board in October 2016. A search has been initiated for further candidates with the intent of maintaining the gender diversity on the board, and as a result the board is proposing Melody Meyer for election as a director at the 2017 AGM. The board as a whole considers succession planning and diversity as discussed on pages 64-65. Committee evaluation The evaluation concluded that the committee was generally working well. It was important to ensure that future work would be focused on building a board capable of governing the company as it implements its strategy towards 2021 and beyond. There should be a strong continued focus on diversity. 79 Corporate governanceBP Annual Report and Form 20-F 2016Directors’ remuneration report Letter from the remuneration committee chair After a thorough review and extensive shareholder engagement, we believe the new policy is simpler, transparent and has strategic focus. Professor Dame Ann Dowling Chair of the remuneration committee Dear shareholder, Last year’s AGM remuneration vote was a clear message about how we manage executive pay. We made a commitment to respond in a constructive way and have taken a comprehensive look at remuneration of our executive directors. We are proposing to make a number of significant changes to our remuneration policy for 2017 which will make it simpler, better align pay and performance, and lead to a reduced maximum award for the group chief executive (GCE) and the chief financial officer (CFO). We have held extensive dialogue with many of our largest shareholders as well as representative bodies beginning in May 2016 and running through to this year’s AGM. We have listened and sought to respond to their concerns. I would like to thank all those who took part in the process for their time and insight. It is clear that shareholders and other stakeholders would like our remuneration policy to be simpler, more transparent, and to lead to reduced levels of reward. There is also a wish to see the committee make greater use of discretion. BP is a global company with a global management team, competing for talent in a demanding environment. The company’s ability to attract and retain the high-calibre executives required to lead this complex business is important for shareholders. We are mindful of this and have tried to balance these commercial pressures with the wider social context when determining executive pay. Although we are still working under our 2014 policy, we have used some of the principles from our new policy in making our decisions for pay in 2016. We have considered the formulaic results and outcomes for shareholders and then exercised downward discretion to reach our final decisions. As a result – in a year of good performance and progress – Bob Dudley‘s total single figure for 2016 has been reduced by some 40% compared to last year. Future remuneration policy The proposed remuneration policy is designed to ensure a clear link between delivery of BP’s strategy and pay. Over the past year, there has been much debate in the UK regarding pay models. We appointed new independent advisers and approached our review with an open mind. We explored a number of different Key outcomes for 2016 Bob Dudley – total pay A year of progress and performance for the company. Total single figure in 2016 for Bob Dudley is $11.6 million – 40% lower than for 2015. $19.4m Committee discretion reduced pay by $2.2 million. Maximum opportunity for 2017 and beyond significantly reduced. $13.8m $11.6m 2015 2016 Formulaic outcome 2016 Outcome after committee discretion 80 BP Annual Report and Form 20-F 2016Directors’ remuneration report – overview remuneration structures before focusing on two for further consideration – restricted shares and performance shares. We consulted with shareholders and the board has reaffirmed its view that performance shares rather than restricted shares remain the appropriate structure at the current time as they align pay outcomes with long-term performance. Key changes From 2017, we propose a simplified approach with a significant reduction in overall remuneration levels. • We will operate only two incentive plans – a short-term annual bonus and a long-term performance share plan. • The maximum annual bonus will only be earned where stretch performance is delivered on every measure. • The level of bonus paid for an ‘on-target’ score will be reduced by 25%. • The bonus performance scale for executive directors will be the same as the wider professional and managerial employee population. • The proportion of annual bonus that must be deferred into shares will be increased from 33% to 50%. • Deferred shares will no longer be matched with additional shares. • The maximum longer-term incentives for the GCE will be reduced from seven times salary (previously granted as matching shares on the deferred annual bonus and performance shares) to a maximum of five times salary. Policy features In addition, the following features of the new policy support the group’s long-term strategic priorities, which are in the interests of all stakeholders: • A simplified performance assessment providing a clear link between the delivery of BP’s strategy, outcomes for shareholders and pay. • An annual bonus that rewards safety, reliable operations and financial performance during the year based on the annual plan. • For long-term performance share awards, performance will be tested and shares will vest after three years, but awards will not be released until the end of a further three-year period – a six-year period in total. This lengthy period reinforces the executive’s stewardship of the company. • Target ranges for total shareholder return (TSR) and return on average capital employed (ROACE) will be disclosed at the start of the performance period. For 2017 awards, these determine eighty per cent of the available performance shares. • The remainder of the performance shares will be based on strategic measures, including alignment with the company’s progress towards a lower carbon transition over the longer term. • Where appropriate, the committee will exercise its discretion in determining outcomes, which will include a broader consideration of outcomes for shareholders, safety and environmental performance. • Stronger malus and clawback provisions. • Minimum shareholding requirements of five times base salary will be maintained, and a significant portion of the new package will continue to be linked to performance and delivered in BP shares. It is expected that Bob Dudley and Dr Brian Gilvary will maintain a shareholding of at least 250% of salary for two years following retirement. How we responded to shareholders in developing our new policy 1 2 3 4 Simplification Reduced package versus 2014 policy Link to strategy Stewardship • Simpler package – fixed pay, bonus and long-term shares. • Removal of matching shares. • Maximum opportunity for long-term incentives has been significantly reduced from seven times to five times salary for the GCE. • On-target bonus reduced by 25%. • Clearer link between strategy and incentive targets. • Review of measures for bonus and long-term incentives. • TSR and ROACE targets disclosed in advance. • Five times salary shareholding requirements. • Post-retirement shareholding. • Safety and the environment remain important considerations. 81 BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – overview Performance and pay for 2016 Our full year results were good in the context of tough conditions; however the board recognizes the opportunity for further improvement. We have made considerable progress over the year on a number of the measures by which we judge our performance. We have executed our projects safely and more efficiently. We have driven down costs and made careful judgements about the best use of capital. The board has worked with Bob Dudley and the executive team on BP’s strategic direction. This has been a significant step forward in defining BP’s pathway to sustained growth. The year closed with the announcement of a number of major additions to our portfolio, all aimed at contributing to returns over both the short and the longer term. All of this has been reflected in an improved share price during the year and good returns for shareholders. 2016 outcomes We determined executive pay for 2016 and have exercised downward discretion in coming to our final decision. • The annual bonus for 2016 was based on a combination of safety and value based measures. • Overall performance has been good; however the threshold performance for loss of primary containment (LOPC) was not met, partly due to harsher winter operating conditions in our unconventional gas operations in the US. • The committee exercised discretion and applied some of the principles of our new policy early. As a result, a bonus of 81% of maximum based on the previous formulaic outcome was reduced to 61% of the maximum. • For performance shares awarded in 2014, vesting will be determined by a combination of relative TSR, financial, safety and operational performance assessed over the three years from 2014 to 2016. • Again the committee has exercised discretion to reduce the vesting outcome, which is expected to be 40% of the maximum award. This discretion was applied to the operating cash flow element of the award, reflecting the wider performance of the business and outcomes for shareholders over the three-year period. • A portion of the annual bonuses for 2013 was deferred and a corresponding matching award made in 2014. Vesting required satisfactory safety and environmental sustainability performance over the three years from 2014 to 2016. The committee was satisfied that this condition had been met and these awards have vested in full. • From September 2016 Bob Dudley had no further service accrual under the defined benefit pension arrangements. In a year of good performance and progress, the total single figure for Bob Dudley in 2016 is $11.6 million, 40% lower than for 2015. In addition to the above, the executive directors have voluntarily agreed the extension of vesting periods for certain legacy share awards as a transitional approach to the new policy. Conclusion I believe that the board has responded positively to the events of 2016 and has taken significant action. In this, we have worked collaboratively with Bob Dudley and Dr Brian Gilvary. The committee believes that the decisions on the 2016 outcomes represent a balance between BP’s performance and shareholder outcomes over the relevant periods. I have consulted widely with shareholders and listened to and sought to act on their concerns, and have been sensitive to developments in the society in which we work. We believe that the new policy is simpler, transparent and has strategic focus. Professor Dame Ann Dowling Chair of the remuneration committee 6 April 2017 How did we determine 2016 outcomes? 1 2 Assess performance Review outcomes with board committees 3 Align with employees 4 Apply discretion • Checked performance against safety and value measures. • Reviewed the measures against targets set. • Sought views from the audit and safety, ethics and environmental assurance committees to ensure a thorough review of performance. • Considered outcomes in relation to BP’s group leaders and the broader comparator group of US and UK employees in professional and managerial roles. • Used judgement to reflect the broader market environment and outcomes for shareholders. 82 More information Single figure table Page 90 Annual bonus scorecard Page 92 2014-2016 performance shares scorecard Page 93 BP Annual Report and Form 20-F 2016Directors’ remuneration report – overview Business performance We have made good progress, with strong share price growth and the announcement of a number of major investments all aimed at contributing to returns over the short and longer term. Key strategic highlights • Six Upstream major project start-ups. • Deepwater Horizon commitments clarified. • Biggest Downstream fuels launch in a decade. Performance outcomes $17.6bn Operating cash flow, excluding Gulf of Mexico payments. $7.5bn Dividends paid, including scrip. $7bn Cash cost reduction target achieved one year ahead of plan. Annual bonus 81% Formulaic outcome (% of maximum) -20% Committee discretion to reduce award 61% Final outcome after committee discretion (% of maximum) Performance shares 57% Formulaic outcome (% of maximum) -17% Committee discretion to reduce award 40% Expected outcome after committee discretiona (% of maximum) Performance measures (% weighting) Nil Maximum Performance measures (% weighting) Nil Maximum Value Operating cash flow (excluding Gulf of Mexico oil spill payments) (30%) Underlying replacement cost profit (25%) Corporate and functional costs (10%) Major project delivery (5%) Safety – Loss of primary containment (10%) – Tier 1 process safety events (10%) – Recordable injury frequency (10%) Financial Relative TSR (33.3%) Operating cash flow (excluding Gulf of Mexico oil spill payments) (33.3%) Strategic imperatives Relative reserves replacement a ratio (RRR) (11.1%) Major project delivery (11.1%) Safety and operational risk – Loss of primary containment (3.7%) – Tier 1 process safety events (3.7%) – Recordable injury frequency (3.7%) a The final outcome for part of this award is based on the company’s relative RRR ranking, presently assumed to be third amongst its peers: this will not be known until after the publication of our peers’ reports and will therefore be reported in the directors’ remuneration report for 2017. Remuneration outcomes Bob Dudley, group chief executive Total remuneration 2016 2015 2014 Dr Brian Gilvary, chief financial officer Total remuneration $11.6m $19.4m $16.4m 2016 2015 2014 £4.2m £5.1m £3.6m Overall pay down 40% Performance pay downb 32% Overall pay down 18% Performance pay downb 23% Salary and benefits Retirement benefits Annual bonus Performance shares b Bonus and performance shares. Share ownership Shareholding is a key means by which the interests of executive directors’ are aligned with those of shareholders. As at 22 March 2017 both directors had holdings in BP which significantly exceeded their shareholding requirement. Further details are set out on page 95. Bob Dudley, group chief executive Dr Brian Gilvary, chief financial officer Policy requirement: minimum of 500% of salary 2,700,516 sharesc 825% of salary 1,543,297 shares 959% of salary cHeld as ADSs. 83 BP Annual Report and Form 20-F 2016Corporate governance2016Summary of our pay and performance for 2016 Directors’ remuneration report – overview Summary of our remuneration policy and approach for 2017 New approach Simplification. Reduced package versus 2014 policy. Link to strategy. Stewardship. Competitive salary and benefits to reflect role and home country norms Elements of package Salary and benefits Retirement benefits Annual bonus Performance shares Share ownership Approach Salary and benefits Fixed pay policy is unchanged. Salary and benefits are set at a level which reflects the scale and complexity of the role while recognizing competitive practice in the relevant market. • The salary for the group chief executive will remain at $1,854,000 for 2017. Bob Dudley has not received a salary increase since July 2014. responsibilities for BP’s trading and shipping functions. This increase of 3.75% is within the range used by the company for other UK and US employees. • With effect from the AGM, the salary for the chief financial officer • Benefits will remain unchanged – these include will be £759,000. • The increase to Dr Brian Gilvary’s salary reflects the changes made to his role in 2016 when he took on additional car-related benefits, security assistance, insurance and medical benefits. Retirement benefits • From September 2016, Bob Dudley has no further service accrual under the defined benefit pension arrangements. The 401(k) benefits have been partially capped for future years. • Dr Brian Gilvary receives a cash supplement on the same terms as other participants in the BP UK defined benefit scheme. He receives no further service accrual under the defined benefit pension arrangements. Annual bonus Up to 225% of salary The bonus links variable pay to safety, reliable operations and financial performance for the year. • Maximum bonus only payable for outperformance on • Awards will be subject to clawback and malus provisions. every measure. • The measures for the bonus are set annually to reflect • Bonus payable for delivery of bonus scorecard of 1.0 out of annual priorities. 2.0 reduced by 25% to half of maximum. • For 2017, performance judged on three key areas: • 50% of any bonus earned will be paid in cash; there will be a mandatory deferrral of 50% into shares for three years. • Removal of bonus share matching arrangements – deferred – safety (20%) – reliable operations (30%) – financial performance (50%). shares will not accrue any match. • Overall discretion to review outcomes in the context of annual performance. Performance shares Directly linked to long-term performance and represents the largest part of the package. GCE – 500% CFO – 450% of salary • Three-year performance period, with further three-year holding period. • Measures aligned to long-term strategy and shareholders’ interests. • Awards will be subject to clawback and malus provisions. • For 2017 awards, performance judged on three key areas: – TSR relative to oil and gas majors over three years (50%) – ROACE in 2019 (30%) – strategic progress assessed over the performance period (20%). • Additional safeguard – broader performance including absolute TSR performance and safety and environmental factors to be considered before determining vesting outcomes. Share ownership Share ownership Stewardship and alignment with shareholders • Continuing requirement for directors to maintain a holding • In addition the executive directors have voluntarily agreed of five times salary. • It is expected that Bob Dudley and Dr Brian Gilvary will maintain a holding of at least 250% of salary for two years following retirement. to extend the vesting periods of certain legacy share awards until post retirement. 84 BP Annual Report and Form 20-F 20162017Long-term shareholdingBonus aligned with annual objectivesShare award for meeting three-year targetsIntroduction This year the board has prepared two reports on remuneration. First, a report on how directors will be paid in 2017 and how the 2014 policy has been implemented for 2016. This will be the subject of an advisory vote at the 2017 AGM. Second, a report which sets out the proposed 2017 remuneration policy for the three years commencing at the 2017 AGM. This will be the subject of a binding vote. Contents 86 87 90 91 95 101 Features of 2017 policy Implementation of 2017 policy Single figure table for 2016 Pay and performance for 2016 Stewardship and regulatory information 2017 proposed policy 85 BP Annual Report and Form 20-F 2016Corporate governance Directors’ remuneration report Features of 2017 policy The remuneration policy proposed for 2017 is based on a detailed review of pay and an extensive programme of shareholder engagement following the 2016 AGM. As a result, we are proposing some fundamental changes to simplify the structure and reduce the level of pay for our 2017 policy onwards. Clearer link between pay and strategy BP set out an update of its strategy in February 2017. The foundations for strong performance are safe and reliable operations, a balanced portfolio and a focus on returns. Our strategic priorities include: Shift to gas and advantaged oil in the upstream Venturing and low carbon across multiple fronts Market-led growth in the downstream Modernizing the whole group Shareholders have been clear that they wish to see remuneration measures that are relevant to BP’s strategy and long-term performance and which are genuinely stretching. We are putting in place a balanced set of measures to enable a rounded assessment of performance against our strategy. Weightings for each of the measures may vary over time. Annual bonus Performance shares Measures reflect safety, reliable operations and financial performance over the year. Measures focus on financial returns over the longer term and progress against the strategic priorities. The culture of long-term stewardship is reinforced by the requirement for our senior leadership to own shares in BP over the long term. Shareholder involvement in the new policy The new policy reflects the outcome of an intense period of engagement with shareholders beginning in May 2016 and running through to this year’s AGM. There has been extensive work by the remuneration committee and the board. The committee chair has held 68 meetings or calls and the committee has met 13 times since the 2016 AGM. The committee has sought to address a number of matters raised during this engagement. Simplification and transparency Many shareholders said they found our 2014 policy too complicated. In response the committee has simplified the structure by removing the matching share element of the deferred annual bonus. We have also reduced the number of measures used to determine the vesting of performance shares and have eliminated any duplication of measures between annual and long-term plans. We have simplified the formula used to determine the payment of the annual bonus. Outperformance on every measure is now required to achieve maximum payment, aligning executive directors with the wider professional and managerial employee population. In addition to this simplification, to improve transparency we will disclose the threshold and outperformance levels that determine the vesting of up to eighty per cent of the available performance shares for 2017 at the beginning of the performance period. 86 Safety The 2014 policy used safety measures in all three of its performance elements: the annual bonus, deferred shares and performance shares. A number of shareholders considered that this placed too much reward focus on safety measures. The new policy retains tier 1 process safety events and recordable injury frequency as measures for the annual bonus. There are no longer safety measures for performance shares, however the committee will incorporate the group’s longer-term safety and environmental performance as an underpin when evaluating outcomes for performance share awards. This will include consideration of a number of measures, including LOPC and input from the safety, ethics and environment assurance committee (SEEAC) to inform the exercise of the committee’s discretion. This ensures that BP’s safety performance in the short and long term remains a significant consideration in remuneration. Climate change In 2015 the board supported a shareholder resolution which sought disclosure around ‘BP’s evolving approach to KPIs and executive incentives, in the context of the transition to a low carbon economy, including the role played by the relative reserves replacement ratio (RRR)’. The committee believes that our new strategic priorities support a lower carbon future. These include the shift towards gas in our portfolio and the growth of lower carbon activities – including venturing, renewable trading and alternative energy. The new policy provides an explicit link to our strategic priorities as a longer-term measure. The committee believes that the relative RRR measure does not fit with the group’s strategic focus on ‘value over volume’. The environmental underpin for performance shares will include consideration of issues around carbon and climate change. Remuneration in the wider group Some shareholders have asked about the relationship between executive director pay with the wider BP employee base. The committee has considered this relationship in a number of ways: • Any percentage increase in executive directors’ salaries will not exceed the wider employee population. • Pension plans for the current executive directors have been scrutinized by the committee. The committee is satisfied that these plans should remain in place on the terms set out in the report, on the basis that they are open to broader groups of employees in the same home country and any discretion (e.g. payment in lieu of pension) is also applicable to wider groups of employees below executive level. • The ratio between GCE and employee pay, see page 96. Discretion Discretion and judgement remain features of the new policy and the committee has a clear understanding of the views of shareholders in respect of their use. More information Our strategy Page 14 Implementation of 2017 policy Page 87 2017 proposed policy Page 101 BP Annual Report and Form 20-F 2016Directors’ remuneration report Implementation of 2017 policy Salary and benefits The committee noted that salary increases for UK and US based employees across the group were generally between 3-4%. Salary increases over the last five years Bob Dudley Dr Brian Gilvary Bob Dudley has informed the committee that he does not intend to accept a salary increase for 2017 and therefore his salary will remain unchanged. His salary has not been increased since 1 July 2014. Following the AGM, Dr Brian Gilvary’s salary will be increased by 3.75%, which does not exceed increases within the broader employee population. This increase reflects the changes made to his role in 2016 when he took on additional responsibilities for BP’s trading and shipping functions. Benefits for 2017 will remain broadly unchanged from prior years. 2017 Nil 2016 Nil 2015 Nil 2014 2013 Bob Dudley Dr Brian Gilvary 3.0% 2.8% 2017 2016 Nil 2015 Nil 2014 2013 Salary with effect from AGM $1,854,000 £759,000 3.75% 3.0% 2.9% Increase Nil 3.75% Annual bonus For 2017, the bonus measures will focus on three areas: safety, reliable operations and financial performance. This approach is intended to provide a balanced assessment of how the business has performed over the course of the year against stated objectives. Targets are aligned with the annual plan and strategic and operational priorities for the year. The safety element has been simplified to focus on measures that are robust and can be readily benchmarked against sector peers. In addition, the measures linked to reliable operations also require execution of good safety practices. Although the detail of the targets is currently commercially sensitive, the committee intends to continue to provide retrospective disclosure following the year end. In order to provide a fair assessment of underlying performance, changes in plan conditions (including oil and gas prices and refining margins) are considered when reviewing financial outcomes. Awards will be subject to malus and clawback provisions as set out in the policy. The maximum bonus opportunity is 225% of salary for a bonus scorecard of 2.0 out of 2.0. As noted in the policy, the bonus payable for performance which meets the annual plan (i.e. a bonus scorecard of 1.0 out of a maximum of 2.0) has been reduced by 25% to half of maximum. For any bonus earned, 50% will be delivered in cash and 50% must be deferred into shares that will vest after three years. The committee retains overall discretion to review outcomes in the context of overall performance. Measures for 2017 annual bonus Element 1 Safety 20% Measures include 2 Reliable operations 3 Financial performance Metric weighting for 2017 30% Measures include Metric weighting for 2017 50% Measures include Metric weighting for 2017 Recordable injury frequency 10% Upstream operating efficiency Tier 1 process safety events 10% Downstream refining availability (Solomon Associates’ operational availability) 15% 15% Operating cash flow (excluding Gulf of Mexico oil spill payments) Underlying replacement cost profit 20% 20% Upstream unit production costs 10% 87 BP Annual Report and Form 20-F 2016Corporate governanceFuture growth Measures for the strategic element are aligned with the company’s long- term strategy, positioning the portfolio for resilience and future growth. We will be following the implementation of our strategy through the four measures relating to the strategic priorities set out below. The committee has also sought input from the board regarding the specific measures. Details of the strategic priorities targets – determining 20% of the performance shares available – are commercially sensitive and are not included in this report. However, the committee intends to provide detailed retrospective disclosure after the end of the performance period so that shareholders can understand the basis of payment. Performance shares The measures for 2017 performance share awards now focus on shareholder value, capital discipline and future growth. Shareholder value The total shareholder return (TSR) element will continue to be measured on a relative basis against the oil majors: Chevron, ExxonMobil, Shell and Total. The committee has reviewed the current comparator group and believes that it remains appropriate as it is used for benchmarking across a range of activities in other parts of the group. There will be no vesting of this element if BP’s TSR is positioned below third place in the group. Capital discipline Return on average capital employed (ROACE) will be calculated by dividing the underlying replacement cost profit (after adding back net interest) by average capital employed excluding cash and goodwill. This assessment will be based on the final year of the three-year period. Targets for TSR and ROACE measures for 2017 – determining 80% of the performance shares available – are set out below at the start of the assessment period. Measures for 2017 performance shares Element 1 Relative TSR versus oil majorsa 2 Return on average capital employedb 3 Strategic progress 50% 30% 20% Threshold vesting Maximum vesting 25% of element Third out of five 100% of element First place 0% of element 6% return on average capital employed • Shift to gas and advantaged oil in the upstream 100% of element 11% return on average capital employed • Market led growth in the downstream • Venturing and low carbon across multiple fronts • Gas, power and renewables trading and marketing growth a Nil vesting for fourth and fifth place. Vesting of 80% for second place. b Based on performance in 2019. There will be straight-line vesting for performance between the threshold and maximum vesting level. Adjustments may be required in certain circumstances (e.g. to reflect changes in accounting standards). Operation of the performance share plan Prior to approving vesting outcomes the committee will additionally take into account the broader performance of the business including absolute TSR performance, together with safety and environmental factors over the three-year period. The maximum opportunity for share awards will be 500% of salary for Bob Dudley and 450% of salary for Dr Brian Gilvary. This represents a significant reduction from the previous long-term variable pay opportunity – delivered via awards of performance and matching shares on the deferred annual bonus – of 700% of salary for Bob Dudley and 550% of salary for Dr Brian Gilvary. Performance will be measured over three years, with any vested shares being subject to a mandatory holding period for a further three years. Awards will be subject to malus and clawback provisions as set out in the policy. 88 BP Annual Report and Form 20-F 2016Directors’ remuneration report – implementation of 2017 policyDirectors’ remuneration report – implementation of 2017 policy Retirement benefits Bob Dudley and Dr Brian Gilvary participate in the pension arrangements which are available to wider groups of employees in the US and UK, as set out below. Bob Dudley Bob Dudley is provided with pension benefits and retirement savings through a combination of tax-qualified and non-qualified benefit plans, consistent with applicable US tax regulations. The BP supplemental executive retirement benefit plan (SERB) is a non-qualified pension plan which provides a pension of 1.3% of final average earnings (as defined in plan rules) for each year of service, less benefits paid under all other BP (US) tax-qualified and non-qualified pension plans. Final average earnings include base salary, cash bonus and bonus deferred into a share award under the deferred element of the EDIP. Service, including service with TNK-BP, is limited to 37 years. Bob Dudley completed 37 years of service in September 2016 and therefore will not receive any further service accrual under these arrangements. There will be no additional payment in lieu of any further service accrual. The benefit payable under the SERB is unreduced at age 60 or above. Bob Dudley is also a member of other tax-qualified and non-qualified pension plans. However, the benefits from those plans are offset against the SERB benefit and so his benefit entitlement is determined by his participation in the SERB. The BP Employee Savings Plan (ESP) is a US tax-qualified section 401(k) plan to which both Bob Dudley and BP contribute. BP matches contributions by Bob Dudley 1:1 up to 7% of eligible pay up to an IRS limit. The BP Excess Compensation (Savings) Plan (ECSP) is a non- qualified retirement savings plan under which BP provides a notional match in respect of eligible pay that exceeds the IRS limit. In common with other participants, Bob Dudley does not contribute to the ESCP. From 2017 onwards, for the purposes of both plans, eligible pay for Bob Dudley is base salary only. Under both tax-qualified and non-qualified savings plans, Bob Dudley is entitled to make investment elections, involving an investment in the relevant fund in the case of the ESP and a notional investment (the return on which would be delivered by BP under its unfunded commitment) in the case of the ECSP. Benefits payable under non-qualified plans are unfunded and therefore paid from corporate assets. Benefits are generally paid as a lump sum, with any pension benefit being converted to a lump sum equivalent. Shareholding requirements Both executive directors meet the share ownership requirements of five times salary. It is expected that Bob Dudley and Dr Brian Gilvary will maintain a shareholding of at least 250% of salary for two years following retirement. Dr Brian Gilvary Dr Brian Gilvary participates in a UK final salary pension plan, the BP Pension Scheme (BPPS), in respect of service prior to 1 April 2011. The BPPS provides a pension of one sixtieth of final base salary for each year of service, up to a maximum of two thirds of final base salary, and a dependant’s benefit of two thirds of the member’s pension. Since 1 April 2011, Dr Brian Gilvary has, along with some other participants in the BPPS, elected to receive a cash supplement in lieu of future service pension accrual in the BPPS. In 2016 Dr Brian Gilvary received a cash supplement of 35% of base salary. It has been agreed for all participants who have elected to receive a cash supplement, including Dr Brian Gilvary, that a transition will take effect from April 2021 when the level of cash supplement will progressively reduce to 15% of base salary by 2024. Pension benefits in excess of the individual lifetime allowance set by legislation are provided to Dr Brian Gilvary via an unapproved, unfunded pension arrangement provided directly by the company. The rules of the BPPS were amended in 2006 to introduce a normal retirement age of 65, but in common with other BPPS participants in service on 30 November 2006, Dr Brian Gilvary has a normal retirement age of 60. If Dr Brian Gilvary were to retire between age 55 and 60, then subject to the consent of the committee, he would be entitled to an immediate pension, with a reduction (currently 3%) for each year before normal retirement age in respect of the benefit that relates to service since 1 December 2006 and no reduction in respect of the remainder of his benefit. Irrespective of this, on leaving in circumstances of total incapacity, an immediate unreduced pension would be payable as from his leaving date. 89 BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – implementation Single figure for 2016 – executive directors Single figure of remuneration for executive directors in 2016 (audited) Remuneration is reported in the currency in which the individual is paid Salary and benefits Salary Benefits Annual bonus Bonus earned Less: amount deferred and at risk subject to future performancea Performance shares Performance shares Legacy: deferred bonus and matchd Total remuneration Retirement benefits Bob Dudley (thousand) Dr Brian Gilvary (thousand) 2016 2015 2016 2015 $1,854 $74 $1,854 $119 £732 £67 £732 £53 $2,545 ($848) $4,172 ($2,781) £1,004 £1,646 (£335) (£1,097) $3,713b $2,015 $9,353 $6,890c $2,603 $12,857 £1,387b £2,229c £1,046 £3,901 £1,272 £4,835 Pension and retirement savings – value increasee Cash in lieu of future accrual Total including pension $2,205 $6,519 – – – £256 – £256 $11,558 $19,376 £4,157 £5,091 Bob Dudley’s total including pension for 2016 is equivalent to £8.57 million based on the average dollar-sterling exchange rate for 2016. a This reflects the portion of the annual bonus which is deferred into shares and will only vest subject to achievement of future performance as described below. b Represents the assumed vesting of shares in 2017 following the end of the relevant performance period, based on a preliminary assessment of performance achieved under the rules of the plan and includes reinvested dividends on shares vested. In accordance with UK regulations, the vesting price of the assumed vesting is the average market price for the fourth quarter of 2016 which was £4.73 for ordinary shares and $35.39 for ADSs. The final vesting will be confirmed by the committee in second quarter 2017 and provided in the 2017 directors’ remuneration report. c In accordance with UK regulations, in the 2015 single figure table, the performance outcome value was based on an estimated vesting at an assumed share price of £3.72 for ordinary shares and $33.81 for ADSs. In April 2016, after the external data became available, the committee reviewed the relative reserves replacement ratio position. This resulted in an adjustment to the final vesting from 77.6% to 74.3%. On 28 April 2016, 205,731 ADSs for Bob Dudley and 583,571 shares for Dr Brian Gilvary vested at prices of $33.49 and £3.82 respectively. The 2015 values for the total vesting have decreased by $226,330 for Bob Dudley and increased by £6,065 for Dr Brian Gilvary. d Value of vested deferred bonus and matching shares. The amounts reported for 2016 relate to the 2013 annual bonus deferred over three years, which vested on 24 February 2017 at the market price of £4.47 for ordinary shares and $33.50 for ADSs and include reinvested dividends on shares vested. There was an additional accrual of notional dividends on 31 March 2017 which will vest in 2017 and will be provided in the 2017 directors’ remuneration report. The amounts reported for 2015 relate to the 2012 annual bonus. e Represents (1) the annual increase net of inflation in accrued pension multiplied by 20 as prescribed by UK regulations, and (2) the aggregate value of the company match under Bob Dudley’s US retirement savings arrangements. Full details are set out on page 94. Bob Dudley Overall pay down 40% Performance pay downb 32% Dr Brian Gilvary Overall pay down 18% Performance pay downb 23% b Bonus and performance shares. Key outcomes for 2016 Bob Dudley – total pay A year of progress and performance for the company. Total single figure in 2016 for Bob Dudley is $11.6 million – 40% lower than for 2015. $19.4m Committee discretion reduced pay by $2.2 million. Maximum opportunity for 2017 and beyond significantly reduced. 90 $13.8m $11.6m 2015 2016 Formulaic outcome 2016 Outcome after committee discretion BP Annual Report and Form 20-F 2016Pay and performance for 2016 Salary and benefits Base salary No salary increases were awarded to executive directors for 2016. The 2016 salaries therefore remained unchanged from 1 July 2014: $1,854,000 for Bob Dudley and £731,500 for Dr Brian Gilvary. Annual bonus The targets for the 2016 annual bonus were set at the start of the year based on a combination of safety and value based measures. Targets were set in the context of the group’s strategy and the annual plan. During 2016 BP’s share price performed strongly and the group distributed $7.5 billion to shareholders in cash and scrip dividends. However, it has clearly been another challenging year for the industry. Over the course of 2016, the oil price averaged $44 per barrel, and both gas prices and refining margins remained weak compared to historic levels. In this context, the group’s operating cash flow was solid. Goals for reduction in controllable costs were delivered one year ahead of schedule, and there has been good discipline on capital expenditure. Trends in safety and environmental measures continued to be positive with outperformance against targets for tier 1 process safety events and recordable injury frequency. The outcome for loss of primary containment was partly impacted by harsher winter operating conditions in our unconventional gas operations in the US, and therefore the threshold set was not met. Although there was no payment against this performance measure, the committee noted that the 2016 outcomes did not create any safety concerns and that the longer-term trend for the measure remained positive. More generally, good progress was made during 2016 to create a platform for future growth: the remaining material uncertainties regarding Deepwater Horizon liabilities have now been clarified; visible progress has been made in a number of upstream projects; and in our downstream business we rolled out our biggest fuels launch in a decade. When reviewing performance over the period, the committee also sought input from the chairs of the audit committee and the safety, ethics and environment assurance committee to ensure a comprehensive review of peformance. Overall, the performance delivered during the year resulted in a scorecard outcome of 1.22. Under the policy applicable for the year, approved by shareholders in 2014, this scorecard outcome would have resulted in a bonus outcome equal to 81% of the maximum available. Benefits Executive directors received car-related benefits, security assistance, insurance and medical benefits. The committee considered the overall outcome and noted that while performance during the second and third quarters was strong, there were some challenges during the final quarter. The committee exercised discretion and applied some of the principles of the new policy early. As a result, the bonus of 81% of maximum based on the previous formulaic outcome was reduced to 61% of the maximum annual bonus available. Overall, the committee believes that the bonuses for 2016 fairly reflect performance over the period. Outcome Name Bob Dudley Dr Brian Gilvary Adjusted outcome after committee discretion (thousand) $2,545a £1,004 Paid in cash (thousand) $1,696 £669 Deferred into BP shares (thousand) $848 £335 a Due to rounding, the total does not agree exactly with the sum of its component parts. Under the terms of the existing directors’ remuneration policy applicable for 2016, directors mandatorily defer a third of their bonus and could volunteer to defer a further third; the deferred portion of the annual bonus is then matched with a further performance-based award. The deferred and matching awards vest subject to a safety and environmental sustainability performance hurdle. As a transition to the new policy, for 2016 the executive directors will defer a third of their bonus but will not have the opportunity to increase the potential matching award by voluntarily increasing the proportion of their bonus to be deferred. In addition, with the support of the committee, the executive directors have elected to extend the vesting period for their matching awards in respect of the compulsorily deferred 2016 bonus, so that vesting will not occur until after retirement rather than the normal three-year period. During this extended period, the matching award will remain subject to the performance hurdle. The committee is of the view that this is a positive step as it significantly increases the time horizons for management’s incentives, and reinforces the emphasis on stewardship, safety and the environment which remain core priorities for the group. 91 BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – implementationDirectors’ remuneration report – implementation Annual bonus – continued Scorecard 2016 annual bonus 1 Safety 0.36 Measures 1 Safety Loss of primary containment Tier 1 process safety events Recordable injury frequency Safety outcome 2 Value Operating cash flow (excluding Gulf of Mexico oil spill payments) Underlying replacement cost profit Corporate and functional costs Major project delivery Value outcome 3 Total bonus score More information Key performance indicators page 18 2 Value 0.86 3 Formulaic score 1.22 out of 2.0 Threshold 0 performance and score Plan/target 1.0 performance and score Maximum 2.0 performance and score Performance and outcome 230 events 0 25 events 0 0.253/200k hrs 0 214 events 0.1 22 events 0.1 0.232/200k hrs 0.1 182 events 0.2 15 events 0.2 0.191/200k hrs 0.2 $14.8bn 0 $2.1bn 0 $4.04bn 0 2 0 $16.8bn 0.3 $2.9bn 0.25 $3.74bn 0.1 4 0.05 $18.8bn 0.6 $3.7bn 0.5 $3.44bn 0.2 6 0.1 233 events 0 16 events 0.19 0.202/200k hrs 0.17 0.36 $17.6bn 0.42 $2.6bn 0.16 $3.49bn 0.18 6 0.10 0.86 1.22 out of 2.0 Bonus after discretion 61% of maximum Application of the score The maximum annual bonus available to be paid is 225% of salary. By using the methodology under the 2014 policy, a score of 1.22 would result in payment of 81% of that maximum. The committee has used discretion to reduce the payment from 81% to 61%. 92 BP Annual Report and Form 20-F 2016Performance shares For performance shares awarded in 2014, vesting was determined by a combination of relative TSR, safety, financial and operational performance assessed over the three years from 2014 to 2016. The results are summarized in the table below. Measured over the three-year period, the company’s TSR was in third place amongst the five oil majors. The committee noted that returns on the value of BP’s shares in sterling have also risen by 22% over this period, outperforming returns on the FTSE 100 index over the same timeframe. The group delivered positive scores for tier 1 process safety events and recordable injury frequency. As noted above, the outcome for loss of primary containment was partly impacted by harsher winter operating conditions in our unconventional gas operations in the US. While the threshold for this element was not met, the outcomes did not create any safety concerns and the longer-term trend for the measure remains positive. The nil outcome provides an indication of the stretch of the original target range set. In respect of project delivery, the vesting outcome reflects the strong progress over the three-year period. Further details of performance are set out in the strategic report. Preliminary assessment of relative reserves replacement ratio indicates vesting for this measure. For the purpose of this report, a forecast has been used. The final outcome for this measure will be confirmed later in the year, once competitor data is published in full. Scorecard 2014-2016 performance shares Vesting % of the 2014 award For operating cash flow, the hurdle for full vesting was originally set at $34.9 billion, based on an assumed oil price of $105 per barrel. Under the methodology used and disclosed in prior years, this target would have been adjusted to reflect the price environment in 2016, when the actual average oil price was $44 per barrel. The adjusted target would mean that 60% of the award would vest for $15.3 billion, with full vesting occurring at $19.3 billion. The performance in 2016 would have resulted in a vesting outcome of just over 80% of the maximum available for this part of the award. However, in light of shareholder feedback in 2016, the committee determined that it would be appropriate to exercise its discretion on this part of the award to ensure that the overall vesting outcome fairly reflected the performance of the business and outcomes for shareholders. The committee undertook a wider review of performance over the three-year performance period, with additional consultation with the chairs of the audit committee and the safety, ethics and environment assurance committee. Following this review of performance, the committee determined that the vesting for the 2016 award should be reduced from the formulaic outcome of 57% of maximum to 40% of maximum. More information Key performance indicators page 18 1 Financial 35.9% Measures 1 Financial Relative total shareholder return Operating cash flow (excluding Gulf of Mexico oil spill payments) 2 Strategic imperatives Relative reserves replacement ratio Major project delivery Safety and operational risk – Loss of primary containment – Tier 1 process safety events – Recordable injury frequency 3 Total formulaic vesting Vesting after committee judgement 2 Strategic imperatives 21.1% 3 Total formulaic vesting 57% Weighting at maximum % Threshold performance Maximum performance Performance and outcome 33.3 33.3 11.1 11.1 3.7 3.7 3.7 Third First See discussion above Third 8 First 12 210 events 172 events 23 events 15 events 0.265/200k hrs 0.215/200k hrs Third 8.3% $17.6bn 27.6% 35.9% Third 2.8% 17 11.1% 233 events 0% 16 events 3.5% 0.202/200k hrs 3.7% 21.1% 57% Vesting after discretion 40% 93 BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – implementationPerformance shares – continued Preliminary outcome – 2014-2016 performance shares Name Bob Dudley Dr Brian Gilvary Shares awarded 1,304,922 605,544 Shares vesting including dividends 629,484 293,296 Value of vested shares $3,712,906 £1,387,290 These values are based on forecast vesting levels. As noted above, final vesting will be determined once competitor data is published in respect of relative reserves replacement. Legacy: deferred bonus and matching award Both Bob Dudley and Dr Brian Gilvary deferred one third of their 2013 annual bonus in accordance with the terms of the deferred bonus plan. The three-year performance period for this deferred award ended on 31 December 2016. The committee reviewed safety and environmental sustainability performance over this period and sought the input of the safety, ethics and environment assurance committee. This included an assessment of both actual outcomes under safety and sustainability measures and also consideration of the long-term performance trend. Over the three-year period 2014-2016 safety performance continued to demonstrate progress and improvement. The committee also noted the extent to which safety performance had become embedded into the culture of the organization and the degree to which this has supported stronger operational and financial performance. This Conclusions of the safety and sustainability assessment 2013-2015 performance shares – final outcome Last year the committee made a preliminary assessment of first place for the relative RRR in the 2013-2015 performance shares element. In April 2016 the committee reviewed the results for all comparator companies as published in their annual reports and assessed that BP was in second place relative to other oil majors and that 7.8% of shares – out of a maximum of 11.1% – would vest for this performance measure. This resulted in a final overall vesting of 74.3% of maximum instead of the preliminary outcome of 77.6% outlined in the 2015 directors’ remuneration report. strengthened safety performance has also informed the committee’s thinking when including safety measures in pay arrangements under the new policy. Following the committee’s review, full vesting of the deferred and matching shares in respect of the 2013 deferred bonus was approved. Subject to approval of the new policy, which will be presented to shareholders at the 2017 AGM, the committee does not intend to grant further matching share awards under this plan. 2013 deferred bonus vesting – outcome Name Bob Dudley Dr Brian Gilvary Shares deferred 299,256 193,306 Total shares including Vesting dividends agreed 100% 360,900 100% 234,070 Total value at vesting $2,015,025 £1,046,293 No systemic issues identified No major incidents Safety culture and values embedded within the global organization Strong performance supports efficiency and financial results across the group Retirement benefits 2016 outcomes Bob Dudley participates in the US pension and retirement savings plans described on page 89. In 2016, Bob Dudley’s accrued pension increased, net of inflation, by $59,000. This increase has been reflected in the single figure table on page 90 by multiplying it by a factor of 20 in accordance with the requirements of the UK regulations (giving $1,185,000). In relation to the retirement savings plans, Bob Dudley made contributions in 2016 to the ESP totalling $26,500. For 2016 the total value of BP matching contributions in respect of Bob Dudley to the ESP and notional matching contributions to the ECSP was $422,000, 7% of eligible pay. After adjusting for investment gains within his accumulating unfunded ECSP account (aggregating the unfunded arrangements relating to his overall service with BP and TNK-BP) the amount included in the single figure table on page 90 is $1,020,000. Dr Brian Gilvary participates in the UK pension arrangements described on page 89. In 2016 Dr Brian Gilvary’s accrued pension did not increase. In accordance with the requirements of the UK regulations, the value shown in the single figure table on page 90 is zero. He has exceeded the lifetime allowance under UK pensions legislation and, in accordance with the policy, receives a cash supplement of 35% of base salary, which has been separately identified in the single figure table on page 90. The committee continues to keep under review the increase in the value of pension benefits for individual directors. 94 BP Annual Report and Form 20-F 2016Directors’ remuneration report – implementationStewardship The committee places significant emphasis on executive directors having material interests in the shares of the company. Such shareholding not only provides direct alignment with the experience of shareholders, but also encourages a longer-term focus when considering the performance of BP. Executive directors are required to build a personal shareholding of five times salary within five years of their appointment. Both executive directors significantly exceed the minimum holding required. This ensures they are subject to any fluctuation in the share price and the wider shareholder experience. Post-retirement share ownership interests Given the long-term nature of the group’s operations, the committee sees the merits of ensuring that executives have performance alignment beyond the timeframe of existing incentive plans. The executive directors have taken a number of steps in this respect. • Firstly, the current executive directors have indicated to the committee that they expect to maintain a shareholding of at least 250% of salary for two years following retirement. • Secondly, as noted above, for deferred awards granted in respect of the 2016 bonus, Bob Dudley and Brian Gilvary have agreed to delay vesting of awards of matching shares until after retirement, rather than the normal three-year period. • Thirdly, Bob Dudley has further voluntarily opted to delay the vesting of all outstanding deferred bonus and matching shares in respect of his 2014 and 2015 bonus (representing a total interest over 1,691,784 ordinary shares), which were originally due to vest in 2018 and 2019 respectively, so that vesting is delayed until after retirement. These factors significantly extend the time horizons for both executive directors, and in particular Bob Dudley. The committee fully endorses the steps taken by both executive directors as they clearly demonstrate a continued commitment to the long-term stewardship of the group. Directors’ shareholdings The table below shows the status of each of the executive directors in developing the required level of share ownership. These figures include the value as at 22 March 2017 of the directors’ interests shown below excluding the assumed vesting of the 2014-2016 performance shares. Current directors Bob Dudley Appointment date October 2010 Value of current shareholding $15,298,423 Dr Brian Gilvary January 2012 £7,018,143 % of policy achieved 165 191 The figures below indicate and include all beneficial and non-beneficial interests of each executive director of the company in shares of BP (or calculated equivalents) that have been disclosed to the company under the Disclosure and Transparency Rules (DTRs) as at the applicable dates. Ordinary shares or Ordinary shares equivalents at or equivalents at 1 Jan 2016 31 Dec 2016 1,554,198 2,509,500 1,419,263 903,856 Changes from 31 Dec 2016 to 22 March 2017 191,016 124,034 Ordinary shares or equivalents total at 22 March 2017 2,700,516 1,543,297 Current directors Bob Dudleya Dr Brian Gilvary a Held as ADSs. The following table shows both the performance shares and the deferred bonus element awarded under the executive directors’ incentive plan (EDIP) and yet to vest. These figures represent the maximum possible vesting levels. The actual number of shares/ADSs that vest will depend on the extent to which performance conditions have been satisfied over a three-year period. Ordinary shares or equivalents at 1 Jan 2016 5,536,950 2,789,921 Ordinary shares or equivalents at 31 Dec 2016 6,607,314 3,259,891 Changes from 31 Dec 2016 to 22 March 2017 (299,256) (193,306) Ordinary shares or equivalents total at 22 March 2017 6,308,058 3,066,585 Current directors Bob Dudleya Dr Brian Gilvary a Held as ADSs. At 22 March 2017, the following directors held options under the BP group share plan schemes over ordinary shares or their calculated equivalent set out below. None of these are subject to performance conditions. Additional details regarding these plans can be found on page 100. Current director Dr Brian Gilvary Share options 503,103 No director has any interest in the preference shares or debentures of the company or in the shares or loan stock of any subsidiary company. There are no directors or other members of senior management who own more than 1% of the ordinary shares in issue. At 22 March 2017, all directors and other members of senior management as a group held interests of 13,080,536 ordinary shares or their calculated equivalent, 9,619,319 restricted share units (with or without conditions) or their calculated equivalent, 9,374,643 performance shares or their calculated equivalent and 5,513,021 options over ordinary shares or their calculated equivalent under the BP group share option schemes. Senior management comprises members of the executive team. See pages 58-59 for further information. Further information Historical TSR performance FTSE 100 BP £250 £200 £150 £100 £50 i l g n d o h 0 0 1 £ l a c i t e h t o p y h f o e u a V l 2008 2009 2010 2011 2012 2013 2014 2015 2016 This graph shows the growth in value of a hypothetical £100 holding in BP p.l.c. ordinary shares over eight years, relative to a hypothetical £100 holding in the FTSE 100 Index of which the company is a constituent. 95 BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – implementation Directors’ remuneration report – implementation History of GCE remuneration Year 2009 2010c 2011 2012 2013 2014 2015 2016 Total remuneration thousanda £6,753 £3,890 $8,057 $8,439 $9,609 $15,086 $16,390 $19,376 $11,558 Annual bonus % of maximum 89b 0 0 67 65 88 73 100 61 Performance shares vesting % of maximum 17.5 0 0 16.7 0 45.5 63.8 74.3 40 GCE Hayward Hayward Dudley Dudley Dudley Dudley Dudley Dudley Dudley a Total remuneration figures include pension. The total figure is also affected by share vesting outcomes and these amounts represent the actual outcome for the periods up to 2011 or the adjusted outcome in subsequent years where a preliminary assessment of the performance for EDIP was made. For 2016, the preliminary assessment has been reflected. b 2009 annual bonus did not have an absolute maximum and so is shown as a percentage of the maximum established in 2010. c 2010 figures show full year total remuneration for both Tony Hayward and Bob Dudley, although Bob Dudley did not become GCE until October 2010. Relative importance of spend on pay ($ million) Distributions to shareholders Remuneration paid to all employeesa Capital investmentb 18,440 18,748 12,928 11,233 7,469 7,301 2016 2015 2016 2015 2016 2015 Total Total 2.3% 13.1% Total 1.6% a Total remuneration reflects overall employee costs. See Financial statements – Note 34 for further information. b Capital investment reflects organic capital expenditure. 2016 includes Abu Dhabi onshore oil concession renewal. 96 GCE-to-employee pay ratio The committee wanted to understand the GCE-to-employee pay ratio at BP when developing the policy. The ratio can vary significantly depending on the calculation methodology and sample employee population used and therefore can evolve over time. The most relevant comparator group is the professional/managerial grade employees based in the UK and US which represent some 22% of the global employee population and is used elsewhere in this report. GCE-to-median-worker pay ratio for this sample was 71 to 1 in 2016. The ratio is based on a comparison of total compensation (base salary, actual annual bonus and vested equity awards) in the year. The committee will review the progression of the pay ratio over time. Percentage change in GCE remuneration Comparing 2016 to 2015 % change in GCE remuneration % change in comparator group remuneration Salary 0% Benefits -38.1% Bonus -39.0% 3.5%a 3.0% -7.6% a The comparator group comprises some 22% of BP’s global employee population being professional/managerial grades of employees based in the UK and US and employed on more readily comparable terms. Independence and advice The board considers all committee members to be independent with no personal financial interest, other than as shareholders, in the committee’s decisions. Further detail on the activities of the committee, including activities during the year, advice received and shareholder engagement is set out in the remuneration committee report on page 76. During 2016 David Jackson, the company secretary, who is employed by the company and reports to the chairman of the board, acted as secretary to the remuneration committee. Gerrit Aronson, an independent consultant, was the committee’s independent adviser until April 2016. He was engaged directly by the committee. Willis Towers Watson provided information on the global remuneration market, principally for benchmarking purposes. Freshfields Bruckhaus Deringer LLP provided legal advice on specific compliance matters to the committee. Following a competitive tender process, the committee appointed Deloitte LLP as its independent adviser in May 2016. Deloitte is a member of the Remuneration Consulting Group and, as such, operates under the code of conduct in relation to executive remuneration consulting in the UK. The committee is satisfied that the advice received is objective and independent. Both firms provide other advice in their respective areas to the group. During the year, the wider Deloitte firm also provided BP with services including consulting on HR and Upstream matters. In October 2016, BP completed a tender of its statutory audit and selected Deloitte as BP’s auditor for the financial year 2018. Consequently, Deloitte will step down as adviser to the committee during 2017. Total fees or other charges (based on an hourly rate) for the provision of remuneration advice to the committee in 2016 (save in respect of legal advice) are as follows: Gerrit Aronson £45,000 Willis Towers Watson £5,000 Deloitte £262,000 BP Annual Report and Form 20-F 2016Shareholder engagement As set out in the committee chairman’s letter, during the last year we had extensive dialogue with many of our largest shareholders as well as representative bodies on remuneration matters. We have listened and sought to respond to their concerns. Following the vote at the 2016 AGM the committee is proposing a number of changes to our remuneration policy for future years to respond to shareholder concerns. The table below shows the votes on the report for the last three years. AGM directors’ remuneration report vote results Year 2016 2015 2014 % vote ‘for’ 40.7% 88.8% 83.9% % vote ‘against’ Votes withheld 59.3% 464,259,340 11.2% 305,297,190 16.1% 2,218,417,773 The committee’s remuneration policy was approved by shareholders at the 2014 AGM. The votes on the policy are shown below. 2014 AGM directors’ remuneration policy vote results Year 2014 % vote ‘for’ 96.4% % vote ‘against’ Votes withheld 3.6% 125,217,443 External appointments The board supports executive directors taking up appointments outside the company to broaden their knowledge and experience. Each executive director is permitted to accept one non-executive appointment, from which they may retain any fee. External appointments are subject to agreement by the chairman and reported to the board. Any external appointment must not conflict with a director’s duties and commitments to BP. Details of appointments during 2016 are shown below. Additional position held at appointee company Director L’Air Liquide Non-executive director Appointee company Rosnefta Total fees 0 €47,333 Director Bob Dudley Dr Brian Gilvary a Bob Dudley holds this appointment as a result of the company’s shareholding in Rosneft. Non-executive directors This section of the directors’ remuneration report completes the directors’ annual report on remuneration with details for the chairman and non-executive directors (NEDs). The board’s remuneration policy for the NEDs was approved at the 2014 AGM. This policy was implemented during 2014. There has been no variance of the fees or allowances for the chairman and the NEDs during 2016. Chairman The table below shows the fee structure for the chairman in place since 1 May 2013. He is not eligible for committee chairmanship and membership fees or intercontinental travel allowance. He has the use of a fully maintained office for company business, a car and driver, and security advice in London. He receives a contribution to an office and secretarial support as appropriate to his needs in Sweden. Chairman Fees £ thousand 785 The table below shows the fees paid for the chairman for the year ended 31 December 2016. 2016 remuneration (audited) £ thousand Carl-Henric Svanberg Fees Benefitsa Total 2016 785 2015 785 2016 58 2015 38 2016 843 2015 823 a Benefits include travel and other expenses relating to attendance at board and other meetings. Amounts disclosed have been grossed up using a tax rate of 45%, where relevant, as an estimation of tax due. Chairman’s interests The figures below include all the beneficial and non-beneficial interests of the chairman in shares of BP (or calculated equivalents) that have been disclosed under the DTRs as at the applicable dates. The chairman’s holdings represented as a percentage against policy achieved are 1,203%. Ordinary shares or equivalents at 1 Jan 2016 Ordinary shares or equivalents at 31 Dec 2016 Change from 31 Dec 2016 to 22 March 2017 Ordinary shares or equivalents total at 22 March 2017 2,076,695 2,076,695 – 2,076,695 Chairman Carl-Henric Svanberg Non-executive directors Fee structure The table below shows the fee structure for non-executive directors: Senior independent directora Board member Audit, geopolitical, remuneration and SEEA committees chairmanship feesb Committee membership feec Intercontinental travel allowance Fees £ thousand 120 90 30 20 5 a The senior independent director is eligible for committee chairmanship fees and intercontinental travel allowance plus any committee membership fees. b Committee chairmen do not receive an additional membership fee for the committee they chair. c For members of the audit, geopolitical, SEEA and remuneration committees. 21A_2017_03_22_34642_BP_ARA_DRR_VERSION_B_p80_110.indd 97 97 06/04/2017 16:47:23 BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – implementation Directors’ remuneration report – implementation 2016 remuneration (audited) £ thousand Fees Benefitsa Total Nils Andersenb Paul Anderson Alan Boeckmann Admiral Frank Bowman Antony Burgmansc Cynthia Carroll Ian Davis Professor Dame Ann Dowlingd Brendan Nelson Phuthuma Nhlekoc Paula Rosput Reynoldse Sir John Sawers Andrew Shilston 2016 23 165 168 162 47 140 136 150 130 48 140 148 190 2015 – 177 178 177 149 127 145 141 125 167 93 85 165 2016 6 32 17 14 21 28 2 2 30 3 17 19 5 2015 – 28 14 12 19 68 3 1 11 11 8 0 3 2016 29 197 185 176 68 168 138 152 160 51 157 167 195 2015 – 205 192 189 168 195 148 142 136 178 101 85 168 a Benefits include travel and other expenses relating to the attendance at board and other meetings. Amounts disclosed have been grossed up using a tax rate of 45%, where relevant, as an estimation of tax due. b Appointed on 31 October 2016. c Retired on 14 April 2016. d In addition, Professor Dame Ann Dowling received £25,000 for chairing and being a member of the BP technology advisory council. e The 2015 number has been restated to reflect tax treatment. The geopolitical committee was established in late 2015. Its members received the first full year of fees in 2016. Non-executive director interests The figures below indicate and include all the beneficial and non-beneficial interests of each non-executive director of the company in shares of BP (or calculated equivalents) that have been disclosed to the company under the DTRs as at the applicable dates. Nils Andersena Paul Anderson Alan Boeckmann Admiral Frank Bowman Antony Burgmansc Cynthia Carroll Ian Davis Professor Dame Ann Dowling Brendan Nelson Phuthuma Nhlekoc Paula Rosput Reynolds Sir John Sawers Andrew Shilston a Appointed on 31 October 2016. b Held as ADSs. c Retired on 14 April 2016. Ordinary shares or equivalents at 1 Jan 2016 – 30,000b 44,772b 24,864b 10,156 10,500b 23,854 22,320 11,040 – 52,200b 13,528 15,000 Ordinary shares or equivalents at 31 Dec 2016 47,855 30,000b 44,772b 24,864b – 10,500b 25,735 22,320 11,040 – 52,200b 13,528 15,000 Change from 31 Dec 2016 to 22 March 2017 52,145 – – – – – – – – – 6,000 – – Ordinary shares or equivalents total at 22 March 2017 100,000 30,000b 44,772b 24,864b – 10,500b 25,735 22,320 11,040 – 58,200b 13,528 15,000 Value of current shareholding £454,750 $169,950 $253,633 $140,855 – $59,483 £117,030 £101,500 £50,204 – $329,703 £61,519 £68,213 % of policy achieved 505 140 209 116 – 49 130 113 56 – 271 68 57 Past directors Sir Ian Prosser (who retired as a non-executive director of BP in April 2010) was appointed as a director and non-executive chairman of BP Pension Trustees Limited on 1 October 2010. During 2016, he received £100,000 for this role. 98 BP Annual Report and Form 20-F 2016Executive directors Deferred shares (audited)a Bob Dudleyb Dr Brian Gilvary 2013 Bonus year 2012 Type Comp Vol Mat Comp Mat 2014d Comp Vol Mat 2015e Comp Vol Mat Comp Vol Mat Comp Mat 2014d Comp Vol Mat 2015e Comp Vol Mat 2013 2012 Former executive directors Iain Conn 2012 Comp Vol Mat 2013 Comp Mat 2012 Comp Vol Mat Dr Byron Groteb Performance period 2013-2015 2013-2015 2013-2015 2014-2016 2014-2016 2015-2017g 2015-2017g 2015- 2017g 2016-2018g 2016-2018g 2016-2018g 2013-2015 2013-2015 2013-2015 2014-2016 2014-2016 2015-2017 2015-2017 2015-2017 2016-2018 2016-2018 2016-2018 2013-2015 2013-2015 2013-2015 2014-2016 2014-2016 2013-2015 2013-2015 2013-2015 Date of award of deferred shares 11 Feb 2013 11 Feb 2013 11 Feb 2013 12 Feb 2014 12 Feb 2014 11 Feb 2015 11 Feb 2015 11 Feb 2015 4 Mar 2016 4 Mar 2016 4 Mar 2016 11 Feb 2013 11 Feb 2013 11 Feb 2013 12 Feb 2014 12 Feb 2014 11 Feb 2015 11 Feb 2015 11 Feb 2015 4 Mar 2016 4 Mar 2016 4 Mar 2016 11 Feb 2013 11 Feb 2013 11 Feb 2013 12 Feb 2014 12 Feb 2014 11 Feb 2013 11 Feb 2013 11 Feb 2013 Deferred share element interests Potential maximum deferred shares At 1 Jan 2016 114,690 114,690 229,380 149,628 149,628 147,054 147,054 294,108 – – – 78,815 78,815 157,630 96,653 96,653 88,288 88,288 176,576 – – – 80,648 80,648 107,531f 100,563 33,521f 97,278 97,278 32,424f Awarded 2016 – – – – – – – – 275,892 275,892 551,784 – – – – – – – – 159,021 159,021 318,042 – – – – – – – – At 31 Dec 2016 – – – 149,628 149,628 147,054 147,054 294,108 275,892 275,892 551,784 – – – 96,653 96,653 88,288 88,288 176,576 159,021 159,021 318,042 – – – 100,563 33,521f – – – Interests vested in 2016 and 2017 Number of ordinary shares vested – – – – – – Vesting date 134,856c 9 Feb 2016 134,856c 9 Feb 2016 269,712c 9 Feb 2016 180,450c 24 Feb 2017 180,450c 24 Feb 2017 – – – – – – 95,226c 9 Feb 2016 95,226 c 9 Feb 2016 190,453c 9 Feb 2016 117,035c 24 Feb 2017 117,035c 24 Feb 2017 – – – – – – – – – – – – 97,441c 9 Feb 2016 97,441c 9 Feb 2016 129,922c 9 Feb 2016 121,770c 24 Feb 2017 40,590c 24 Feb 2017 114,384c 9 Feb 2016 114,384c 9 Feb 2016 38,124c 9 Feb 2016 £ Face value of the award – – – – – 655,861 655,861 1,311,722 1,015,283 1,015,283 2,030,565 – – – – – 393,764 393,764 787,529 585,197 585,197 1,170,395 – – – – – – – – Comp = Compulsory. Vol = Voluntary. Mat = Matching. a Since 2010, vesting of the deferred shares has been subject to a safety and environmental sustainability hurdle, and this will continue. If the committee assesses that there has been a material deterioration in safety and environmental performance, or there have been major incidents, either of which reveal underlying weaknesses in safety and environmental management, then it may conclude that shares should vest only in part, or not at all. In reaching its conclusion, the committee will obtain advice from the SEEAC. There is no identified minimum vesting threshold level. b Bob Dudley and Dr Byron Grote received awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares. c Represents vestings of shares made at the end of the relevant performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares vested. The market price of each share used to determine the total value at vesting on the vesting dates of 9 February 2016 and 24 February 2017 were £3.34 and £4.47 respectively and for ADSs on 9 February 2016 and 24 February 2017 were $28.95 and $33.50 respectively. d The face value has been calculated using the market price of ordinary shares on 11 February 2015 of £4.46. e The market price at closing of ordinary shares on 4 March 2016 was £3.68 and for ADSs was $31.15. The sterling value has been used to calculate the face value. f All matching shares have been pro-rated to reflect actual service during the performance period and these figures have been used to calculate the face value. g Bob Dudley has voluntarily agreed to defer vesting of these awards until after retirement. Therefore the performance period is expected to exceed the minimum term of three years. 99 BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – implementationDirectors’ remuneration report – implementation Executive directors Performance shares (audited) Share element interests Interests vested in 2015 and 2016 Bob Dudleyb Dr Brian Gilvary Performance period 2013-2015 2014-2016 2015-2017e 2016-2018e 2013-2015 2014-2016 2015-2017e 2016-2018e Date of award of performance shares 11 Feb 2013 12 Feb 2014 11 Feb 2015 4 Mar 2016 11 Feb 2013 12 Feb 2014 11 Feb 2015 4 Mar 2016 Potential maximum performance sharesa At 1 Jan 2016 1,384,026 1,304,922 1,501,770 – 637,413 605,544 685,246 – Awarded 2016 – – – 1,809,582 – – – 786,559 At 31 Dec 2016 – 1,304,922 1,501,770 1,809,582 – 605,544 685,246 786,559 Number of ordinary shares vested – – Vesting date 1,234,386c 28 Apr 2016d 629,484c May 2017 – – 583,571c 28 Apr 2016d 293,296c May 2017 – – – – £ Face value of the award – – 6,697,894 6,659,262 – – 3,056,197 2,894,537 Former executive directors Iain Conn Dr Byron Groteb 2013-2015 2014-2016 2013-2015 11 Feb 2013 12 Feb 2014 11 Feb 2013 463,126 220,043 142,278 – – – – 220,043f – 424,006c 28 Apr 2016d 106,578c May 2017 126,894c 28 Apr 2016d – – – a For awards under the 2013-2015, 2014-2016, 2015-2017 and 2016-2018 plans, performance conditions are measured one third on TSR relative to ExxonMobil, Shell, Total and Chevron; one third on operating cash flow; and one third on a balanced scorecard of strategic imperatives. Each performance period ends on 31 December of the third year. There is no identified overall minimum vesting threshold level but to comply with UK regulations a value of 44.4%, which is conditional on the TSR, operating cash flow and each of the strategic imperatives reaching the minimum threshold, has been calculated. b Bob Dudley and Dr Byron Grote received awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares. c Represents vestings of shares made at the end of the relevant performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares vested. The market price of each share at the vesting date of 28 April 2016 was £3.82 and for ADSs was $33.49. For the assumed vestings dated May 2017 a price of £4.73 per ordinary share and $35.39 per ADS has been used. These are the average prices from the fourth quarter of 2016. d The 2013-2015 award vested on 28 April 2016, which resulted in an increase in value at vesting of £4,405 for Iain Conn and a decrease of $23,233 for Byron Grote. Details for Bob Dudley and Brian Gilvary can be found in the single figure table on page 90. e The market price at closing of ordinary shares on 11 February 2015 was £4.46 and for ADSs was $40.35 and on 4 March 2016 was £3.68 and for ADSs was $31.15. f Potential maximum of performance shares element has been pro-rated to reflect actual service during the performance period and these figures have been used to calculate the face value. Share interests in share options plans (audited) Dr Brian Gilvary Option type At 1 Jan 2016 500,000 BP 2011 4,191 SAYE – SAYE Granted – – 3,103 Exercised – 4,191 – At 31 Dec 2016 500,000 – 3,103 Option price £3.72 £3.68 £2.90 Market price at date of exercise Date from which first exercisable Expiry date – 07 Sep 2014 07 Sep 2021 £4.35 01 Sep 2016 28 Feb 2017 – 01 Sep 2019 28 Feb 2020 The closing market prices of an ordinary share and of an ADS on 31 December 2016 were £5.10 and $37.38 respectively. During 2016 the highest market prices were £5.11 and $37.40 respectively and the lowest market prices were £3.10 and $27.64 respectively. BP 2011 = BP 2011 plan. These options were granted to Dr Brian Gilvary prior to his appointment as a director and are not subject to performance conditions. SAYE = Save As You Earn all employee share plan. 100 BP Annual Report and Form 20-F 2016Directors’ remuneration policy Set out below is our directors’ remuneration policy (the ‘policy’) for 2017 and subsequent years. It will be presented to shareholders at the 2017 annual general meeting and, subject to shareholder approval, will take effect for the 2017 financial year. We have developed this policy following a fundamental review of remuneration arrangements and extensive consultation with our major shareholders. Remuneration principles Remuneration principles BP is a global company with a global management team, competing for talent in a demanding environment. The company’s ability to attract and retain the high calibre executives required to lead a global and highly complex business is important for shareholders. The policy has been designed to reflect the global nature of BP’s business and talent pool. The competitive market for top executives both within the oil and gas sector and more broadly provides an important reference point, but is only one of a number of factors considered when the company sets pay. The following principles underpin BP’s revised approach to remuneration for executive directors. 1 2 3 4 Simplification Link to strategy Shareholder alignment Stewardship • Simpler, transparent and fair approach. • Substantial proportion is variable and linked to the delivery of BP’s strategy. • Package is intended to vary with performance. • Outcomes are intended to reflect • Focus on long-term performance. • Pay is intended to reflect shareholder experience. sustainable performance. • Emphasis on share ownership. Key changes The policy is intended to provide a simplified approach with a clear link between delivery of BP’s strategy and pay, while reflecting outcomes for shareholders. The policy has been simplified and clarified in response to shareholder feedback. Certain elements have been updated to reflect developments in the UK market and best practice over the past three years. It is designed to be well-balanced and to support the priorities for BP over the short and long term. We have made a number of important changes to executive directors’ remuneration which result in a significant reduction in the overall variable remuneration opportunity. These include: • Simplified and updated measures to provide a more balanced and rounded assessment of group performance and better alignment with outcomes for shareholders. • Removal of the matching arrangements for the deferred annual bonus. • A revised structure so that the annual bonus pay-out scale will be more demanding in future years. Payment for on-target performance is reduced and the maximum bonus will only be paid if there is outperformance on all targets. • A higher mandatory deferral of annual bonus awards into BP shares from one third to one half of any annual bonus earned. These will vest after three years with no voluntary deferral or match. • Reduction in the GCE’s maximum opportunity for performance shares from 550% of salary to 500%. • Together with the elimination of matching shares this reduces the total maximum available under long-term remuneration (i.e. performance and matching shares) from 700% to 500% of salary for the GCE and from 550% to 450% of salary for the CFO. • Stronger malus and clawback provisions. • Removal of duplicate measures between the annual and long-term elements. Consideration of shareholder views In designing the policy the committee undertook a major review of remuneration, considering how pay would support BP’s strategy and better align with shareholders’ interests. Engagement with major shareholders has been key to this review and the committee chair has consulted with shareholders beginning in May 2016 and running through to this year’s AGM. This multi-stage approach was adopted for the committee to hear and reflect on shareholder feedback while developing the new policy. In direct response to the views received, the policy has been refined over a number of months. We have valued this dialogue with shareholders and remain committed to ensuring a clear and transparent approach to pay. This policy is designed to provide a transparent framework through which shareholders can assess the basis on which the executive directors at BP are paid. 101 BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – policyDirectors’ remuneration report – policy Remuneration policy table – executive directors Salary and benefits Purpose Operation and opportunity Performance framework Annual bonus Purpose To provide fixed remuneration to reflect the scale and complexity of both the business and the role, and to be competitive with the external market. Benefits • The committee expects to maintain benefits at the current level. • Executive directors are entitled to receive those benefits available to all BP employees generally, such as participation in all-employee share plans, sickness pay, relocation assistance and maternity pay. Benefits are not pensionable. • Executive directors may receive other benefits that are judged to be cost effective and appropriate in terms of the individual’s role, time and/or security. These include car-related benefits or cash in lieu, driver, security, assistance with tax return preparation, insurance and medical benefits. The company may meet any tax charges arising on business-related benefits provided to directors, for example security. • The taxable value of benefits provided may fluctuate during the period of this policy, depending on the cost of provision and a director’s personal circumstances. Salary • Salary levels take into account the nature of the role, performance of the business and the individual, market positioning and pay conditions in the wider BP group. When setting salaries, the committee considers practice in other oil and gas majors as well as European and US companies of a similar size, geographic spread and business dynamic to BP. • Salaries are normally set in the home currency of the executive director and are reviewed annually. They may be reviewed at other times where appropriate, for example following a major role change. • Salary levels are specific to the role and individual and therefore there is no maximum salary under the policy. However, when reviewing salaries for executive directors, the committee will consider salary increases for the most senior management and for employees in relevant countries. Percentage increases for executive directors will not exceed that of the broader employee population, other than in specific circumstances identified by the committee (e.g. in response to a substantial change in responsibilities). • Following the 2017 AGM, the annual salaries for the executive directors will be: – Group chief executive – Bob Dudley: $1,854,000. – Chief financial officer – Dr Brian Gilvary: £759,000. • Not applicable To provide variable remuneration dependent on performance against annual financial, operational and safety measures. 50% of the bonus is paid in cash and 50% is mandatorily deferred and held in BP shares for three years to reinforce the long-term nature of the business and the importance of sustainability. Operation and opportunity • The bonus is based on performance against annual measures and targets set at the start of the year, evaluated over the financial year and assessed following the year end. • 50% of the bonus earned is required to be deferred into BP shares for three years. Dividends (or equivalents, including the value of any reinvestment) may accrue in respect of any deferred shares. • Awards are subject to malus and clawback provisions as described on page 105. • Typically the annual bonus earned would be 50% of the maximum available for delivery of performance in line with the annual plan. The level of bonus payable may vary depending on the nature of the performance measure and level of target set. • Executive directors may earn a maximum annual bonus (including any deferral) of up to 225% of salary for stretching performance against the objectives set for the year. The committee intends to set demanding requirements for maximum payment. Performance framework • The committee determines specific measures, weightings and targets each year to reflect the priorities in the annual plan, which is designed to deliver the group’s strategy and is approved by the board. • Measures will typically include a balance of financial, operational and safety measures. Details of the measures will be reported in advance each year in the annual report on remuneration. The committee intends to disclose targets for the annual bonus retrospectively. 102 BP Annual Report and Form 20-F 2016 Performance shares Purpose Operation and opportunity Performance framework To link the largest part of remuneration opportunity with the long-term performance of the business. The outcome varies with performance against measures linked directly to strategic priorities. • Annual awards of shares will vest based on performance relative to measures and targets that reflect the delivery of BP’s strategy. Performance will normally be measured over a period of at least three years. • The maximum annual award level for the group chief executive will be 500% of salary and 450% of salary for the chief financial officer. • Performance shares will only vest to the extent that performance targets are met. The level of vesting for performance will depend on the stretch of the objective set, but the threshold level would normally • Performance shares may vest based on a combination of total shareholder return, financial and strategic measures. • For 2017 awards, the measures and weightings will be: – total shareholder return relative to oil and gas majors (50%) – return on average capital employed (30%) – strategic progress (20%) • Details of 2017 targets relating to the total shareholder return and return on average capital employed measures are outlined in the remuneration report. Details relating to strategic progress will be disclosed retrospectively. not be expected to exceed 25% of the maximum opportunity for the relevant element. • Once performance has been measured, a proportion of the shares that will vest are subject to a holding period. The combined length of the performance and holding periods will be normally six years. • Dividends (or equivalents, including the value of reinvestment) may accrue in respect of vested shares. • Awards are subject to malus and clawback provisions as described on page 105. • Prior to granting each award the committee will review the measures, weightings and targets to ensure they remain focused on delivering the strategy and are in the interests of shareholders. • At least 40% of any award will be subject to measures linked to shareholder returns and the proportion linked to strategic progress will not exceed 30%. The committee would consult appropriately with major shareholders regarding any material changes to the measures. Shareholding requirements Purpose To provide alignment between the interests of executive directors and our other shareholders. Operation and opportunity Performance framework Retirement benefits • An executive director is expected to build up and maintain a minimum shareholding of five times their base salary within five years of their appointment. • Not applicable. Purpose To recognize competitive practice in home country. Operation and opportunity • Executive directors normally participate in the company retirement plans that operate in their home country. • Senior executives in BP have generally been employees of the group for a number of years. They often remain participants in long-standing arrangements in which other group employees continue to participate, but which are no longer offered to new employees. The maximum opportunity will vary depending on the terms of these arrangements. • UK participants may remain members of the company’s defined benefit plan. In common with other employees in this plan, they may choose to receive up to 35% of salary in lieu as a cash supplement but do not receive further service accrual under this plan. The level of this allowance is expected to reduce in future, in line with the proposed reduction for other UK employees who participate in this arrangement. • US executive directors participate in long-standing plans of Amoco and Arco and other BP defined benefit and retirement savings plans for US employees. • For future appointments, the committee will carefully review any retirement benefits to be granted to a new director. This will take account of retirement policies across the wider group, any arrangements currently in place, local market practice and individual circumstances. The committee will consider retirement benefits in the context of the overall approach to remuneration. Performance framework • Retirement benefits in the UK are not directly linked to performance. Reflecting local market practice, legacy arrangements in the US may reference bonuses when determining the benefit level. 103 BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – policyDirectors’ remuneration report – policy Notes to the policy table How is variable pay linked to performance under the new policy? Annual bonus Performance shares Share ownership 50% paid in cash; 50% in BP shares deferred for 3 years 6 years: 3-year performance period + 3-year holding period Built up over 5 years and maintained The three elements described above provide a balance between focus on short-term, medium-term and long-term performance, while encouraging behaviours which are in the long-term interests of shareholders. The operation of variable pay is supported by a focus on stewardship. There is an expectation that executives will build up a holding of five times salary over a period of five years following appointment and maintain that level during employment. How are performance measures linked to the strategy under the new policy? Variable pay is linked to performance measures designed to deliver the BP strategy. At the start of each year, the remuneration committee reviews the measures, targets and weightings to ensure they remain consistent with the priorities in the annual plan and the group strategy. For the annual bonus and performance shares, the approach to performance measurement is intended to provide a balance of measures to assess performance reflecting the global scale of the business and unique characteristics of the oil and gas sector. The measures for the 2017 awards are summarized below, with further detail set out in the annual report on remuneration on pages 87-88. New remuneration policy measures for period commencing in 2017 Annual bonus 1 Safety 20% Recordable injury frequency Tier 1 process safety events Performance shares 1 Relative TSR 50% TSR relative to five oil and gas majors Rankings: 1st = 100% of award 2nd = 80% 3rd = 25% 2 Reliable operations 3 Financial performance 30% Upstream operating efficiency Downstream refining availability (Solomon Associates’ operational availability) 50% Operating cash flow (excluding Gulf of Mexico oil spill payments) Underlying replacement cost profit Upstream unit production costs 2 Return on capital employed 3 Strategic progress 30% Absolute ROACE (with target disclosed in advance) Evaluation will be based on final year of three-year period 20% Based on a balanced assessment of performance against key strategic priorities. Underpin: Take into account absolute TSR and safety/environmental factors prior to determining final vesting outcome. Discretion to reflect broader environment Robust malus and clawback • The annual bonus is determined based on performance against measures and targets from the annual plan, which is designed to implement BP’s strategy. Performance measures include a range of financial, operating and safety metrics. • Measures for performance share awards provide alignment with shareholder returns and long-term sustainable performance. • The combination of measures provides a diverse and rounded assessment of performance with appropriate checks and balances. • The committee reviews BP’s underlying performance and external market reference points, as well as performance against specific measures and targets. It also seeks input from the board’s audit and safety, ethics and environmental assurance committees on relevant aspects before determining final outcomes. For the performance share awards, the committee will consider longer-term safety and environmental performance as an underpin when evaluating outcomes. This will take into account both absolute shareholder returns and safety and environmental factors, including consideration of issues around carbon and climate change, prior to determining the actual vesting levels. • When appropriate, the committee may make adjustments, upwards or downwards, to a straight formulaic outcome based on the group’s broader performance and the outcomes for shareholders. The committee considers that this informed judgement is important to establishing an overall assessment of performance. 104 BP Annual Report and Form 20-F 2016Long-term shareholdingBonus aligned with annual objectivesShare award for meeting three-year targets How will we use flexibility, judgement and discretion? The committee is empowered to make quantitative and qualitative assessments of performance in reaching its decisions. This involves the use of judgement and discretion within a transparent framework approved by shareholders. The committee continues to consider that the powers of flexibility, judgement and discretion are critical to the successful execution of the policy. In framing the policy, the committee has taken care to ensure that these important powers continue to be available: • Sufficient flexibility to take account of future changes in the industry environment and in remuneration practice generally. This allows the committee to respond to changes in circumstances, for example in applying particular performance measures within the plans which may need to evolve with the company’s strategy, without the need for specific shareholder approval. • Power to exercise judgement in making a qualitative assessment in certain circumstances. A number of measures are used for annual or long-term incentive awards, many of which are numerical in nature and require a quantitative assessment of performance. Others may require a qualitative assessment. How will we safeguard against payments for failure? • Scope for the committee to exercise discretion, mainly where it is desirable to vary a formulaic outcome that would otherwise arise from the policy’s implementation. The committee considers that the ability to exercise discretion, upwards or downwards, is important to ensure that a particular outcome is fair in light of the director’s own performance, the company’s overall performance and positioning under particular performance measures and outcomes for shareholders. In accordance with UK regulations, areas where the remuneration policy provides for the exercise of discretion are identified in this report. The committee intends to provide appropriate disclosure on the use of discretion so that shareholders can understand the basis for its decisions. Performance based pay Discretion Malus and clawback • A significant portion of remuneration varies with performance – where performance targets are not achieved, lower or no payments will be made under the plans. • The committee may vary formulaic outcomes where these do not suitably reflect performance over the relevant performance period. • The malus provisions enable the committee to • The clawback provisions enable the committee to reduce the size of award, cancel an unvested award, or impose further conditions on an award made under this policy. require participants to return some or all of an award after payment or vesting. They may be applied under the following circumstances: • The malus provisions may apply if, prior to the − incorrect outcomes due to miscalculation or based vesting or payment of an award, there is a negative event such as: on incorrect information − restatement due to financial reporting failure or − material failure impacting safety or environmental misstatement of audited results − material misconduct by the participant. sustainability − incorrect award outcomes due to miscalculation or based on incorrect information − restatement due to financial reporting failure or misstatement of audited results − material misconduct by the participant − such other exceptional circumstances that the committee consider to be similar in nature. 105 BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – policyDirectors’ remuneration report – policy Illustration of application of remuneration policy The total remuneration opportunity for executive directors is strongly performance based and weighted to the long term. The charts below provide scenarios for the total remuneration of executive directors at different levels of performance and are calculated as prescribed in UK regulations. Bob Dudley Min 100% $2.33m Dr Brian Gilvary Min 100% £1.09m Mid 26% 23% 51% $9.05m Mid 30% 23% 47% £3.65m Max 15% 26% 59% $15.77m Max 18% 27% 55% £6.21m Fixed pay Annual bonus Performance shares Fixed pay Annual bonus Performance shares Component For these illustrations base salary, benefits and pension are the same in all three scenarios Base salary GCE: $1,854,000 CFO: £759,000 Benefits and retirement benefits GCE: $474,000 CFO: £332,000 Based on salary effective following the AGM. Benefits are based on the value shown in the 2016 single figure table. Mr Dudley’s assumed pension value is based on illustrative returns from his retirement savings plans. Dr Gilvary’s retirement benefits assume an allowance of 35% of salary. Component Variable pay under the new policy comprises annual bonus and performance shares Scenario Minimum Mid Maximum Annual bonus (including cash and deferred elements) Performance sharesb Threshold not met Nil Threshold not met GCE – Nil CFO – Nil 50% of maximum 112.5% of salary 50% vestinga GCE – 250% of salary CFO – 225% of salary 100% of maximum 225% of salary 100% vesting GCE – 500% of salary CFO – 450% of salary a Note that this is an indicative figure. The average vesting level for BP performance shares between 2010-2016 was 34%. b Amounts in respect of performance shares and deferred annual bonus are shown at face value excluding the impact of share price growth and dividends. 106 BP Annual Report and Form 20-F 2016Recruitment policy The committee expects any new executive director to be engaged on terms that are consistent with the policy. However it recognizes that it cannot anticipate circumstances in which any new executive director may be recruited. The committee may determine that it is in the interests of the company and shareholders to secure the services of a particular individual which may require it to take account of the terms of that individual’s existing employment and/or their personal circumstances. Accordingly, the committee will ensure that: • The salary level of any new director is appropriate to their role and the competitive environment at the time of appointment. Where appropriate it may appoint an individual on a lower salary, then gradually increase salary levels as the individual gains experience in the role. • Variable remuneration will be awarded within the parameters of the policy. • The committee may tailor the vesting criteria for initial incentive awards depending on the specific circumstances. • Where an existing employee is promoted to the board, the company may honour all existing contractual commitments including any outstanding share awards or pension entitlements. • The committee would expect any new director to participate in the company pension and benefit schemes that are open to other senior employees (where appropriate referencing the candidate’s home country) but would take into account the director’s existing arrangements and market norms. Service contract • Where an individual is relocating in order to take up the role, the company may provide certain one-off benefits such as reasonable relocation expenses, accommodation for a period following appointment, assistance with visa applications or other immigration issues and ongoing arrangements such as tax equalization, annual flights home and a housing allowance. • Where an individual would be forfeiting remuneration or employment terms in order to join the company, the committee may award appropriate compensation. The committee would require reasonable evidence of the nature and value of any forfeited arrangements and would, to the extent practicable, ensure any compensation was of comparable commercial value and capped as appropriate, taking into account the terms of the previous arrangement being forfeited (for example the form and structure of award, timeframe, performance criteria and likelihood of vesting). Where appropriate, the committee would have a preference for buy-outs to be delivered in the form of shares in the company. In making any decision on the remuneration of a new director, the committee would balance shareholder expectations, current best practice and the circumstances of any new director. It would strive not to pay more than is necessary to recruit the right candidate and would give full details in the next remuneration report. Bob Dudley’s service contract is with BP Corporation North America Inc. Dr Brian Gilvary’s service contract is with BP p.l.c. The employer may lawfully terminate the executive director’s employment in the following ways: Each executive director is entitled to pension provision as outlined on page 103. Each executive director is also entitled to the following contractual benefits: • For security reasons, a company car and driver is provided for business and private use. The company will bear all normal servicing, insurance and running costs. • Medical and dental benefits, sick pay during periods of absence and assistance with the preparation of tax returns. • Indemnification in accordance with applicable law. • Participation in bonus or incentive arrangements at the committee’s sole discretion. Each executive director may terminate their employment by giving 12 months’ written notice. In this event, for business reasons, the employer may not necessarily hold the executive director to their full notice period. • By giving the director 12 months’ written notice. • Without compensation, in circumstances where the employer is entitled to terminate for cause, as defined for the purposes of their service contract. Additionally, in the case of Dr Brian Gilvary, the company may lawfully terminate employment by making a lump sum payment in lieu of notice equal to 12 months’ base salary or by monthly instalments rather than as a lump sum. The lawful termination mechanisms described above are without prejudice to the employer’s ability in appropriate circumstances to terminate in breach of the notice period referred to above, and thereby to be liable for damages to the executive director. In the event of termination by the company, each executive director may have an entitlement to compensation in respect of their statutory rights under employment protection legislation in the UK and potentially elsewhere. Where appropriate the company may also meet a director’s reasonable legal expenses in connection with either their appointment or termination of their appointment. 107 BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – policyTermination payments In determining overall termination arrangements, the committee will distinguish between types of leaver and the circumstances of their leaving. The committee would also consider all relevant circumstances, including whether a contractual provision in the director’s arrangements complied with best practice at the time of termination and the date the provision was agreed, as well as the performance of the director in certain respects. Where appropriate, the committee may consider providing certain benefits relating to termination including the provision of outplacement support or costs associated with relocation back to an individual’s home country. Should it become necessary to terminate an executive director’s employment, and therefore to determine a termination payment, the committee’s policy is as follows: Termination payments Annual bonus Share awards • The director’s primary entitlement would be a termination payment in respect of their service agreement, as set out above. However the committee will consider mitigation to reduce the termination payment where appropriate to do so, taking into account the circumstances for leaving and the terms of the agreement. Mitigation would not be applicable where a contractual payment in lieu of notice is made. • If the departing director is eligible for an early retirement pension, the committee would consider, if relevant under the terms of the appropriate plan, the extent of any actuarial reduction that should be applied. UK directors who leave in circumstances approved by the committee may have a favourable actuarial reduction applied to their pensions (which to date has been 3%). Departing directors who leave in other circumstances may be subject to a greater reduction. • The committee would consider whether the director should be entitled to an annual bonus in respect of the financial year in which the termination occurs. Normally, any such bonus would be restricted to the director’s actual period of service in that financial year. • In deciding whether to exercise discretion to preserve EDIP awards, the committee would also consider the proximity of the award to its maturity date. • Share awards will be treated in accordance with the relevant plan rules. For awards granted under the Executive Directors’ Incentive Plan (EDIP), the treatment can only be made in accordance with the framework approved by shareholders. • The committee would consider whether conditional share awards held by the director should lapse on leaving or should, at the committee’s discretion, be preserved. If awards are preserved, the award would normally continue until the vesting date. Awards may be pro-rated based on service over the performance period. 108 BP Annual Report and Form 20-F 2016Directors’ remuneration report – policyDirectors’ remuneration report – policy Legacy arrangements and other detailed provisions Previously the deferred element of the annual bonus in respect of years up to and including 2016 attracted a corresponding award of matching shares. Although the committee will no longer grant matching awards in respect of future bonus awards, executives retain interests in legacy awards previously granted under this arrangement under the terms set out in the 2014 policy. For completeness, the table below summarizes the key terms of the previous matching share element. Legacy incentives: deferred bonus and matching shares (no further awards to be granted) Purpose Operation To reinforce the long-term nature of the business and the importance of sustainability. • Previously one third of the annual bonus was • Where shares vest, additional shares representing subject to compulsory deferral and a further third was subject to voluntary deferral. • These deferred shares were matched on a one-for-one basis. Performance framework • Both deferred and matching shares must pass an additional hurdle related to safety and environmental sustainability performance in order to vest. the value of reinvested dividends are added. • All deferred shares are subject to clawback provisions if they are found to have been granted on the basis of a material misstatement of financial or other data. • If there has been a material deterioration in safety and environmental metrics, or major incidents revealing underlying weaknesses in safety and environmental management then the committee, with advice from the board’s safety, ethics and environmental assurance committee, may conclude that shares vest in part, or not at all. In addition to the award described above, the committee may continue to satisfy existing remuneration commitments and/or payments for loss of office, including the exercise of any discretion in connection with such payments provided that such terms were agreed: • before 10 April 2014 when the first approved remuneration policy came into effect • before the 2017 policy came into effect, provided that the terms of the payment were consistent with the shareholder-approved directors’ remuneration policy in force at the time they were agreed • at a time when the relevant individual was not a director of the company and, in the opinion of the committee, the payment was not in consideration for the individual becoming a director. Share awards are subject to the terms of the relevant plan rules under which the award has been granted. The committee may adjust or amend awards, but only in accordance with the provisions of the plan rules. This includes making adjustments to awards to reflect one-off corporate events, such as a change in the company’s capital structure or treatment of awards in the event of a change of control. In accordance with the plan rules, awards may be settled in cash rather than shares, where the committee considers this appropriate. The committee may make minor amendments to the policy to aid its operation or implementation without seeking shareholder approval, for example for regulatory, exchange control, tax or administrative purposes or to take account of a change in legislation provided that any such change is not to the material advantage of the directors. Remuneration in the wider group The committee considers employment conditions in the BP group when establishing and implementing policy for executive directors to ensure the alignment of and context for principles and approach. In particular, the committee reviews the policy for the most senior leaders. The wider employee group participates in performance-based incentives. Throughout the group, base salary and benefit levels are set in accordance with the prevailing relevant market conditions and practice in the countries in which employees are based. Decisions regarding remuneration for employees outside the group leaders are the responsibility of the GCE. The committee does not consult directly with employees when formulating the policy. However, feedback from employee surveys, that are regularly reported to the board, provide views on a wide range of employee matters including pay. Differences between executive director pay policy and that of other employees reflect the senior position of the individuals, prevailing market conditions and corporate governance practices in respect of executive director remuneration. The key difference in policy for executive directors is that a greater proportion of total remuneration is delivered as performance-based incentives. 109 BP Annual Report and Form 20-F 2016Corporate governanceRemuneration policy table – non-executive directors Non-executive chairman Fees Approach Remuneration is in the form of cash fees, payable monthly. The level and structure of the chairman’s remuneration will primarily be compared against UK best practice. Operation and opportunity The quantum and structure of the non-executive chairman’s remuneration is reviewed annually by the remuneration committee, which makes a recommendation to the board. Benefits and expenses Approach Operation and opportunity The chairman is provided with support and reasonable travelling expenses. The chairman is provided with an office and full time secretarial and administrative support in London and a contribution to an office and secretarial support in his home country as appropriate. A car and the use of a driver is provided in London, together with security assistance. All reasonable travelling and other expenses (including any relevant tax) incurred in carrying out his duties is reimbursed. Non-executive directors Fees Approach Remuneration is in the form of cash fees, payable monthly. Remuneration practice is consistent with recognized best practice standards for non-executive directors’ remuneration and, as a UK-listed company, the level and structure of non-executive directors’ remuneration will primarily be compared against UK best practice. Additional fees may be payable to reflect additional board responsibilities, for example, committee chairmanship and membership and for the role of senior independent director. Operation and opportunity The level and structure of non-executive directors’ remuneration is reviewed by the chairman, the GCE and the company secretary who make a recommendation to the board. Non-executive directors do not vote on their own remuneration. Remuneration for non-executive directors is reviewed annually. Other fees and benefits Intercontinental allowance Approach Operation and opportunity Benefits and expenses Non-executive directors receive an allowance to reflect the global nature of the company’s business. The intercontinental travel allowance is payable for the purpose of attending board or committee meetings or site visits. The allowance is paid in cash following each event of intercontinental travel. Approach Non-executive directors are provided with administrative support and reasonable travelling expenses. Professional fees are reimbursed in the form of cash, payable following the provision of advice and assistance. Operation and opportunity Non-executive directors are reimbursed for all reasonable travelling and subsistence expenses (including any relevant tax) incurred in carrying out their duties. The reimbursement of professional fees incurred by non-executive directors based outside the UK in connection with advice and assistance on UK tax compliance matters. The maximum fees for non-executive directors are set in accordance with the Articles of Association. This directors’ remuneration report was approved by the board and signed on its behalf by David J Jackson, company secretary on 6 April 2017. 110 BP Annual Report and Form 20-F 2016Directors’ remuneration report – policyDirectors’ statements Statement of directors’ responsibilities The directors are responsible for preparing the Annual Report and the financial statements in accordance with applicable law and regulations. The directors are required by the UK Companies Act 2006 to prepare financial statements for each financial year that give a true and fair view of the financial position of the group and the parent company and the financial performance and cash flows of the group and parent company for that period. Under that law they are required to prepare the consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union (EU) and applicable law and have elected to prepare the parent company financial statements in accordance with applicable United Kingdom law and United Kingdom accounting standards (United Kingdom generally accepted accounting practice). In preparing the consolidated financial statements the directors have also elected to comply with IFRSs as issued by the International Accounting Standards Board (IASB). In preparing those financial statements, the directors are required to: • select suitable accounting policies and then apply them consistently. • make judgements and estimates that are reasonable and prudent. • present information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information. • provide additional disclosure when compliance with the specific requirements of IFRS is insufficient to enable users to understand the impact of particular transactions, other events and conditions on the group’s financial position and financial performance. • state that applicable accounting standards have been followed, subject to any material departures disclosed and explained in the parent company financial statements. • prepare the financial statements on the going concern basis unless it is inappropriate to presume that the company will continue in business. The directors are responsible for keeping proper accounting records that disclose with reasonable accuracy at any time the financial position of the group and company and enable them to ensure that the consolidated financial statements comply with the Companies Act 2006 and Article 4 of the IAS Regulation and the parent company financial statements comply with the Companies Act 2006. They are also responsible for safeguarding the assets of the group and company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities. Risk management and internal control Under the UK Corporate Governance Code (Code), the board is responsible for the company’s risk management and internal control systems. In discharging this responsibility the board, through its governance principles, requires the group chief executive to operate the company with a comprehensive system of controls and internal audit to identify and manage the risks that are material to BP. In turn, the board, through its monitoring processes, satisfies itself that these material risks are identified and understood by management and that systems of risk management and internal control are in place to mitigate them. These systems are reviewed periodically by the board, have been in place for the year under review and up to the date of this report and are consistent with the requirements of principle C.2 of the Code. The board has processes in place to: • assess the principal risks facing the company. • monitor the company’s system of internal control (which includes the ongoing process for identifying, evaluating and managing the principal risks). • review the effectiveness of that system annually. Non-operated joint ventures and associates have not been dealt with as part of this board process. A description of the principal risks facing the company, including those that could potentially threaten its business model, future performance, solvency or liquidity, is set out in Risk factors on page 49. During the year, the board undertook a robust assessment of the principal risks facing the company. The principal means by which these risks are managed or mitigated are set out in How we manage risk on page 47. In assessing the risks faced by the company and monitoring the system of internal control, the board and the audit, safety, ethics and environment assurance and geopolitical committees requested, received and reviewed reports from executive management, including management of the business segments, corporate activities and functions, at their regular meetings. A report by each of these committees, including its activities during the year, is set out on pages 64-78. During the year, the committees also met with management, the group head of audit and other monitoring and assurance functions (including group ethics and compliance, safety and operational risk, group control, group legal and group risk) and the external auditor. Responses by management to incidents that occurred were considered by the appropriate committee or the board. Having made the requisite enquiries, so far as the directors are aware, there is no relevant audit information (as defined by Section 418(3) of the Companies Act 2006) of which the company’s auditors are unaware, and the directors have taken all the steps they ought to have taken to make themselves aware of any relevant audit information and to establish that the company’s auditors are aware of that information. A board meeting in February 2017 carried out an annual review of the effectiveness of the system of internal control. In considering this system, the board noted that it is designed to manage, rather than eliminate, the risk of failure to achieve business objectives and can only provide reasonable, and not absolute, assurance against material misstatement or loss. The directors confirm that to the best of their knowledge: • the consolidated financial statements, prepared in accordance with IFRS as issued by the IASB, IFRS as adopted by the EU and in accordance with the provisions of the Companies Act 2006, give a true and fair view of the assets, liabilities, financial position and profit or loss of the group. • the parent company financial statements, prepared in accordance with United Kingdom generally accepted accounting practice, give a true and fair view of the assets, liabilities, financial position, performance and cash flows of the company. • the management report, which is incorporated in the strategic report and directors’ report, includes a fair review of the development and performance of the business and the position of the group, together with a description of the principal risks and uncertainties that they face. This review included a report from the group head of audit which summarized group audit’s consideration of the design and operation of elements of BP’s system of internal control over significant risks arising in the categories of strategic and commercial, safety and operational and compliance and control and considered the control environment for the group. The report also highlighted the results of internal audit work conducted during the year and the remedial actions taken by management in response to failings and weaknesses identified. Where failings or weaknesses were identified, the board was satisfied that these were or are being appropriately addressed by the remedial actions proposed by management. A statement regarding the company’s internal controls over financial reporting is set out on page 267. C-H Svanberg Chairman 6 April 2017 This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 111 BP Annual Report and Form 20-F 2016Corporate governanceLonger-term viability In accordance with provision C.2.2 of the Code, the directors have assessed the prospects of the company over a period significantly longer than 12 months. The directors believe that an assessment period of three years is appropriate based on management’s reasonable expectations of the position and performance of the company over this period, taking account of its short-term and longer-range plans. Taking into account the company’s current position and its principal risks, the directors have a reasonable expectation that the company will be able to continue in operation and meet its liabilities as they fall due over three years. The directors’ assessment included a review of the financial impact of the most severe but plausible scenarios that could threaten the viability of the company and the likely effectiveness of the potential mitigations that management reasonably believes would be available to the company over this period. In assessing the prospects of the company, the directors noted that such assessment is subject to a degree of uncertainty that can be expected to increase looking out over time and, accordingly, that future outcomes cannot be guaranteed or predicted with certainty. Going concern In accordance with provision C.1.3 of the Code, the directors have made an assessment of the group’s ability to continue as a going concern and consider it appropriate to adopt the going concern basis of accounting in preparing the financial statements. Fair, balanced and understandable The board considers the Annual Report and financial statements, taken as a whole, is fair, balanced and understandable and provides the information necessary for shareholders to assess the company’s position and performance, business model and strategy. This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 112 BP Annual Report and Form 20-F 2016Financial statements 114 Consolidated financial statements of the BP group Independent auditor’s reports Group income statement Group statement of comprehensive income 114 122 123 Group statement of changes in equity Group balance sheet Group cash flow statement 126 Notes on financial statements 123 124 125 157 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 126 136 Significant accounting policies Significant event – Gulf of Mexico oil spill Non-current assets held for sale 139 Disposals and impairment 140 Segmental analysis 142 Income statement analysis Exploration expenditure Taxation Dividends Earnings per ordinary share Property, plant and equipment 145 146 146 148 148 150 150 151 152 12. Capital commitments 13. Goodwill 14. 15. Intangible assets Investments in joint ventures 153 Investments in associates 153 155 155 16. 17. Other investments Inventories 18. Trade and other 19. receivables 156 20. Valuation and qualifying accounts 156 Trade and other payables 156 21. 22. 23. Provisions Pensions and other post- retirement benefits 157 24. Cash and cash equivalents 163 25. 163 26. Capital disclosures and Finance debt analysis of changes in net debt 27. Operating leases 28. Financial instruments and financial risk factors 29. Derivative financial instruments 30. Called-up share capital 31. Capital and reserves 32. Contingent liabilities 33. Remuneration of senior management and non- executive directors Employee costs and numbers 34. 35. Auditor’s remuneration 36. Subsidiaries, joint arrangements and associates 37. Condensed consolidating information on certain US subsidiaries 164 164 165 168 172 174 177 178 179 179 180 181 i F n a n c a i l s t a t e m e n t s 187 Supplementary information on oil and natural gas (unaudited) Oil and natural gas exploration and production activities Movements in estimated net proved reserves 188 194 Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves Operational and statistical information 215 Parent company financial statements of BP p.l.c. Company balance sheet Company statement of changes in equity Notes on financial statements 1. Significant accounting policies Investments Receivables Pensions Payables Taxation Called-up share capital 2. 3. 4. 5. 6. 7. 215 216 217 217 219 220 220 223 224 224 Capital and reserves Financial guarantees 8. 9. 10. Share-based payments 11. Auditor’s remuneration 12. Directors’ 13. remuneration Employee costs and numbers 14. Related undertakings of the group 209 212 225 225 225 225 226 226 227 BP Annual Report and Form 20-F 2016 113 Consolidated financial statements of the BP group Independent auditor’s report on the Annual Report and Accounts to the members of BP p.l.c. Opinion on financial statements In our opinion: • the financial statements give a true and fair view of the state of the group’s and of the parent company’s affairs as at 31 December 2016 and of the group’s profit for the year then ended; • the group financial statements have been properly prepared in accordance with IFRS as adopted by the European Union; • the parent company financial statements have been properly prepared in accordance with United Kingdom generally accepted accounting practice including FRS 101 ‘Reduced Disclosure Framework’; and • the financial statements have been prepared in accordance with the requirements of the Companies Act 2006 and, as regards the group financial statements, Article 4 of the IAS Regulation. Separate opinion in relation to IFRS as issued by the International Accounting Standards Board As explained in Note 1 to the consolidated financial statements, the group in addition to applying IFRS as adopted by the European Union, has also applied IFRS as issued by the International Accounting Standards Board (IASB). In our opinion the consolidated financial statements comply with IFRS as issued by the IASB. What we have audited We have audited the financial statements of BP p.l.c. for the year ended 31 December 2016 which comprise: Group Parent company Group balance sheet as at 31 December 2016. Balance sheet as at 31 December 2016. Group income statement for the year then ended. Statement of changes in equity for the year then ended. Group statement of comprehensive income for the year then ended. Related Notes 1 to 14 to the financial statements. Group statement of changes in equity for the year then ended. Group cash flow statement for the year then ended. Related Notes 1 to 37 to the financial statements. The financial reporting framework that has been applied in the preparation of the group financial statements is applicable law and International Financial Reporting Standards (IFRS) as adopted by the European Union. The financial reporting framework that has been applied in the preparation of the parent company financial statements is applicable law and United Kingdom accounting standards (United Kingdom generally accepted accounting practice) including FRS 101. Our assessment of the risks of material misstatement We identified the risks of material misstatement described below as those that had the greatest effect on our overall audit strategy, the allocation of resources in the audit and the direction of the efforts of the audit team. In addressing these risks, we designed and performed the procedures below for the purpose of expressing an audit opinion on the financial statements as a whole. We do not express any opinion on these individual risks. Other than as described, these matters are unchanged from those we reported in our 2015 audit opinion. Risk Our response to the risk The determination of the liabilities, contingent liabilities and disclosures arising from the significant uncertainties related to the Gulf of Mexico oil spill (as described on page 71 of the report of the audit committee and Note 2 of the financial statements). Following significant progress in 2016 in resolving outstanding claims, management concluded they were able to reliably estimate the remaining material liabilities arising from the 2010 Deepwater Horizon incident. There is uncertainty around estimating and valuing the remaining outstanding business economic loss claims. The determination of the liability is subject to judgement as to the amount that each remaining claim will be settled at. For the liabilities and contingent liabilities related to the Gulf of Mexico oil spill the primary audit engagement team performed the following audit procedures. • We walked through and tested the controls designed and operated by the group relating to the provisions and payables for the Gulf of Mexico oil spill. • We met with the group’s legal team to understand developments across key remaining Gulf of Mexico oil spill matters and their status. We discussed legal developments with the group’s external lawyers, reviewed audit enquiry response letters from external legal counsel and read determinations and judgments made by the courts. • In respect of the provision for the outstanding business economic loss claims: • We compared the key assumptions that have been used in the determination of the year end provision, to historical experience. These assumptions are the proportion of outstanding claims that will receive a monetary award and the average monetary claim value. • We reconciled the number of undetermined claims to third party claims management data. What we concluded to the Audit Committee We are satisfied that management is able to determine a reliable estimate for the remaining business economic loss claims and that the disclosures presented in relation to contingent liabilities are appropriate. Based on our procedures we are satisfied that the amounts provided in the financial statements, as disclosed in Note 2 of the financial statements, are supported by claims experience. This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 114 BP Annual Report and Form 20-F 2016 Risk Our response to the risk What we concluded to the Audit Committee The current macroeconomic environment has the potential to materially impact the carrying value of the group’s Upstream non-current assets (as described on page 71 of the report of the audit committee and Note 1 of the financial statements). 2016 has been a more uncertain political and macroeconomic environment, influenced by significant political and economic events. Additionally, OPEC decisions on the production of hydrocarbons have a significant effect on prices in global commodity markets. These factors combine to create additional uncertainty in relation to key inputs into future cash flow forecasts, which are used to project the recoverability of the group’s tangible and intangible assets. • We performed sensitivity analyses over average cost per claim assumptions and assessed the potential effect on the provision. • With regard to Plaintiffs’ Steering Committee settlements, we engaged EY actuarial experts to consider the analysis of available claims data undertaken by management. We corroborated the data used in respect of all claim categories, with specific regard to business economic loss, this being the most complex to estimate. Our testing included understanding and verifying trends in the claim models, considering the approach in respect of all claim categories compared with prior periods. • We assessed the remaining economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were excluded from that settlement. We validated a sample of claims to third party data, assessing the year end closing provision was appropriate. • We considered the accounting treatment of the liabilities, contingent liabilities and disclosures under IFRS criteria, to conclude whether these were appropriate in all the circumstances. We extended the scope of our original planned procedures to address the changing risk. This included further use of EY valuation experts in critically assessing and corroborating, to external market data, the revised assumptions used in impairment testing, the most significant of these being future market oil and gas prices and discount rates. We also focused on reserves and resources volumes, as described elsewhere in our report. In addressing this risk, audit procedures were performed by component teams at each of the group’s 10 Upstream components scoped-in for the audit of asset impairment. In addition, the primary audit engagement team tested certain remaining assets identified at risk of impairment. • We walked through and tested the controls designed and operated by the group relating to the assessment of the carrying value of tangible assets. • We examined the methodology used by management to assess the carrying value of tangible assets assigned to cash-generating units, to determine its compliance with accounting standards and consistency of application. • We assessed the centrally-derived oil and gas price assumptions by reference to external market data and engaged EY valuation experts to critically assess the suitability of the revised assumptions. • We evaluated estimates of future cash flows and considered whether these were appropriate in light of future price assumptions and cost budgets. • Together with EY valuation experts we assessed specific inputs to the determination of the discount rate. Such inputs were benchmarked against rates observable in the markets in which the group operates. • We performed procedures over the completeness of the impairment charges and reversals and exploration write-offs, also validating that base data used in the impairment models agreed to the underlying books and records. • We checked the mathematical accuracy of the impairment models. BP’s oil and gas price assumptions are comparable to the range seen within the industry at this time. The methodology used has been applied consistently year on year. The pre-tax discount rate of 9% (2015 11%) and the post- tax discount rate of 6% (2015 7%) are within our range of expectation. The movement year on year is verifiable and reasonable based on market data. Based on our procedures, we believe the impairment charges and certain reversals of previous impairment charges recorded, are appropriate and in accordance with IFRS. Based on our procedures on the exploration portfolio we consider the write-offs were properly recorded and remaining carrying values are appropriate and in accordance with IFRS. This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 115 i F n a n c a i l s t a t e m e n t s Risk Our response to the risk The estimate of oil and gas reserves and resources has a significant impact on the financial statements, particularly impairment testing and depreciation, depletion and amortization (‘DD&A’) charges (as described on page 71 of the report of the audit committee and Note 1 of the financial statements). The estimation of oil and natural gas reserves and resources is a significant area of judgement due to the technical uncertainty in assessing quantities and complex contractual arrangements dictating the group’s share of reportable volumes. Reserves and resources are also a fundamental indicator of the future potential of the group’s performance. Unauthorized trading activity within the integrated supply and trading function has the potential to impact revenue and profits (as described on page 71 of the report of the audit committee and Note 1 of the financial statements). Unauthorized trading activity is a fraud risk associated with a potential deliberate misstatement of the group’s trading positions or mis-marking of positions with an intention to: • Minimize trading losses. • Maximize trading profits. • Understate profits or move profits to subsequent periods when bonus ceilings have already been reached, to maximize individual bonuses across financial years. These acts would lead to a misstatement of the group’s revenue and profits. Audit procedures were performed by team members with significant experience of auditing oil and gas reserves, including the primary audit engagement team and component teams at 10 Upstream components. • We tested the group’s controls over their internal certification process for internal technical and commercial experts who are responsible for reserves and resources estimation. • We assessed the competence and objectivity of the group’s internal and external experts, to satisfy ourselves they were appropriately qualified to carry out the volumes estimation. • We performed procedures to assess the reliability of data provided to external experts. • We confirmed that significant changes in reserves and resources were made in the appropriate period, and in compliance with the Discovered Resources Management Policy (‘DRM-P’). • Where volumetric movements had a material impact on the financial statements, we validated these volumes against underlying information and documentation as required by the DRM-P, along with checking that assumptions used to estimate reserves and resources were made in compliance with relevant regulations. • We validated that the updated reserves and resources estimates were included appropriately in the group’s consideration of impairment and in accounting for DD&A. Audit procedures on revenue and trading were performed by component teams and the primary engagement team at 7 components across the UK, US and Singapore. • We walked through and tested the controls designed and operated by the group over unauthorized trading activity. • We identified trades with the highest risk of unauthorized activity so as to focus our testing on these trades. • We performed existence and completeness testing by confirming a sample of trades with third parties. • We verified the fair value of a sample of derivatives using contract and external market prices. • We tested the completeness of the amounts recorded in the financial statements through performing procedures to detect unrecorded liabilities as well as detailed cut-off procedures around sales, purchases, trade receivables and trade payables. What we concluded to the Audit Committee Based on our procedures we consider that the reserves estimations are reasonable for use in the impairment testing and calculation of DD&A. Based on our procedures we identified no matters to report to the Audit Committee. Changes from the prior year Our risk assessment and audit approach evolve as circumstances which impact the group’s business or financial statements change. Since the 2015 audit we have changed our assessment of the risk of material misstatement as this relates to the group’s investment in Rosneft. The continued demonstration of significant influence by the group over Rosneft, along with the relative stabilization of the current environment in Russia, meant that in our view the profile of this risk had reduced and no longer had a significant effect on our audit strategy or our allocation of resources. The scope of our audit Tailoring the scope Our assessment of audit risk, our evaluation of materiality and our allocation of performance materiality determine our audit scope for each entity within the group. Taken together, this enables us to form an opinion on the consolidated financial statements. We take into account size, risk profile, the organization of the group and effectiveness of group-wide controls, changes in the business environment and other factors such as recent internal audit results when assessing the level of work to be performed at each component. In scoping the audit we reflect the group’s structure (Upstream, Downstream, Rosneft and Other businesses and corporate), plus the group’s functions. In assessing the risk of material misstatement to the group financial statements, and to ensure we had adequate quantitative coverage of significant accounts in the financial statements, we performed full or specific scope audit procedures over 50 components covering the UK, US, Angola, Azerbaijan, Egypt, Germany, India, Iraq, Russia, Singapore, Trinidad and the group functions, representing the principal business units within the group. Of the 50 components selected, we performed an audit of the complete financial information of 9 components (“full scope components”) which were selected based on their size or risk characteristics. For the remaining 41 components (“specific scope components”), we This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 116 BP Annual Report and Form 20-F 2016 performed audit procedures on specific accounts within that component that we considered had the potential for the greatest impact on the significant accounts in the financial statements either because of the size of these accounts or their risk profile. For the current year, the full scope components contributed 29% of the group’s loss before tax (2015 43%), 41% of the group’s revenue (2015 41%) and 10% of the group’s property, plant and equipment (2015 11%). The specific scope components contributed 32% of the group’s loss before tax (2015 10%), 26% of the group’s revenue (2015 29%) and 54% of the group’s property, plant and equipment (2015 55%). The audit scope of the specific scope components may not have included testing of all significant accounts of the component but will have contributed to the coverage of significant accounts tested for the group. Of the 41 specific scope components, we instructed 10 of these locations to perform specified procedures over impairment of goodwill and other intangible assets, recoverability of certain receivables and the carrying value of certain investments held by the group. The remaining components not subject to full or specific group scoping are not significant individually or in the aggregate. They include many small, low risk components and balances; each remaining component represents an average of 0.11% of the total group loss before tax and 0.11% of total group revenue. For these components, we performed other procedures, including evaluating and testing management’s group wide controls across a range of geographies and segments, specifically testing the oversight and review controls that management has in place to ensure there are no material misstatements in these locations. We performed analytical and enquiry procedures to address the risk of residual misstatement on a segment-wide and component basis. We tested consolidation journals to identify the existence of any further risks of misstatement that could have been material to the group financial statements. Involvement with component teams In establishing our overall approach to the group audit, we determined the type of work that needed to be undertaken at each of the components by us, as the primary audit engagement team, or by component auditors from other EY global network firms operating under our instruction. Of the 9 full scope components, audit procedures were performed on 5 of these directly by the primary audit engagement team. For the 41 specific scope components, audit procedures were performed on 25 of these directly by the primary audit engagement team. Testing of management’s group wide controls was performed by component auditors. Where work was performed by component auditors, we determined the appropriate level of involvement to enable us to determine that sufficient audit evidence had been obtained as a basis for our opinion on the group as a whole. The group audit team continued to follow a programme of planned visits designed to ensure that the Senior Statutory Auditor or his designate visits significant locations to ensure the audit is executed and delivered in accordance with the planned approach and to confirm the quality of the audit work undertaken. During the current year’s audit cycle, visits were undertaken by the primary audit engagement team to the component teams in Germany, India, Russia, Singapore, Trinidad and the US. Part of the purpose of these visits is to confirm that appropriate procedures have been performed by the auditors of the components and that the significant audit areas were covered as communicated in the detailed audit instructions, including the risks of material misstatement as outlined above. The primary audit engagement team review included examining key working papers and conclusions where these related to areas of management and auditor judgement with specific focus on the risks detailed above. The primary audit engagement team also participated in the component teams’ planning, during visits made earlier in the audit period. Telephone and video meetings were held with the auditors at locations which the primary audit engagement team did not visit in person. This, together with additional procedures performed at group level, gave us appropriate evidence for our opinion on the group financial statements. One of the significant locations is Russia, which includes Rosneft, a material associate not controlled by BP. We were provided with appropriate access to Rosneft’s auditor in order to ensure they had completed the procedures required by ISA 600 on the financial statements of Rosneft, used as the basis for BP’s equity accounting. Our application of materiality We apply the concept of materiality in planning and performing the audit, in evaluating the effect of identified misstatements on the audit and in forming our audit opinion. Materiality The magnitude of an omission or misstatement that, individually or in the aggregate, could reasonably be expected to influence the economic decisions of the users of the financial statements. Materiality provides a basis for determining the nature and extent of our audit procedures. We determined materiality for the group to be $0.5 billion (2015 $0.5 billion). For our current year audit we changed the basis of determining materiality from current year underlying replacement cost profit before interest and taxation (as defined on page 284) that was used in 2015. In setting audit materiality for the current year we considered the activity levels within the business and the fact that the commodity prices experienced in the current period are below those expected in the coming years by the group and the wider market. We believe it is appropriate in these circumstances to determine materiality based on 5% of the average 2016 underlying replacement cost profit before interest and taxation and how those results would look if the oil and gas prices forecast by the company for 2017 and 2018 had prevailed in the year. These forward earnings have been determined using BP’s Rules of Thumb, available on the website, applied to the 2016 actual results as the base year. Underlying replacement cost profit before interest and taxation remains the most appropriate measure upon which to calculate materiality, due to the fact it excludes the impact of changes in crude oil, gas and product prices and items disclosed as non-operating items, which can significantly distort the group’s results in a given period. For details of non-operating items please see page 241 of the Annual Report and Form 20-F 2016. During the course of our audit, we re-assessed initial materiality in the context of the group’s performance and forward expectations and this resulted in no change from our original assessment of materiality. Performance materiality The application of materiality at the individual account or balance level. It is set at an amount to reduce to an appropriately low level the probability that the aggregate of uncorrected and undetected misstatements exceeds materiality. On the basis of our risk assessments, together with our assessment of the group’s overall control environment, our judgement was that performance materiality was 75% (2015 75%) of our materiality, namely $375 million (2015 $375 million). We have set performance materiality at this percentage to reduce to an appropriately low level the probability that the aggregate of uncorrected and undetected misstatements exceeds materiality. This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 117 i F n a n c a i l s t a t e m e n t s Audit work at component locations for the purpose of obtaining audit coverage over significant financial statement accounts is undertaken based on a percentage of total performance materiality. The performance materiality set for each component is based on the relative scale and risk of the component to the group as a whole and our assessment of the risk of misstatement at that component. In the current year, the range of performance materiality allocated to components was $75 million to $281 million (2015 $75 million to $300 million). Reporting threshold An amount below which identified misstatements are considered as being clearly trivial. We agreed with the audit committee that we would report to them all uncorrected audit differences in excess of $25 million (2015 $25 million), which is set at 5% of materiality, as well as differences below that threshold that, in our view, warranted reporting on qualitative grounds. We evaluate any uncorrected misstatements against both the quantitative measures of materiality discussed above and in light of other relevant qualitative considerations in forming our opinion. Scope of the audit of the financial statements An audit involves obtaining evidence about the amounts and disclosures in the financial statements sufficient to give reasonable assurance that the financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting policies are appropriate to the group’s and the parent company’s circumstances and have been consistently applied and adequately disclosed; the reasonableness of significant accounting estimates made by the directors; and the overall presentation of the financial statements. In addition, we read all the financial and non-financial information in the Annual Report to identify material inconsistencies with the audited financial statements and to identify any information that is apparently materially incorrect based on, or materially inconsistent with, the knowledge acquired by us in the course of performing the audit. If we become aware of any apparent material misstatements or inconsistencies we consider the implications for our report. Respective responsibilities of directors and auditor As explained more fully in the Statement of directors’ responsibilities set out on page 111, the directors are responsible for the preparation of the financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit and express an opinion on the financial statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards require us to comply with the Auditing Practices Board’s Ethical Standards for Auditors. This report is made solely to the company’s members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work has been undertaken so that we might state to the company’s members those matters we are required to state to them in an auditor’s report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the company’s members as a body, for our audit work, for this report, or for the opinions we have formed. Opinion on other matters prescribed by the Companies Act 2006 In our opinion: • the part of the Directors’ remuneration report to be audited has been properly prepared in accordance with the Companies Act 2006; and • based on the work undertaken in the course of the audit: • The information given in the Strategic report and the Directors’ report for the financial year for which the financial statements are prepared is consistent with the financial statements. • The Strategic report and the Director’s report have been prepared in accordance with applicable legal requirements. Matters on which we are required to report by exception ISAs (UK and Ireland) reporting We are required to report to you if, in our opinion, financial and non- financial information in the annual report is: • materially inconsistent with the information in the audited financial We have no exceptions to report. statements; or • apparently materially incorrect based on, or materially inconsistent with, our knowledge of the group acquired in the course of performing our audit; or • otherwise misleading. In particular, we are required to report whether we have identified any inconsistencies between our knowledge acquired in the course of performing the audit and the directors’ statement that they consider the annual report and accounts taken as a whole is fair, balanced and understandable and provides the information necessary for shareholders to assess the entity’s position and performance, business model and strategy; and whether the annual report appropriately addresses those matters that we communicated to the audit committee that we consider should have been disclosed. This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 118 BP Annual Report and Form 20-F 2016 Companies Act 2006 reporting In light of our knowledge and understanding of the Company and its environment obtained in the course of the audit, we have identified no material misstatements in the Strategic Report or Directors’ Report. We have no exceptions to report. We are required to report to you if, in our opinion: • adequate accounting records have not been kept by the parent company, or returns adequate for our audit have not been received from branches not visited by us; or • the parent company financial statements and the part of the Directors’ remuneration report to be audited are not in agreement with the accounting records and returns; or • certain disclosures of directors’ remuneration specified by law are not made; or • we have not received all the information and explanations we require for our audit. Listing Rules review requirements We are required to review: • the directors’ statement in relation to going concern, set out on page 112, and longer-term viability, set out on page 112; and • the part of the Corporate governance statement relating to the company’s compliance with the provisions of the UK Corporate Governance Code specified for our review. We have no exceptions to report. Statement on the directors’ assessment of the principal risks that would threaten the solvency or liquidity of the entity ISAs (UK and Ireland) reporting We have nothing material to add or to draw attention to. We are required to give a statement as to whether we have anything material to add or to draw attention to in relation to: • the directors’ confirmation in the annual report that they have carried out a robust assessment of the principal risks facing the entity, including those that would threaten its business model, future performance, solvency or liquidity; • the disclosures in the annual report that describe those risks and explain how they are being managed or mitigated; • the directors’ statement in the Directors’ report (Directors’ statements, page 112) about whether they considered it appropriate to adopt the going concern basis of accounting in preparing them, and their identification of any material uncertainties to the entity’s ability to continue to do so over a period of at least twelve months from the date of approval of the financial statements; and • the directors’ explanation in the annual report as to how they have assessed the prospects of the entity, over what period they have done so and why they consider that period to be appropriate, and their statement as to whether they have a reasonable expectation that the entity will be able to continue in operation and meet its liabilities as they fall due over the period of their assessment, including any related disclosures drawing attention to any necessary qualifications or assumptions. John C. Flaherty (Senior Statutory Auditor) for and on behalf of Ernst & Young LLP, Statutory Auditor London 6 April 2017 1. 2. The maintenance and integrity of the BP p.l.c. web site is the responsibility of BP p.l.c. the work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements since they were initially presented on the web site. Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions. This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 119 i F n a n c a i l s t a t e m e n t s Consolidated financial statements of the BP group Report of Independent Registered Public Accounting Firm The board of directors and shareholders of BP p.l.c. We have audited the accompanying group balance sheets of BP p.l.c. as of 31 December 2016 and 31 December 2015, and the related group income statement, group statement of comprehensive income, group statement of changes in equity and group cash flow statement for each of the three years in the period ended 31 December 2016. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the group financial position of BP p.l.c. at 31 December 2016 and 31 December 2015 and the group results of its operations and its cash flows for each of the three years in the period ended 31 December 2016, in accordance with International Financial Reporting Standards as adopted by the European Union and International Financial Reporting Standards as issued by the International Accounting Standards Board. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), BP p.l.c.’s internal control over financial reporting as of 31 December 2016, based on criteria established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting and our report dated 6 April 2017 expressed an unqualified opinion. /s/ Ernst & Young LLP London, United Kingdom 6 April 2017 1. 2. The maintenance and integrity of the BP p.l.c. web site is the responsibility of BP p.l.c. the work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements since they were initially presented on the web site. Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions. 120 BP Annual Report and Form 20-F 2016 Consolidated financial statements of the BP group Report of Independent Registered Public Accounting Firm The board of directors and shareholders of BP p.l.c. We have audited BP p.l.c.’s internal control over financial reporting as of 31 December 2016, based on criteria established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting. BP p.l.c.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s report on internal control over financial reporting on page 267. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, BP p.l.c. maintained, in all material respects, effective internal control over financial reporting as of 31 December 2016, based on the UK Financial Reporting Council’s Guidance. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the group balance sheets of BP p.l.c. as of 31 December 2016 and 2015, and the related group income statement, group statement of comprehensive income, group statement of changes in equity and group cash flow statement for each of the three years in the period ended 31 December 2016, and our report dated 6 April 2017 expressed an unqualified opinion thereon. /s/ Ernst & Young LLP London, United Kingdom 6 April 2017 Consent of independent registered public accounting firm We consent to the incorporation by reference of our reports dated 6 April 2017, with respect to the group financial statements of BP p.l.c., and the effectiveness of internal control over financial reporting of BP p.l.c., included in this Annual Report and Form 20-F for the year ended 31 December 2016 in the following Registration Statements: Registration Statement on Form F-3 (File Nos. 333-208478 and 333-208478-01) of BP Capital Markets p.l.c. and BP p.l.c.; and Registration Statements on Form S-8 (File Nos. 333-67206, 333-79399, 333-103924, 333-123482, 333-123483, 333-131583, 333-131584, 333-132619, 333-146868, 333-146870, 333-146873, 333-173136, 333-177423, 333-179406, 333-186462, 333-186463, 333-199015, 333-200794, 333- 200795, 333-207188, 333-207189, 333-210316 and 333-210318) of BP p.l.c. /s/ Ernst & Young LLP London, United Kingdom 6 April 2017 1. 2. The maintenance and integrity of the BP p.l.c. web site is the responsibility of BP p.l.c. the work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements since they were initially presented on the web site. Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions. BP Annual Report and Form 20-F 2016 121 i F n a n c a i l s t a t e m e n t s Group income statement For the year ended 31 December Sales and other operating revenues Earnings from joint ventures – after interest and tax Earnings from associates – after interest and tax Interest and other income Gains on sale of businesses and fixed assets Total revenues and other income Purchases Production and manufacturing expensesa Production and similar taxes Depreciation, depletion and amortization Impairment and losses on sale of businesses and fixed assets Exploration expense Distribution and administration expenses Profit (loss) before interest and taxation Finance costsa Net finance expense relating to pensions and other post-retirement benefits Profit (loss) before taxation Taxationa Profit (loss) for the year Attributable to BP shareholders Non-controlling interests Earnings per share – cents Profit (loss) for the year attributable to BP shareholders Basic Diluted Per ADS (dollars) Basic Diluted a See Note 2 for information on the impact of the Gulf of Mexico oil spill on these income statement line items. Note 2016 2015 5 15 16 6 4 18 5 5 4 7 6 23 8 10 10 10 10 183,008 966 994 506 1,132 186,606 132,219 29,077 683 14,505 (1,664) 1,721 10,495 (430) 1,675 190 (2,295) (2,467) 172 115 57 172 0.61 0.60 0.04 0.04 222,894 (28) 1,839 611 666 225,982 164,790 37,040 1,036 15,219 1,909 2,353 11,553 (7,918) 1,347 306 (9,571) (3,171) (6,400) (6,482) 82 (6,400) (35.39) (35.39) (2.12) (2.12) $ million 2014 353,568 570 2,802 843 895 358,678 281,907 27,375 2,958 15,163 8,965 3,632 12,266 6,412 1,148 314 4,950 947 4,003 3,780 223 4,003 20.55 20.42 1.23 1.23 122 BP Annual Report and Form 20-F 2016 Group statement of comprehensive incomea For the year ended 31 December Profit (loss) for the year Other comprehensive income Items that may be reclassified subsequently to profit or loss Note 2016 172 2015 (6,400) $ million 2014 4,003 Currency translation differences Exchange gains (losses) on translation of foreign operations reclassified to gain or loss on 254 (4,119) (6,838) sale of businesses and fixed assets Available-for-sale investments Cash flow hedges marked to market Cash flow hedges reclassified to the income statement Cash flow hedges reclassified to the balance sheet Share of items relating to equity-accounted entities, net of tax Income tax relating to items that may be reclassified Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Share of items relating to equity-accounted entities, net of tax Income tax relating to items that will not be reclassified Other comprehensive income Total comprehensive income Attributable to BP shareholders Non-controlling interests a See Note 31 for further information. Group statement of changes in equitya 29 29 29 8 23 8 30 1 (639) 196 81 833 13 769 (2,496) – 739 (1,757) (988) (816) (846) 30 (816) 23 1 (178) 249 22 (814) 257 (4,559) 4,139 (1) (1,397) 2,741 51 – (155) (73) (11) (2,584) 147 (9,463) (4,590) 4 1,334 (3,252) (1,818) (12,715) (8,218) (8,712) (8,259) 41 (8,218) (8,903) 191 (8,712) At 1 January 2016 Profit (loss) for the year Other comprehensive income Total comprehensive income Dividendsb Share-based payments, net of tax Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests At 31 December 2016 At 1 January 2015 Profit (loss) for the year Other comprehensive income Total comprehensive income Dividendsb Share-based payments, net of tax Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests At 31 December 2015 At 1 January 2014 Profit (loss) for the year Other comprehensive income Total comprehensive income Dividendsb Repurchases of ordinary share capital Share-based payments, net of tax Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests At 31 December 2014 a See Note 31 for further information. b See Note 9 for further information. Share capital and capital Treasury reserves shares 43,902 (19,964) – – – – 1,521 – – – – 2,220 Foreign currency translation reserve (7,267) – 389 389 – – Fair value reserves Profit and loss account (823) 81,368 115 (1,020) (905) (4,611) (750) – (330) (330) – – – – – – 46,122 (18,443) 43,902 (20,719) – – – – 755 – – – – – – – – – 43,902 (19,964) 43,656 (20,971) – – – – – 252 – – – – – 246 – – – – 43,902 (20,719) – – 106 430 (6,878) (1,153) 75,638 – – (3,409) – (3,858) (3,858) – – – – (7,267) 3,525 – (6,934) (6,934) – – – – – (3,409) (897) 92,564 (6,482) 2,007 (4,475) (6,659) (99) – 74 74 – – – – 40 (3) (823) 81,368 (695) 103,787 3,780 (5,547) (1,767) (5,850) (3,366) (313) – (202) (202) – – – – – 73 – (897) 92,564 BP shareholders’ equity 97,216 115 (961) (846) (4,611) 2,991 Non- controlling interests 1,171 57 (27) 30 (107) – 106 430 95,286 111,441 (6,482) (1,777) (8,259) (6,659) 656 40 (3) 97,216 129,302 3,780 (12,683) (8,903) (5,850) (3,366) 185 73 – 111,441 – 463 1,557 1,201 82 (41) 41 (91) – – 20 1,171 1,105 223 (32) 191 (255) – – – 160 1,201 $ million Total equity 98,387 172 (988) (816) (4,718) 2,991 106 893 96,843 112,642 (6,400) (1,818) (8,218) (6,750) 656 40 17 98,387 130,407 4,003 (12,715) (8,712) (6,105) (3,366) 185 73 160 112,642 BP Annual Report and Form 20-F 2016 123 i F n a n c a i l s t a t e m e n t s Group balance sheet At 31 December Non-current assets Property, plant and equipment Goodwill Intangible assets Investments in joint ventures Investments in associates Other investments Fixed assets Loans Trade and other receivables Derivative financial instruments Prepayments Deferred tax assets Defined benefit pension plan surpluses Current assets Loans Inventories Trade and other receivables Derivative financial instruments Prepayments Current tax receivable Other investments Cash and cash equivalents Assets classified as held for sale Total assets Current liabilities Trade and other payables Derivative financial instruments Accruals Finance debt Current tax payable Provisions Liabilities directly associated with assets classified as held for sale Non-current liabilities Other payables Derivative financial instruments Accruals Finance debt Deferred tax liabilities Provisions Defined benefit pension plan and other post-retirement benefit plan deficits Total liabilities Net assets Equity BP shareholders’ equity Non-controlling interests Total equity C-H Svanberg Chairman R W Dudley Group Chief Executive 6 April 2017 124 BP Annual Report and Form 20-F 2016 Note 2016 $ million 2015 129,758 11,627 18,660 8,412 9,422 1,002 178,881 529 2,216 4,409 1,003 1,545 2,647 129,757 11,194 18,183 8,609 14,092 1,033 182,868 532 1,474 4,359 945 4,741 584 195,503 191,230 259 17,655 20,675 3,016 1,486 1,194 44 23,484 67,813 – 272 14,142 22,323 4,242 1,838 599 219 26,389 70,024 578 67,813 70,602 263,316 261,832 37,915 2,991 5,136 6,634 1,666 4,012 58,354 – 31,949 3,239 6,261 6,944 1,080 5,154 54,627 97 58,354 54,724 13,946 5,513 469 51,666 7,238 20,412 8,875 2,910 4,283 890 46,224 9,599 35,960 8,855 108,119 108,721 166,473 163,445 96,843 98,387 95,286 1,557 96,843 97,216 1,171 98,387 11 13 14 15 16 17 19 29 8 23 18 19 29 17 24 3 21 29 25 22 3 21 29 25 8 22 23 31 31 31 Group cash flow statement For the year ended 31 December Operating activities Profit (loss) before taxation Adjustments to reconcile profit (loss) before taxation to net cash provided by operating activities Exploration expenditure written off Depreciation, depletion and amortization Impairment and (gain) loss on sale of businesses and fixed assets Earnings from joint ventures and associates Dividends received from joint ventures and associates Interest receivable Interest received Finance costs Interest paid Net finance expense relating to pensions and other post-retirement benefits Share-based payments Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans Net charge for provisions, less payments (Increase) decrease in inventories (Increase) decrease in other current and non-current assets Increase (decrease) in other current and non-current liabilities Income taxes paid Net cash provided by operating activities Investing activities Capital expenditure Acquisitions, net of cash acquired Investment in joint ventures Investment in associates Proceeds from disposals of fixed assets Proceeds from disposals of businesses, net of cash disposed Proceeds from loan repayments Net cash used in investing activities Financing activities Net issue (repurchase) of shares Proceeds from long-term financing Repayments of long-term financing Net increase (decrease) in short-term debt Net increase (decrease) in non-controlling interests Dividends paid BP shareholders Non-controlling interests Net cash provided by (used in) financing activities Currency translation differences relating to cash and cash equivalents Increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of year Cash and cash equivalents at end of year Note 2016 2015 $ million 2014 (2,295) (9,571) 4,950 7 5 4 6 23 23 4 4 9 1,274 14,505 (2,796) (1,960) 1,105 (200) 267 1,675 (1,137) 190 779 (467) 4,487 (3,681) (1,172) 1,655 (1,538) 10,691 1,829 15,219 1,243 (1,811) 1,614 (247) 176 1,347 (1,080) 306 321 (592) 11,792 3,375 6,796 (9,328) (2,256) 19,133 (16,701) (1) (50) (700) 1,372 1,259 68 (18,648) 23 (265) (1,312) 1,066 1,726 110 3,029 15,163 8,070 (3,372) 1,911 (276) 81 1,148 (937) 314 379 (963) 1,119 10,169 3,566 (6,810) (4,787) 32,754 (22,546) (131) (179) (336) 1,820 1,671 127 (14,753) (17,300) (19,574) – 12,442 (6,685) 51 887 (4,611) (107) 1,977 (820) (2,905) 26,389 23,484 – 8,173 (6,426) 473 (5) (6,659) (91) (4,535) (672) (3,374) 29,763 26,389 (4,589) 12,394 (6,282) (693) 9 (5,850) (255) (5,266) (671) 7,243 22,520 29,763 BP Annual Report and Form 20-F 2016 125 i F n a n c a i l s t a t e m e n t s Notes on financial statements 1. Significant accounting policies, judgements, estimates and assumptions Authorization of financial statements and statement of compliance with International Financial Reporting Standards The consolidated financial statements of the BP group for the year ended 31 December 2016 were approved and signed by the group chief executive and chairman on 6 April 2017 having been duly authorized to do so by the board of directors. BP p.l.c. is a public limited company incorporated and domiciled in England and Wales. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB. The differences have no impact on the group’s consolidated financial statements for the years presented. The significant accounting policies and accounting judgements, estimates and assumptions of the group are set out below. Basis of preparation The consolidated financial statements have been prepared on a going concern basis and in accordance with IFRS and IFRS Interpretations Committee (IFRIC) interpretations issued and effective for the year ended 31 December 2016. The accounting policies that follow have been consistently applied to all years presented. The consolidated financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where otherwise indicated. Significant accounting policies: use of judgements, estimates and assumptions Inherent in the application of many of the accounting policies used in preparing the financial statements is the need for BP management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and assumptions used. The accounting judgements and estimates that could have a significant impact on the results of the group are set out in boxed text below, and should be read in conjunction with the information provided in the Notes on financial statements. The areas requiring the most significant judgement and estimation in the preparation of the consolidated financial statements are: accounting for interests in other entities; oil and natural gas accounting, including the estimation of reserves; the recoverability of asset carrying values, including trade receivables; derivative financial instruments, including the application of hedge accounting; provisions and contingencies, including provisions and contingencies related to the Gulf of Mexico oil spill; pensions and other post-retirement benefits; and income taxes. Basis of consolidation The group financial statements consolidate the financial statements of BP p.l.c. and its subsidiaries drawn up to 31 December each year. Subsidiaries are consolidated from the date of their acquisition, being the date on which the group obtains control, and continue to be consolidated until the date that control ceases. The financial statements of subsidiaries are prepared for the same reporting year as the parent company, using consistent accounting policies. Intra-group balances and transactions, including unrealized profits arising from intra-group transactions, have been eliminated. Unrealized losses are eliminated unless the transaction provides evidence of an impairment of the asset transferred. Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to BP shareholders. Interests in other entities Business combinations and goodwill Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities assumed are recognized at their fair values at the acquisition date. Goodwill is initially measured as the excess of the aggregate of the consideration transferred, the amount recognized for any non-controlling interest and the acquisition-date fair values of any previously held interest in the acquiree over the fair value of the identifiable assets acquired and liabilities assumed at the acquisition date. At the acquisition date, any goodwill acquired is allocated to each of the cash-generating units, or groups of cash-generating units, expected to benefit from the combination’s synergies. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill arising on business combinations prior to 1 January 2003 is stated at the previous carrying amount under UK generally accepted accounting practice, less subsequent impairments. See Note 13 for further information. Goodwill may also arise upon investments in joint ventures and associates, being the surplus of the cost of investment over the group’s share of the net fair value of the identifiable assets and liabilities. Any such goodwill is recorded within the corresponding investment in joint ventures and associates. Interests in joint arrangements The results, assets and liabilities of joint ventures are incorporated in these financial statements using the equity method of accounting as described below. Certain of the group’s activities, particularly in the Upstream segment, are conducted through joint operations. BP recognizes, on a line-by-line basis in the consolidated financial statements, its share of the assets, liabilities and expenses of these joint operations incurred jointly with the other partners, along with the group’s income from the sale of its share of the output and any liabilities and expenses that the group has incurred in relation to the joint operation. Interests in associates The results, assets and liabilities of associates are incorporated in these financial statements using the equity method of accounting as described below. Significant judgement: accounting for interests in other entities Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity; depending upon the facts and circumstances in each case, BP may obtain control, joint control or significant influence over the entity or arrangement. Transactions which give BP control of a business are business combinations. If BP obtains joint control of an arrangement, judgement is also required to assess whether the arrangement is a joint operation or a joint venture. If BP has neither control nor joint control, it may be in a position to exercise significant influence over the entity, which is then classified as an associate. Since 21 March 2013, BP has owned 19.75% of the voting shares of Rosneft Oil Company (Rosneft), a Russian oil and gas company. The Russian federal government, through its investment company JSC Rosneftegaz, owned 50% plus one share of the voting shares of Rosneft at 31 December 2016. BP uses the equity method of accounting for its investment in Rosneft because under IFRS it is considered to have significant influence. Significant influence is defined as the power to participate in the financial and operating policy decisions of the investee 126 BP Annual Report and Form 20-F 2016 1. Significant accounting policies, judgements, estimates and assumptions – continued but is not control or joint control. IFRS identifies several indicators that may provide evidence of significant influence, including representation on the board of directors of the investee and participation in policy-making processes. BP’s group chief executive, Bob Dudley, has been a member of the board of directors of Rosneft since 2013 and he is a member of the Rosneft board’s Strategic Planning Committee. A second BP-nominated director, Guillermo Quintero, has been a member of the Rosneft board and its HR and Remuneration Committee since 2015. BP also holds the voting rights at general meetings of shareholders conferred by its 19.75% stake in Rosneft. In management’s judgement, the group has significant influence over Rosneft, as defined by the relevant accounting standard, and the investment is, therefore, classified as an associate and accounted for using the equity method. BP’s share of Rosneft’s oil and natural gas reserves is included in the estimated net proved reserves of equity-accounted entities. The equity method of accounting Under the equity method, the investment is carried on the balance sheet at cost plus post-acquisition changes in the group’s share of net assets of the entity, less distributions received and less any impairment in value of the investment. Loans advanced to equity-accounted entities that have the characteristics of equity financing are also included in the investment on the group balance sheet. The group income statement reflects the group’s share of the results after tax of the equity-accounted entity, adjusted to account for depreciation, amortization and any impairment of the equity-accounted entity’s assets based on their fair values at the date of acquisition. The group statement of comprehensive income includes the group’s share of the equity-accounted entity’s other comprehensive income. The group’s share of amounts recognized directly in equity by an equity-accounted entity is recognized directly in the group’s statement of changes in equity. Financial statements of equity-accounted entities are prepared for the same reporting year as the group. Where material differences arise, adjustments are made to those financial statements to bring the accounting policies used into line with those of the group. Unrealized gains on transactions between the group and its equity-accounted entities are eliminated to the extent of the group’s interest in the equity-accounted entity. The group assesses investments in equity-accounted entities for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. If any such indication of impairment exists, the carrying amount of the investment is compared with its recoverable amount, being the higher of its fair value less costs of disposal and value in use. If the carrying amount exceeds the recoverable amount, the investment is written down to its recoverable amount. Segmental reporting The group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the group chief executive, BP’s chief operating decision maker, in deciding how to allocate resources and in assessing performance. The accounting policies of the operating segments are the same as the group’s accounting policies described in this note, except that IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker. For BP, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit. Replacement cost profit for the group is not a recognized measure under IFRS. For further information see Note 5. Foreign currency translation In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency of those entities at the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included in the income statement, unless hedge accounting is applied. Non-monetary assets and liabilities, other than those measured at fair value, are not retranslated subsequent to initial recognition. In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, joint ventures, associates, and related goodwill, are translated into US dollars at the spot exchange rate on the balance sheet date. The results and cash flows of non-US dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars using average rates of exchange. In the consolidated financial statements, exchange adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars are recognized in a separate component of equity and reported in other comprehensive income. Exchange gains and losses arising on long-term intra-group foreign currency borrowings used to finance the group’s non-US dollar investments are also reported in other comprehensive income. On disposal or partial disposal of a non-US dollar functional currency subsidiary, joint venture or associate, the related accumulated exchange gains and losses recognized in equity are reclassified from equity to the income statement. Non-current assets held for sale Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell. Non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale, and actions required to complete the plan of sale should indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. Property, plant and equipment and intangible assets are not depreciated or amortized once classified as held for sale. Intangible assets Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, computer software, patents, licences and trademarks and are stated at the amount initially recognized, less accumulated amortization and accumulated impairment losses. Intangible assets acquired separately from a business are carried initially at cost. An intangible asset acquired as part of a business combination is measured at fair value at the date of acquisition and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights. BP Annual Report and Form 20-F 2016 127 i F n a n c a i l s t a t e m e n t s 1. Significant accounting policies, judgements, estimates and assumptions – continued Intangible assets with a finite life, other than capitalized exploration and appraisal costs as described below, are amortized on a straight-line basis over their expected useful lives. For patents, licences and trademarks, expected useful life is the shorter of the duration of the legal agreement and economic useful life, and can range from three to 15 years. Computer software costs generally have a useful life of three to five years. The expected useful lives of assets are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively. Oil and natural gas exploration, appraisal and development expenditure Oil and natural gas exploration, appraisal and development expenditure is accounted for using the principles of the successful efforts method of accounting as described below. Licence and property acquisition costs Exploration licence and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still under way or planned or that it has been determined, or work is under way to determine, that the discovery is economically viable based on a range of technical and commercial considerations, and sufficient progress is being made on establishing development plans and timing. If no future activity is planned, the remaining balance of the licence and property acquisition costs is written off. Lower value licences are pooled and amortized on a straight-line basis over the estimated period of exploration. Upon recognition of proved reserves and internal approval for development, the relevant expenditure is transferred to property, plant and equipment. Exploration and appraisal expenditure Geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are initially capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, rig costs and payments made to contractors. If potentially commercial quantities of hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an asset. If it is determined that development will not occur then the costs are expensed. Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalized as an intangible asset. When proved reserves of oil and natural gas are determined and development is approved by management, the relevant expenditure is transferred to property, plant and equipment. Development expenditure Expenditure on the construction, installation and completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including service and unsuccessful development or delineation wells, is capitalized within property, plant and equipment and is depreciated from the commencement of production as described below in the accounting policy for property, plant and equipment. Significant judgement: oil and natural gas accounting The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within one year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover potentially economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. an offshore platform or a pipeline) would be required before production could begin, and where the economic viability of that major capital expenditure depends on the successful completion of further exploration work in the area, remain capitalized on the balance sheet as long as additional exploration or appraisal work is under way or firmly planned. It is not unusual to have exploration wells and exploratory-type stratigraphic test wells remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and natural gas field is performed or while the optimum development plans and timing are established. All such carried costs are subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value from, the discovery. Where this is no longer the case, the costs are immediately expensed. One of the facts and circumstances which indicate that an entity should test such assets for impairment is that the period for which the entity has a right to explore in the specific area has expired or will expire in the near future, and is not expected to be renewed. BP has leases in the Gulf of Mexico making up a prospect, some with terms which were scheduled to expire at the end of 2013 and some with terms which were scheduled to expire at the end of 2014. A significant proportion of our capitalized exploration and appraisal costs in the Gulf of Mexico relate to this prospect. This prospect requires the development of subsea technology to ensure that the hydrocarbons can be extracted safely. BP is in negotiation with the US Bureau of Safety and Environmental Enforcement in relation to seeking extension of these leases so that the discovered hydrocarbons can be developed. BP remains committed to developing this prospect and expects that the leases will be renewed and, therefore, continues to carry the capitalized costs on its balance sheet. Property, plant and equipment Property, plant and equipment is stated at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into the location and condition necessary for it to be capable of operating in the manner intended by management, the initial estimate of any decommissioning obligation, if any, and, for assets that necessarily take a substantial period of time to get ready for their intended use, finance costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. The capitalized value of a finance lease is also included within property, plant and equipment. Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated with the item will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Inspection costs associated with major maintenance programmes are capitalized and amortized over the period to the next inspection. Overhaul costs for major maintenance programmes, and all other maintenance costs are expensed as incurred. Oil and natural gas properties, including related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is amortized over proved developed reserves. Licence acquisition, common facilities and future decommissioning costs are amortized over total proved reserves. The unit-of-production rate for the depreciation of common facilities takes into account expenditures incurred to date, together 128 BP Annual Report and Form 20-F 2016 1. Significant accounting policies, judgements, estimates and assumptions – continued with estimated future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed through these common facilities. Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life. The typical useful lives of the group’s other property, plant and equipment are as follows: Land improvements Buildings Refineries Petrochemicals plants Pipelines Service stations Office equipment Fixtures and fittings 15 to 25 years 20 to 50 years 20 to 30 years 20 to 30 years 10 to 50 years 15 years 3 to 7 years 5 to 15 years The expected useful lives of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively. An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in the period in which the item is derecognized. Significant judgements and estimates: estimation of oil and natural gas reserves Significant technical and commercial judgements are required to determine the group’s estimated oil and natural gas reserves. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and divestment activity, drilling of new wells, and commodity prices all impact on the determination of the group’s estimates of its oil and natural gas reserves. BP bases its proved reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements. The estimation of oil and natural gas reserves and BP’s process to manage reserves bookings is described in Supplementary information on oil and natural gas on page 187, which is unaudited. Details on BP’s proved reserves and production compliance and governance processes are provided on page 252. Estimates of oil and natural gas reserves determined by applying US Securities and Exchange Commission regulations are used to calculate depreciation, depletion and amortization charges for the group’s oil and gas properties. The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining carrying value of the asset over the expected future production. Oil and natural gas reserves estimates also have a direct impact on the assessment of the recoverability of asset carrying values reported in the financial statements. If proved reserves estimates determined by applying management’s assumptions are revised downwards, earnings could be affected by changes in depreciation expense or an immediate write-down of the property’s carrying value. The 2016 movements in proved reserves are reflected in the tables showing movements in oil and natural gas reserves by region in Supplementary information on oil and natural gas (unaudited) on page 187. Information on the carrying amounts of the group’s oil and natural gas properties, together with the amounts recognized in the income statement as depreciation, depletion and amortization is contained in Note 11 and Note 5 respectively. Impairment of property, plant and equipment, intangible assets, and goodwill The group assesses assets or groups of assets, called cash-generating units (CGUs), for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or CGU may not be recoverable; for example, changes in the group’s business plans, changes in the group’s assumptions about commodity prices, low plant utilization, evidence of physical damage or, for oil and gas assets, significant downward revisions of estimated reserves or increases in estimated future development expenditure or decommissioning costs. If any such indication of impairment exists, the group makes an estimate of the asset’s or CGU’s recoverable amount. Individual assets are grouped into CGUs for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. A CGU’s recoverable amount is the higher of its fair value less costs of disposal and its value in use. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the determination of value in use. They contain forecasts for oil and natural gas production, refinery throughputs, sales volumes for various types of refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. As an initial step in the preparation of these plans, various assumptions regarding market conditions, such as oil prices, natural gas prices, refining margins, refined product margins and cost inflation rates are set by senior management. These assumptions take account of existing prices, global supply-demand equilibrium for oil and natural gas, other macroeconomic factors and historical trends and variability. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset group and are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money. Fair value less costs of disposal is the price that would be received to sell the asset in an orderly transaction between market participants and does not reflect the effects of factors that may be specific to the group and not applicable to entities in general. An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to the lower of its recoverable amount and the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Impairment reversals are recognized in profit or loss. After a reversal, the depreciation charge is adjusted in future periods to allocate the asset’s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life. Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the group of CGUs to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of the group of CGUs to which goodwill has been allocated is compared with its recoverable amount. Where the recoverable amount of the group of BP Annual Report and Form 20-F 2016 129 i F n a n c a i l s t a t e m e n t s 1. Significant accounting policies, judgements, estimates and assumptions – continued CGUs is less than the carrying amount (including goodwill), an impairment loss is recognized. An impairment loss recognized for goodwill is not reversed in a subsequent period. Significant judgements and estimates: recoverability of asset carrying values Determination as to whether, and by how much, an asset, CGU, or group of CGUs containing goodwill is impaired involves management estimates on highly uncertain matters such as the effects of inflation and deflation on operating expenses, discount rates, production profiles, reserves and resources, and future commodity prices, including the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas and refined products. Judgement is required when determining the appropriate grouping of assets into a CGU or the appropriate grouping of CGUs for impairment testing purposes. See Note 13 for details on how these groupings have been determined in relation to the impairment testing of goodwill. As disclosed above, the recoverable amount of an asset is the higher of its value in use and its fair value less costs of disposal. Fair value less costs of disposal may be determined based on similar recent market transaction data or, where recent market transactions for the asset are not available for reference, using discounted cash flow techniques. Where discounted cash flow analyses are used to calculate fair value less costs of disposal, accounting judgements are made about the assumptions market participants would use when pricing the asset, CGU or group of CGUs containing goodwill and the test is performed on a post-tax basis. Irrespective of whether there is any indication of impairment, BP is required to test annually for impairment of goodwill acquired in business combinations. The group carries goodwill of approximately $11.2 billion on its balance sheet (2015 $11.6 billion), principally relating to the Atlantic Richfield, Burmah Castrol, Devon Energy and Reliance transactions. In testing goodwill for impairment, the group uses the approach described above to determine recoverable amount. If there are low oil or natural gas prices for an extended period, the group may need to recognize goodwill impairment charges. Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts of assets are shown in Note 11, Note 13 and Note 14. Specific judgements and estimates made in impairment tests in 2016 relating to discount rates, oil and gas properties and oil and gas prices are discussed below. Discount rates For value-in-use calculations, future cash flows are adjusted for risks specific to the cash-generating unit and are discounted using a pre-tax discount rate. The pre-tax discount rate is based upon the cost of funding the group derived from an established model, adjusted to a pre-tax basis. Fair value less costs of disposal calculations use the post-tax discount rate. The discount rates applied in impairment tests are reassessed each year. In 2016 the discount rate used to determine recoverable amounts based on fair value less costs of disposal was revised to 6% (2015 7%). The discount rate used to determine recoverable amounts based on value in use was revised to 9% (2015 11%). In both cases, where the cash-generating unit is located in a country which is judged to be higher risk an additional 2% premium was added to the discount rate (2015 2%). Oil and natural gas properties For oil and natural gas properties, expected future cash flows are estimated using management’s best estimate of future oil and natural gas prices and production and reserves volumes. The estimated future level of production in all impairment tests is based on assumptions about future commodity prices, production and development costs, field decline rates, current fiscal regimes and other factors. Reserves assumptions for value-in-use tests are restricted to proved and probable reserves. When estimating the fair value of our Upstream assets, assumptions reflect all reserves and resources that a market participant would consider when valuing the asset, which in some cases are broader in scope than the reserves used in a value-in-use test. In determining a fair value, risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved. Depending upon the classification of the reserves and resources, this can result in associated forecast cash flows being reduced by a factor of between 10% and 90% from their estimated full potential value. Changing the risk factor applied will in some cases have an impact upon the carrying value of the asset concerned. A 10% increase in the risk factors used in any single test could have an impact of up to $0.4 billion upon the carrying value of that asset. The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and development expenditure above. Oil and gas prices During the third quarter of 2016, the price assumptions used in impairment tests were revised. The long-term price assumptions used to determine recoverable amount based on fair value less costs of disposal from 2022 onwards are derived from $75 per barrel for Brent and $4/mmBtu for Henry Hub (both in 2015 prices) inflated for the remaining life of the asset. For 2015 the equivalent values were $80 per barrel for Brent and $5/mmBtu for Henry Hub. To determine recoverable amount based on value in use, the price assumptions were inflated to 2022 but from 2022 onwards were not inflated. For both value-in-use and fair value less costs of disposal impairment tests, the price assumptions used for the five-year period to 2021 have been set such that there is a gradual transition from current market prices to the long-term price assumptions as noted above. For 2015, market prices were used for the first five years ranging from $40 per barrel for Brent and $2.38/mmBtu for Henry Hub in 2016 to $56 per barrel for Brent and $3.18/mmBtu in 2020. Prices used this year were revised due to a lack of liquidity in the market beyond the very near term. Current market prices for oil reflect the elevated level of oil stocks following strong growth in US shale and OPEC production volumes in recent years. US production fell during 2016 in response to lower prices and, towards the end of the year, OPEC and a number of non-OPEC countries announced an agreement to reduce production volumes. BP’s long-term assumption for oil is higher than current market prices because prices are expected to increase as the current record level of oil inventories is gradually unwound, underpinned by solid demand growth and muted increases in supply. US gas prices have fallen back recently in response to the unusually mild winter. BP’s long-term price assumption for US gas is higher than current market prices because we expect demand for US gas to grow with increased exports of liquefied natural gas (LNG), underpinned by strong growth in the global demand for gas. We expect natural gas to be the fastest growing fossil fuel over the next 20 years, supported by increasing environmental regulation encouraging a switch from coal to cleaner, lower carbon fuels including gas, as well as renewables. 130 BP Annual Report and Form 20-F 2016 1. Significant accounting policies, judgements, estimates and assumptions – continued Inventories Inventories, other than inventories held for short-term trading purposes, are stated at the lower of cost and net realizable value. Cost is determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses. Net realizable value is determined by reference to prices existing at the balance sheet date, adjusted where the sale of inventories after the reporting period gives evidence about their net realizable value at the end of the period. Inventories held for short-term trading purposes are stated at fair value less costs to sell and any changes in fair value are recognized in the income statement. Supplies are valued at the lower of cost on a weighted average basis and net realizable value. Leases Agreements under which payments are made to owners in return for the right to use an asset are accounted for as leases. Leases that transfer substantially all the risks and rewards of ownership are recognized as finance leases. All other leases are accounted for as operating leases. Finance leases are capitalized at the commencement of the lease term at the fair value of the leased item or, if lower, at the present value of the minimum lease payments. Finance charges are allocated to each period so as to achieve a constant rate of interest on the remaining balance of the liability and are charged directly against income. Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term. Operating lease payments are recognized as an expense on a straight-line basis over the lease term. Financial assets Financial assets are recognized initially at fair value, normally being the transaction price plus, in the case of financial assets not at fair value through profit or loss, directly attributable transaction costs. The subsequent measurement of financial assets depends on their classification, as follows: Loans and receivables Loans and receivables are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in income when the loans and receivables are derecognized or impaired, as well as through the amortization process. This category of financial assets includes trade and other receivables. Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Financial assets at fair value through profit or loss Financial assets at fair value through profit or loss are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are classified as held for trading and are included in this category. Derivatives designated as hedging instruments in an effective hedge These derivatives are carried on the balance sheet at fair value. The treatment of gains and losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities. Held-to-maturity financial assets Held-to-maturity financial assets are measured at amortized cost, using the effective interest method, less any impairment. Available-for-sale financial assets Available-for-sale financial assets are measured at fair value, with gains or losses recognized within other comprehensive income, except for impairment losses, and, for available-for-sale debt instruments, foreign exchange gains or losses, interest recognized using the effective interest method, and any changes in fair value arising from revised estimates of future cash flows, which are recognized in profit or loss. Impairment of loans and receivables The group assesses at each balance sheet date whether a financial asset or group of financial assets is impaired. If there is objective evidence that an impairment loss on loans and receivables carried at amortized cost has been incurred, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is reduced, with the amount of the loss recognized in the income statement. Significant judgement: recoverability of trade receivables Judgements are required in assessing the recoverability of overdue trade receivables and determining whether a provision against those receivables is required. Factors considered include the credit rating of the counterparty, the amount and timing of anticipated future payments and any possible actions that can be taken to mitigate the risk of non-payment. See Note 28 for information on overdue receivables. Financial liabilities The measurement of financial liabilities depends on their classification, as follows: Financial liabilities at fair value through profit or loss Financial liabilities at fair value through profit or loss are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are classified as held for trading and are included in this category. Derivatives designated as hedging instruments in an effective hedge These derivatives are carried on the balance sheet at fair value. The treatment of gains and losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities. Financial liabilities measured at amortized cost All other financial liabilities are initially recognized at fair value, net of transaction costs. For interest-bearing loans and borrowings this is the fair value of the proceeds received net of issue costs associated with the borrowing. After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively. This category of financial liabilities includes trade and other payables and finance debt, except finance debt designated in a fair value hedge relationship. BP Annual Report and Form 20-F 2016 131 i F n a n c a i l s t a t e m e n t s 1. Significant accounting policies, judgements, estimates and assumptions – continued Derivative financial instruments and hedging activities The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and commodity prices, as well as for trading purposes. These derivative financial instruments are recognized initially at fair value on the date on which a derivative contract is entered into and subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative. Contracts to buy or sell a non-financial item (for example, oil, oil products, gas or power) that can be settled net in cash, with the exception of contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the group’s expected purchase, sale or usage requirements, are accounted for as financial instruments. Gains or losses arising from changes in the fair value of derivatives that are not designated as effective hedging instruments are recognized in the income statement. Contracts to buy or sell LNG are not accounted for as derivatives as they are not considered capable of being settled net in cash. If, at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation methodology is not recognized in the income statement but is deferred on the balance sheet and is commonly known as ‘day-one gain or loss’. This deferred gain or loss is recognized in the income statement over the life of the contract until substantially all the remaining contract term can be valued using observable market data at which point any remaining deferred gain or loss is recognized in the income statement. Changes in valuation subsequent to the initial valuation are recognized immediately in the income statement. For the purpose of hedge accounting, hedges are classified as: • fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability • cash flow hedges when hedging exposure to variability in cash flows that is attributable to either a particular risk associated with a recognized asset or liability or a highly probable forecast transaction. Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for undertaking the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, and how the entity will assess the hedging instrument effectiveness in offsetting the exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged risk. Such hedges are expected at inception to be highly effective in achieving offsetting changes in fair value or cash flows. Hedges meeting the criteria for hedge accounting are accounted for as follows: Fair value hedges The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the risk being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss. The group applies fair value hedge accounting when hedging interest rate risk and certain currency risks on fixed rate borrowings. If the criteria for hedge accounting are no longer met, or if the group revokes the designation, the accumulated adjustment to the carrying amount of a hedged item at such time is then amortized to profit or loss over the remaining period to maturity. Cash flow hedges The effective portion of the gain or loss on a cash flow hedging instrument is reported in other comprehensive income, while the ineffective portion is recognized in profit or loss. Amounts reported in other comprehensive income are reclassified to the income statement when the hedged transaction affects profit or loss. Where the hedged item is a non-financial asset or liability, such as a forecast foreign currency transaction for the purchase of property, plant and equipment, the amounts recognized within other comprehensive income are reclassified to the initial carrying amount of the non-financial asset or liability. Where the hedged item is an equity investment, the amounts recognized in other comprehensive income remain in the separate component of equity until the hedged cash flows affect profit or loss. Where the hedged item is recognized directly in profit or loss, the amounts recognized in other comprehensive income are reclassified to production and manufacturing expenses, except for cash flow hedges of variable interest rate risk which are reclassified to finance costs. If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or if its designation as a hedge is revoked, amounts previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to the income statement or to the initial carrying amount of a non-financial asset or liability as above. Significant judgement: application of hedge accounting The decision as to whether to apply hedge accounting within subsidiaries, and by equity-accounted entities, can have a significant impact on the group’s financial statements. Cash flow and fair value hedge accounting is applied to certain finance debt-related instruments in the normal course of business and cash flow hedge accounting is applied to certain highly probable foreign currency transactions as part of the management of currency risk. See Note 28 and Note 29 for further information. Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The group categorizes assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed in their measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs that are observable, either directly or indirectly, other than quoted prices included within level 1 for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or BP’s assumptions about pricing by market participants. Significant estimate: valuation of derivatives In some cases the fair values of derivatives are estimated using internal models due to the absence of quoted prices or other observable, market-corroborated data. This applies to the group’s longer-term derivative contracts. The majority of these contracts are valued using models with inputs that include price curves for each of the different products that are built up from available active market pricing data and modelled using the maximum available external pricing information. Additionally, where limited data exists for certain products, prices are determined using historic and long-term pricing relationships. Price volatility is also an input for options models. Changes in the key assumptions could have a material impact on the fair value gains and losses on derivatives recognized in the income statement. For more information see Note 29. 132 BP Annual Report and Form 20-F 2016 1. Significant accounting policies, judgements, estimates and assumptions – continued Offsetting of financial assets and liabilities Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met: the group currently has a legally enforceable right to set off the recognized amounts; and the group intends to either settle on a net basis or realize the asset and settle the liability simultaneously. A right of set off is the group’s legal right to settle an amount payable to a creditor by applying against it an amount receivable from the same counterparty. The relevant legal jurisdiction and laws applicable to the relationships between the parties are considered when assessing whether a current legally enforceable right to set off exists. Provisions and contingencies Provisions are recognized when the group has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk- free rate that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to the passage of time is recognized within finance costs. A provision is discounted using either a nominal discount rate of 2% (2015 2.75%) or a real discount rate of 0.5% (2015 0.75%), as appropriate. Provisions are split between amounts expected to be settled within 12 months of the balance sheet date (current) and amounts expected to be settled later (non-current). Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within the control of the group, or present obligations where it is not probable that an outflow of resources will be required or the amount of the obligation cannot be measured with sufficient reliability. Contingent liabilities are not recognized in the financial statements but are disclosed unless the possibility of an outflow of economic resources is considered remote. Decommissioning Liabilities for decommissioning costs are recognized when the group has an obligation to plug and abandon a well, dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Where an obligation exists for a new facility or item of plant, such as oil and natural gas production or transportation facilities, this liability will be recognized on construction or installation. Similarly, where an obligation exists for a well, this liability is recognized when it is drilled. An obligation for decommissioning may also crystallize during the period of operation of a well, facility or item of plant through a change in legislation or through a decision to terminate operations; an obligation may also arise in cases where an asset has been sold but the subsequent owner is no longer able to fulfil its decommissioning obligations, for example due to bankruptcy. The amount recognized is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. The provision for the costs of decommissioning wells, production facilities and pipelines at the end of their economic lives is estimated using existing technology, at current prices or future assumptions, depending on the expected timing of the activity, and discounted using the real discount rate. The weighted average period over which these costs are generally expected to be incurred is estimated to be approximately 18 years. An amount equivalent to the decommissioning provision is recognized as part of the corresponding intangible asset (in the case of an exploration or appraisal well) or property, plant and equipment. The decommissioning portion of the property, plant and equipment is subsequently depreciated at the same rate as the rest of the asset. Other than the unwinding of discount on the provision, any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding asset. Environmental expenditures and liabilities Environmental expenditures that are required in order for the group to obtain future economic benefits from its assets are capitalized as part of those assets. Expenditures that relate to an existing condition caused by past operations that do not contribute to future earnings are expensed. Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Generally, the timing of recognition of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The amount recognized is the best estimate of the expenditure required to settle the obligation. Provisions for environmental liabilities have been estimated using existing technology, at current prices and discounted using a real discount rate. The weighted average period over which these costs are generally expected to be incurred is estimated to be approximately five years. Significant judgements and estimates: provisions During 2016, significant progress was made in resolving outstanding claims arising from the 2010 Deepwater Horizon accident and oil spill for which, at 31 December 2015, no reliable estimate could be made. As a result, a judgement has been made that a reliable estimate can now be made for all remaining material liabilities arising from the incident. Consequently, the group’s provision at 31 December 2016 for costs associated with the incident now includes the estimated cost of resolving all outstanding business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement and the cost of resolving economic loss and property damage claims from individuals and businesses that opted out of the PSC settlement and/or were excluded from that settlement. The provision for outstanding business economic loss claims under the PSC settlement was determined based upon an expected value of the remaining claims and the resultant charge was recognized in the income statement. Claims are determined by the Deepwater Horizon Court Supervised Settlement Program in accordance with the PSC settlement agreement and, in addition, certain claims are settled by BP. The amounts ultimately payable may differ from the amount provided and the timing of payment is uncertain. A significant number of claims determined by the DHCSSP have been and may be appealed by BP and/or the claimants. Depending upon the resolution of these claims, the amount payable may differ from what is currently provided for. Any further outstanding Deepwater Horizon related claims are not expected to have a material impact on the group’s financial performance. The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest decommissioning obligations facing BP relate to the plugging and abandonment of wells and the removal and disposal of oil and natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly changing, as well as political, environmental, safety and public expectations. BP believes that the impact of any reasonably foreseeable change to these provisions on the group’s results of operations, financial position or liquidity will not be material. If oil and natural gas production facilities and pipelines are sold to third parties and the subsequent owner is unable to meet their decommissioning obligations, judgement must be used to determine whether BP is then responsible for decommissioning, and if so the extent of that responsibility. The timing and amounts of future cash flows are subject to significant uncertainty. Any changes in the expected future costs are reflected in both the provision and the asset. BP Annual Report and Form 20-F 2016 133 i F n a n c a i l s t a t e m e n t s 1. Significant accounting policies, judgements, estimates and assumptions – continued Decommissioning provisions associated with downstream and petrochemicals facilities are generally not recognized, as the potential obligations cannot be measured, given their indeterminate settlement dates. The group performs periodic reviews of its downstream and petrochemicals long-lived assets for any changes in facts and circumstances that might require the recognition of a decommissioning provision. The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology. Other provisions and liabilities are recognized in the period when it becomes probable that there will be a future outflow of funds resulting from past operations or events and the amount of cash outflow can be reliably estimated. The timing of recognition and quantification of the liability require the application of judgement to existing facts and circumstances, which can be subject to change. Since the cash outflows can take place many years in the future, the carrying amounts of provisions and liabilities are reviewed regularly and adjusted to take account of changing facts and circumstances. The timing and amount of future expenditures are reviewed annually, together with the interest rate used in discounting the cash flows. The interest rate used to determine the balance sheet obligation at the end of 2016 was a real rate of 0.5% (2015 0.75%), which was based on long-dated US government bonds. Provisions and contingent liabilities relating to the Gulf of Mexico oil spill are discussed in Note 2. Information about the group’s other provisions is provided in Note 22. As further described in Note 32, the group is subject to claims and actions. The facts and circumstances relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized or revised. Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the outcome of litigation is difficult to predict. Employee benefits Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the balance sheet date are valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the award vests. The accounting policies for share-based payments and for pensions and other post-retirement benefits are described below. Share-based payments Equity-settled transactions The cost of equity-settled transactions with employees is measured by reference to the fair value of the equity instruments on the date on which they are granted and is recognized as an expense over the vesting period, which ends on the date on which the employees become fully entitled to the award. A corresponding credit is recognized within equity. Fair value is determined by using an appropriate, widely used, valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of the shares of the company (market conditions). Non-vesting conditions, such as the condition that employees contribute to a savings-related plan, are taken into account in the grant-date fair value, and failure to meet a non-vesting condition, where this is within the control of the employee is treated as a cancellation and any remaining unrecognized cost is expensed. For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are measured at the fair value of the goods or services received unless their fair value cannot be reliably estimated. If the fair value of the goods and services received cannot be reliably estimated, the transaction is measured by reference to the fair value of the equity instruments granted. Cash-settled transactions The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the corresponding liability which is recognized on the balance sheet. The liability is remeasured at fair value at each balance sheet date until settlement, with changes in fair value recognized in the income statement. Pensions and other post-retirement benefits The cost of providing benefits under the group’s defined benefit plans is determined separately for each plan using the projected unit credit method, which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to determine the present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company becomes committed to a change. Net interest expense relating to pensions and other post-retirement benefits, which is recognized in the income statement, represents the net change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking into account expected changes in the obligation or plan assets during the year. Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not subsequently reclassified to profit and loss. The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the present value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, typically by way of refund. Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable. Significant estimate: pensions and other post-retirement benefits Accounting for defined benefit pensions and other post-retirement benefits involves making significant estimates about uncertain events, including retirement dates, salary levels at retirement, mortality rates, determination of discount rates for measuring plan obligations and net interest expense and assumptions for inflation rates. 134 BP Annual Report and Form 20-F 2016 1. Significant accounting policies, judgements, estimates and assumptions – continued Assumptions about these variables are based on the environment in each country. The assumptions used may vary from year to year, which would affect future net income and net assets. Any differences between these assumptions and the actual outcome also affect future net income and net assets. Pension and other post-retirement benefit assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group’s balance sheet, and pension and other post-retirement benefit expense for the following year. The assumptions used are provided in Note 23. The discount rate and inflation rate have a significant effect on the amounts reported. A sensitivity analysis of the impact of changes in these assumptions on the benefit expense and obligation is provided in Note 23. In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. Mortality assumptions reflect best practice in the countries in which we provide pensions and have been chosen with regard to applicable published tables adjusted where appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. A sensitivity analysis of the impact of changes in the mortality assumptions on the benefit expense and obligation is provided in Note 23. Income taxes Income tax expense represents the sum of current tax and deferred tax. Interest and penalties relating to income tax are also included in the income tax expense. Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity. Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are taxable or deductible in other periods as well as items that are never taxable or deductible. The group’s liability for current tax is calculated using tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for all taxable temporary differences except: • where the deferred tax liability arises on the initial recognition of goodwill • where the deferred tax liability arises on the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss • in respect of taxable temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements, where the group is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred tax assets are recognized for deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits and unused tax losses can be utilized except where the deferred tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss. In respect of deductible temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized. The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and liabilities are not discounted. Deferred tax assets and liabilities are offset only when there is a legally enforceable right to set off current tax assets against current tax liabilities and when the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the current tax assets and liabilities on a net basis or to realize the assets and settle the liabilities simultaneously. Significant judgements and estimates: income taxes The computation of the group’s income tax expense and liability involves the interpretation of applicable tax laws and regulations in many jurisdictions throughout the world. The resolution of tax positions taken by the group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Therefore, judgement is required to determine provisions for income taxes. In addition, the group has carry-forward tax losses and tax credits in certain taxing jurisdictions that are available to offset against future taxable profit. However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused tax losses or tax credits can be utilized. Management judgement is exercised in assessing whether this is the case and estimates are required to be made of the amount of future taxable profits that will be available. To the extent that actual outcomes differ from management’s estimates, income tax charges or credits, and changes in current and deferred tax assets or liabilities, may arise in future periods. For more information see Note 8. Judgement is also required when determining whether a particular tax is an income tax or another type of tax (for example a production tax). Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes; rather such taxes are recognized in the income statement on an appropriate basis. BP Annual Report and Form 20-F 2016 135 i F n a n c a i l s t a t e m e n t s 1. Significant accounting policies, judgements, estimates and assumptions – continued Customs duties and sales taxes Customs duties and sales taxes which are passed on to customers are excluded from revenues and expenses. Assets and liabilities are recognized net of the amount of customs duties or sales tax except: • Customs duties or sales taxes incurred on the purchase of goods and services which are not recoverable from the taxation authority are recognized as part of the cost of acquisition of the asset. • Receivables and payables are stated with the amount of customs duty or sales tax included. The net amount of sales tax recoverable from, or payable to, the taxation authority is included within receivables or payables in the balance sheet. Own equity instruments – treasury shares The group’s holdings in its own equity instruments are shown as deductions from shareholders’ equity at cost. Treasury shares represent BP shares repurchased and available for specific and limited purposes. For accounting purposes, shares held in Employee Share Ownership Plans (ESOPs) to meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are, therefore, included in the financial statements as treasury shares. Consideration, if any, received for the sale of such shares is also recognized in equity, with any difference between the proceeds from sale and the original cost being taken to the profit and loss account reserve. No gain or loss is recognized in the income statement on the purchase, sale, issue or cancellation of equity shares. Shares repurchased under the share buy-back programme which are immediately cancelled are not shown as treasury shares, but are shown as a deduction from the profit and loss account reserve in the group statement of changes in equity. Revenue Revenue arising from the sale of goods is recognized when the significant risks and rewards of ownership have passed to the buyer, which is typically at the point that title passes, and the revenue can be reliably measured. Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods provided in the normal course of business, net of discounts, customs duties and sales taxes. Physical exchanges are reported net, as are sales and purchases made with a common counterparty, as part of an arrangement similar to a physical exchange. Similarly, where the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is recognized but no purchase or sale is recorded. Additionally, where forward sale and purchase contracts for oil, natural gas or power have been determined to be for short-term trading purposes, the associated sales and purchases are reported net within sales and other operating revenues whether or not physical delivery has occurred. Generally, revenues from the production of oil and natural gas properties in which the group has an interest with joint operation partners are recognized on the basis of the group’s working interest in those properties (the entitlement method). Differences between the production sold and the group’s share of production are not significant. Finance costs Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are substantially ready for their intended use. All other finance costs are recognized in the income statement in the period in which they are incurred. Impact of new International Financial Reporting Standards There are no new or amended standards or interpretations adopted during the year that have a significant impact on the financial statements. Not yet adopted The following pronouncements from the IASB will become effective for future financial reporting periods and have not yet been adopted by the group. IFRS 9 ‘Financial Instruments’ will supersede IAS 39 ‘Financial Instruments: Recognition and Measurement’ and is effective for annual periods beginning on or after 1 January 2018. IFRS 9 covers classification and measurement of financial assets and financial liabilities, impairment of financial assets and hedge accounting. IFRS 15 ‘Revenue from Contracts with Customers’ provides a single model for accounting for revenue arising from contracts with customers, focusing on the identification and satisfaction of performance obligations, and is effective for annual periods beginning on or after 1 January 2018. IFRS 15 will supersede IAS 18 ‘Revenue’. BP expects to adopt IFRS 9 and IFRS 15 on 1 January 2018. The group’s evaluation of the effect of adoption of these standards is ongoing but it is not currently anticipated that either IFRS 9 or IFRS 15 will have a material effect on the financial statements. The EU has adopted both IFRS 9 and IFRS 15. IFRS 16 ‘Leases’ provides a new model for lessee accounting in which all leases, other than short-term and small-ticket-item leases, will be accounted for by the recognition on the balance sheet of a right-to-use asset and a lease liability, and the subsequent amortization of the right-to- use asset over the lease term. IFRS 16 will be effective for annual periods beginning on or after 1 January 2019. BP expects to adopt IFRS 16 on 1 January 2019 using the modified retrospective approach to transition permitted by the standard in which the cumulative effect of initially applying the standard is recognized in opening retained earnings at the date of initial application. The group’s evaluation of the effect of adoption of the standard is ongoing but it is expected that it will have a material effect on the group’s financial statements, significantly increasing the group’s recognized assets and liabilities. It is expected that the presentation and timing of recognition of charges in the income statement will also change as the operating lease expense currently reported under IAS 17, typically on a straight-line basis, will be replaced by depreciation of the right-to-use asset and interest on the lease liability. Information on the group’s leases currently classified as operating leases, which are not recognized on the balance sheet, is provided in Note 27. The EU has not yet adopted IFRS 16. There are no other standards and interpretations in issue but not yet adopted that the directors anticipate will have a material effect on the reported income or net assets of the group. 2. Significant event – Gulf of Mexico oil spill As a consequence of the Gulf of Mexico oil spill in April 2010, BP continues to incur costs and has also recognized liabilities for certain future costs. Following significant progress in resolving outstanding claims arising from the 2010 Deepwater Horizon accident and oil spill, a reliable estimate has now been determined for all remaining material liabilities arising from the incident. 136 BP Annual Report and Form 20-F 2016 2. Significant event – Gulf of Mexico oil spill – continued The cumulative pre-tax income statement charge since the incident amounts to $62.6 billion. For more information on the types of expenditure included in the cumulative income statement charge, see Impact upon the group income statement below. It is now possible to reliably estimate the cost of resolving outstanding business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement and the cost of resolving economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were excluded from that settlement. The pre-tax income statement charge for the year of $7.1 billion is primarily attributable to the recognition of additional provisions for these claims. The impacts of the Gulf of Mexico oil spill on the income statement, balance sheet and cash flow statement of the group are included within the relevant line items in those statements and are shown in the table below. Income statement Production and manufacturing expenses Profit (loss) before interest and taxation Finance costs Profit (loss) before taxation Less: Taxation Profit (loss) for the period Balance sheet Current assets Trade and other receivables Current liabilities Trade and other payables Accruals Provisions Net current assets (liabilities) Non-current assets Deferred tax Non-current liabilities Other payables Accruals Provisions Deferred tax Net non-current assets (liabilities) Net assets (liabilities) Cash flow statement Profit (loss) before taxation Net charge for interest and other finance expense, less net interest paid Net charge for provisions, less payments (Increase) decrease in other current and non-current assets Increase (decrease) in other current and non-current liabilities Pre-tax cash flows $ million 2014 781 (781) 38 (819) 262 (557) 2016 2015 6,640 11,709 (6,640) 494 (7,134) 3,105 (4,029) (11,709) 247 (11,956) 3,492 (8,464) 194 686 (3,056) – (2,330) (5,192) (693) (40) (3,076) (3,123) 2,973 – (13,522) – (112) 5,119 (2,057) (186) (13,431) 5,200 (5,542) (10,474) (10,734) (13,597) (7,134) 494 4,353 (3,210) (1,608) (7,105) (11,956) 247 11,296 – (732) (819) 38 939 (662) (792) (1,145) (1,296) The impact on net cash provided by operating activities, on a post-tax basis, amounted to an outflow of $6,892 million (2015 outflow of $1,130 million and 2014 outflow of $9 million). Trust fund BP established the Deepwater Horizon Oil Spill Trust (the Trust), funded in the amount of $20 billion, to satisfy legitimate individual and business claims, state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages and related costs. Fines and penalties are not covered by the trust fund. The funding of the Trust was completed in 2012. The obligation to fund the $20-billion trust fund, adjusted to take account of the time value of money, was recognized in full in 2010 and charged to the income statement. During 2014, cumulative charges to be paid by the Trust reached $20 billion. Subsequent additional costs, over and above those provided within the $20 billion, are expensed to the income statement as incurred. During the first half of 2016, the remaining cash in the Trust was exhausted and BP commenced paying claims and other costs previously funded from the Trust. For certain costs, these payments are made by BP into qualified settlement funds administered by the PSC settlement programmes, which then distribute the amounts to claimants. During 2016, BP paid $3,210 million to the qualified settlement funds. Other payables Other payables include amounts payable under the agreements with the United States and five Gulf coast states that were approved by the federal district court in 2016, including amounts payable for natural resource damages, state claims and Clean Water Act penalties (for full details BP Annual Report and Form 20-F 2016 137 i F n a n c a i l s t a t e m e n t s 2. Significant event – Gulf of Mexico oil spill – continued of these agreements, see BP Annual Report and Form 20-F 2015). Further, at 31 December 2016, $1,929 million remains in Other payables in relation to the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident, of which $739 million falls due in 2017. In addition, Other payables at 31 December 2016 includes BP’s remaining commitment to fund the Gulf of Mexico Research Initiative, which is a 10-year research programme to study the impact of the incident on the marine and shoreline environment of the Gulf of Mexico. Amounts payable for certain economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were excluded from that settlement, as well as certain business economic loss claims under the PSC settlement, are also included in Other payables. Provisions and contingent liabilities Provisions Provisions relating to the agreements with the United States and five Gulf coast states were reclassified to Other payables during 2016, upon approval of those agreements by the federal district court. Remaining provisions relating to the Gulf of Mexico oil spill relate to litigation and claims. Movements in each class of provision during the year and cumulatively since the incident are presented in the tables below. At 1 January Net increase in provision Unwinding of discount Reclassified to other payables Utilization – paid by BP – paid by the settlement fund or Trust At 31 December Of which – current – non-current Net increase in provision Unwinding of discount Change in discount rate Reclassified to other payables Utilization – paid by BP – paid by the settlement fund or Trust At 31 December 2016 Environmental Litigation and claims Clean Water Act 5,919 – 52 (5,970) (1) – – – – 6,459 6,440 25 (4,943) (2,086) (3,453) 2,442 2,330 112 4,129 – 38 (4,167) – – – – – $ million 2016 Total 16,507 6,440 115 (15,080) (2,087) (3,453) 2,442 2,330 112 $ million Cumulative since the incident Environmental Litigation and claims Clean Water Act 19,992 159 (130) (6,429) (11,711) (1,881) 38,867 81 (74) (9,351) (6,400) (20,681) 4,171 106 (110) (4,167) – – Total 63,030 346 (314) (19,947) (18,111) (22,562) – 2,442 – 2,442 Environmental The environmental provisions relating to natural resource damage costs and the early restoration framework agreement were reclassified to Other payables during 2016 following approval by the Court in April 2016 of the Consent Decree between the United States, the Gulf states and BP. Litigation and claims The litigation and claims provision includes amounts for the future cost of resolving claims by individuals and businesses for damage to real or personal property, lost profits or impairment of earning capacity and loss of subsistence use of natural resources. Claims administration costs and legal costs have also been provided for. Litigation and claims – PSC settlement The Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) with the PSC provides for a court-supervised settlement programme, the Deepwater Horizon Court Supervised Settlement Program (DHCSSP), which commenced operation on 4 June 2012. A separate claims administrator has been appointed to pay medical claims and to implement other aspects of the Medical Benefits Class Action Settlement. For further information on the PSC settlements, see Legal proceedings on page 261. The provision for the cost associated with the 2012 PSC settlement has been determined based upon an expected value of the remaining claims, including business economic loss claims. During the year, significant progress was made in resolving business economic loss claims. Claims were determined by the DHCSSP in accordance with the PSC settlement agreement and in addition, certain claims were settled by BP. The provision has been increased in the year to reflect the estimate of the cost of the remaining claims which are expected to be determined and paid by the DHCSSP or resolved by BP, and associated costs. Amounts to resolve remaining claims are expected to be substantially paid in 2017. However, the amounts ultimately payable may differ from the amount provided and the timing of payment is uncertain. A significant number of claims determined by the DHCSSP have been and may be appealed by BP and/or the claimants. Depending upon the resolution of these claims, the amount payable may differ from what is currently provided for. Litigation and claims – Other claims An estimate of the cost of the remaining economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were excluded from that settlement, is recognized in provisions. Amounts have been reclassified to Other payables during the year where settlements were agreed. The 31 December 2015 provision recognized for litigation and claims included amounts agreed under the agreements with the United States and five Gulf Coast states in relation to state claims, which were reclassified to Other payables during 2016. These state claims are payable over 18 years. 138 BP Annual Report and Form 20-F 2016 2. Significant event – Gulf of Mexico oil spill – continued Clean Water Act penalties The provision previously recognized for penalties under Section 311 of the Clean Water Act, as determined by the civil settlement with the United States, was reclassified to Other payables during 2016 following approval by the Court of the Consent Decree. The amount is payable in instalments over 15 years, commencing April 2017. The unpaid balance of this penalty accrues interest at a fixed rate. Provision movements The total amount recognized as an increase in provisions during the year was $6,440 million. It is now possible to reliably estimate the cost of resolving outstanding business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement and the cost of resolving economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were excluded from that settlement, associated claims administration costs and other items. The increase in provisions in 2016 relates primarily to the recognition of amounts for these items, which could not be reliably estimated and provided for in 2015. After deducting amounts utilized during the year totalling $5,540 million, comprising payments from the trust fund and qualifying settlement fund of $3,453 million and payments made directly by BP of $2,087 million (2015 $3,279 million, comprising payments from the trust fund of $3,022 million and payments made directly by BP of $257 million), and after adjustments for discounting, the remaining provision as at 31 December 2016 was $2,442 million (2015 $16,507 million). Contingent liabilities For information on Legal proceedings relating to the Deepwater Horizon oil spill, see Legal proceedings on pages 261-264. Any further outstanding Deepwater Horizon related claims are not expected to have a material impact on the group’s financial performance. Impact upon the group income statement The group income statement for 2016 includes a pre-tax charge of $7,134 million (2015 pre-tax charge of $11,956 million) in relation to the Gulf of Mexico oil spill. The costs charged within production and manufacturing expenses in 2016 include the amounts charged for provisions for business economic loss claims and economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were excluded from that settlement, the cost of the securities claims settlement with the certified class of post-explosion ADS purchasers which was agreed in June 2016, as well as operating and other costs. Finance costs of $494 million (2015 $247 million) reflect the unwinding of the discount on payables and provisions. The cumulative amount charged to the income statement to date comprises spill response costs arising in the aftermath of the incident, amounts charged for the agreements with the United States and five Gulf coast states that were approved by the federal district court in 2016, including amounts payable for natural resource damages, state claims and Clean Water Act penalties, operating costs, amounts charged upon initial recognition of the trust obligation, other litigation, claims, environmental and legal costs and estimated obligations for future costs, net of settlements agreed with the co-owners of the Macondo well and other third parties. The total amount recognized in the income statement is analysed in the table below. Trust fund liability – discounted Change in discounting relating to trust fund liability Recognition of reimbursement asset Other Total (credit) charge relating to the trust fund Environmental costs Spill response costs Litigation and claims costs Clean Water Act penalties Other costs Settlements credited to the income statement (Profit) loss before interest and taxation Finance costs (Profit) loss before taxation 3. Non-current assets held for sale 2016 2015 – – – – – – – 6,596 – 44 – 6,640 494 7,134 – – – – – 5,303 – 5,758 551 97 – 11,709 247 11,956 $ million Cumulative since the incident 19,580 283 (20,000) 8 (129) 8,526 14,304 39,134 4,061 1,398 (5,681) 61,613 972 62,585 2014 – – (662) – (662) 192 – 1,137 – 114 – 781 38 819 There were no non-current assets or associated liabilities classified as held for sale as at 31 December 2016. The assets and associated liabilities classified as held for sale at 31 December 2015 related to the dissolution of the group’s German refining joint operation with Rosneft, which was completed on 31 December 2016. BP Annual Report and Form 20-F 2016 139 i F n a n c a i l s t a t e m e n t s 4. Disposals and impairment The following amounts were recognized in the income statement in respect of disposals and impairments. Gains on sale of businesses and fixed assets Upstream Downstream Other businesses and corporate Losses on sale of businesses and fixed assets Upstream Downstream Other businesses and corporate Impairment losses Upstream Downstream Other businesses and corporate Impairment reversals Upstream Downstream Impairment and losses on sale of businesses and fixed assets Disposals Disposal proceeds and principal gains and losses on disposals by segment are described below. Proceeds from disposals of fixed assets Proceeds from disposals of businesses, net of cash disposed By business Upstream Downstream Other businesses and corporate 2016 2015 557 561 14 1,132 324 316 26 666 2016 2015 $ million 2014 405 474 16 895 $ million 2014 345 401 3 749 6,737 1,264 317 8,318 (102) – (102) 124 98 41 263 2,484 265 155 2,904 (1,080) (178) (1,258) 1,909 8,965 2015 1,066 1,726 2,792 769 1,747 276 2,792 $ million 2014 1,820 1,671 3,491 2,533 864 94 3,491 169 89 3 261 1,022 84 11 1,117 (3,025) (17) (3,042) (1,664) 2016 1,372 1,259 2,631 839 1,646 146 2,631 At 31 December 2016, deferred consideration relating to disposals amounted to $255 million receivable within one year (2015 $41 million and 2014 $1,137 million) and $271 million receivable after one year (2015 $385 million and 2014 $333 million). In addition, contingent consideration receivable relating to disposals amounted to $131 million at 31 December 2016 (2015 $292 million and 2014 $454 million), see Note 29 for further information. Upstream In 2016, gains principally resulted from the contribution of BP’s Norwegian upstream business into Aker BP ASA and from the sale of certain properties in the UK. Losses principally arose from the disposal of certain exploration licences in Australia and contract losses following asset disposals in the US. In 2015, gains principally resulted from the sale of our interests in the Central Area Transmission System in the North Sea, and from adjustments to prior year disposals in Canada. In 2014, gains principally resulted from the sale of certain onshore assets in the US, and the sale of certain interests in the Gulf of Mexico and the North Sea. Losses principally arose from adjustments to prior year disposals in Canada and the North Sea. Downstream In 2016, gains principally resulted from the disposal of certain US and non-US midstream assets in our fuels business and the dissolution of our German refining joint operation with Rosneft. In 2015, gains principally resulted from the disposal of our investment in the UTA European fuel cards business and our Australian bitumen business. In 2014, gains principally resulted from the disposal of our global aviation turbine oils business. Losses principally arose from costs associated with the decision to cease refining operations at Bulwer Island in Australia. Summarized financial information relating to the sale of businesses is shown in the table below. The principal transactions categorized as business disposals in 2016 were the contribution of BP’s Norwegian upstream business into Aker BP ASA and the dissolution of the group’s German refining joint operation with Rosneft. The principal transactions categorized as business disposals in 2015 were the sales of our 140 BP Annual Report and Form 20-F 2016 4. Disposals and impairment – continued interests in the Central Area Transmission System in the North Sea and in the UTA European fuel cards business. The principal transaction categorized as a business disposal in 2014 was the sale of certain of our interests on the North Slope of Alaska in our upstream business. Non-current assets Current assets Non-current liabilities Current liabilities Total carrying amount of net assets disposed Recycling of foreign exchange on disposal Costs on disposala Gains on sale of businessesb Total consideration Non-cash considerationc Consideration received (receivable)d Proceeds from the sale of businesses related to completed transactions Depositse Proceeds from the sale of businesses, net of cash disposedf 2016 4,794 1,202 (2,558) (532) 2,906 25 229 3,160 593 3,753 (2,698) 223 1,278 (19) 1,259 2015 154 80 (70) (50) 114 16 8 138 446 584 – 1,116 1,700 26 1,726 $ million 2014 1,452 182 (395) (65) 1,174 (7) 128 1,295 280 1,575 – 96 1,671 – 1,671 a Includes amounts relating to the remeasurement to fair value of certain assets as a result of the dissolution of our German refining joint operation with Rosneft. b 2016 gains on sale of businesses include deferred amounts not recognized in the income statement. c Non-cash consideration principally relates to the contribution of BP’s Norwegian upstream business into Aker BP ASA in exchange for 30% interest in Aker BP ASA and the dissolution of the group’s German refining joint operation with Rosneft. d Consideration received from prior year business disposals or to be received from current year disposals. 2015 included $1,079 million of proceeds from our Toledo refinery partner, Husky Energy, in place of capital commitments relating to the original divestment transaction that have not been subsequently sanctioned. e Proceeds received in the current year in advance of business disposals, less deposits received in prior years in relation to business disposals completed in the current year. f Proceeds are stated net of cash and cash equivalents disposed of $676 million (2015 $9 million and 2014 $32 million). Impairments Impairment losses and impairment reversals in each segment are described below. For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment, intangibles and goodwill within Note 1. Upstream Impairment losses and reversals related primarily to producing and midstream assets. The 2016 impairment losses of $1,022 million related to a number of different assets, with the most significant charges arising in the North Sea. Impairment losses within Upstream arose primarily as a result of revised cost estimates and decisions to dispose of certain assets. On 3 April 2017, BP announced that it has agreed to sell its Forties Pipeline System business to INEOS for a consideration of up to $250 million. The transaction will lead to an impairment charge of approximately $0.4 billion, which will be included in the group income statement for 2017. The 2016 impairment reversals of $3,025 million primarily related to the North Sea and Angola. The largest impairment reversals related to the Andrew area cash-generating unit (CGU) in the North Sea and the PSVM and Greater Plutonio CGUs in Angola but none of these were individually significant. In addition an impairment reversal was recorded in relation to the Block KG D6 CGU in India; and exploration costs were also written back during the period (see Note 7). The impairment reversals arose following a reduction in the discount rate applied, changes to future price assumptions, and also increased confidence in the progress of the KG D6 projects in India. See Impairment of property, plant and equipment, intangible assets and goodwill within Note 1 for information on assumptions used for impairment testing. The 2015 impairment losses of $2,484 million included $761 million in Angola, of which $371 million related to the Greater Plutonio CGU. Impairment losses also included $830 million in relation to CGUs in the North Sea, of which $328 million related to the Andrew area CGU. The impairment losses primarily arose as a result of a lower price environment in the near term, and were also affected to a lesser extent by certain technical reserves revisions and increases in decommissioning cost estimates. The 2015 impairment reversals of $1,080 million included $945 million in the North Sea business, of which $473 million related to the Eastern Trough Area Project (ETAP) CGU. The impairment reversals mainly arose as a result of decreases in cost estimates and a reduction in the discount rate applied, offsetting the impact of lower prices in the near term. Impairment losses and reversals related to producing assets. The discount rate used to determine the recoverable amount of the Greater Plutonio CGU included the 2% premium for higher-risk countries. A premium was not applied in determining the recoverable amount of the other CGUs. The 2014 impairment losses of $6,737 million included $4,876 million in relation to CGUs in the North Sea, of which $1,964 million related to the Valhall CGU, $660 million related to the Andrew area CGU, and $515 million related to the ETAP CGU. Impairment losses also included an $859- million impairment of our PSVM CGU in Angola, and a $415-million impairment of the Block KG D6 CGU in India. All of the impairments related to producing assets. The impairments in the North Sea and Angola arose as a result of a lower price environment in the near term, technical reserves revisions, and increases in expected decommissioning cost estimates. The impairment of Block KG D6 arose following the introduction of a new formula for Indian gas prices. The discount rate used to determine the value in use of the PSVM CGU included the 2% premium for higher-risk countries. A premium was not applied in determining the recoverable amount of the other CGUs. Downstream The 2016 impairment losses of $84 million principally related to certain office buildings which are expected to be vacated. The 2015 impairment losses of $265 million arose principally in relation to certain manufacturing assets in our petrochemicals business and certain US midstream assets, where the expected disposal proceeds were lower than the book values. The 2014 impairment losses of $1,264 million principally related to our Bulwer Island refinery and certain midstream assets in our fuels business, and certain manufacturing assets in our petrochemicals business. BP Annual Report and Form 20-F 2016 141 i F n a n c a i l s t a t e m e n t s 4. Disposals and impairment – continued Other businesses and corporate Impairment losses totalling $11 million, $155 million, and $317 million were recognized in 2016, 2015 and 2014 respectively. The amount for 2015 was principally in respect of our US wind business. The amount for 2014 was principally in respect of our biofuels businesses in the UK and US. 5. Segmental analysis The group’s organizational structure reflects the various activities in which BP is engaged. At 31 December 2016, BP had three reportable segments: Upstream, Downstream and Rosneft. Upstream’s activities include oil and natural gas exploration, field development and production; midstream transportation, storage and processing; and the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs). Downstream’s activities include the refining, manufacturing, marketing, transportation, and supply and trading of crude oil, petroleum, petrochemicals products and related services to wholesale and retail customers. BP’s interest in Rosneft is accounted for using the equity method and is reported as a separate operating segment, reflecting the way in which the investment is managed. Other businesses and corporate comprises the biofuels and wind businesses, the group’s shipping and treasury functions, and corporate activities worldwide. The costs relating to the Gulf of Mexico oil spill were previously presented as a reconciling item between the sum of the results of the reportable segments and the group results. From 2016, we have reported these costs as part of Other businesses and corporate. Prior period comparatives have been amended to reflect this new presentation. The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. However, IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for the purposes of performance assessment and resource allocation. For BP, this measure of profit or loss is replacement cost profit or loss before interest and tax which reflects the replacement cost of supplies by excluding from profit or loss inventory holding gains and lossesa. Replacement cost profit or loss for the group is not a recognized measure under IFRS. Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers by region are based on the location of the group subsidiary which made the sale. The UK region includes the UK-based international activities of Downstream. All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-retirement benefit plans are allocated to Other businesses and corporate. However, the periodic expense relating to these plans is allocated to the operating segments based upon the business in which the employees work. Certain financial information is provided separately for the US as this is an individually material country for BP, and for the UK as this is BP’s country of domicile. a Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. 142 BP Annual Report and Form 20-F 2016 5. Segmental analysis – continued By business Segment revenues Upstream Downstream Rosneft Other businesses and corporate Consolidation adjustment and eliminations Sales and other operating revenues Less: sales and other operating revenues between segments Third party sales and other operating revenues Earnings from joint ventures and associates – after interest 33,188 (17,581) 15,607 167,683 (1,291) 166,392 – – – 1,667 (658) 1,009 723 574 60 634 608 647 (18) 5,162 1,484 6,646 590 53 643 (8,157) – (8,157) (19,530) 19,530 – – (196) – (196) and tax Segment results Replacement cost profit (loss) before interest and taxation Inventory holding gains (losses)a Profit (loss) before interest and taxation Finance costs Net finance expense relating to pensions and other post- retirement benefits Profit (loss) before taxation Other income statement items Depreciation, depletion and amortization US Non-US Charges for provisions, net of write-back of unused provisions, including change in discount rate Segment assets Investments in joint ventures and associates Additions to non-current assetsb 4,396 7,835 352 10,968 17,879 856 1,094 758 3,035 3,109 – – – 8,243 – 71 253 6,719 455 216 – – – – – a See explanation of inventory holding gains and losses on page 142. b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates. By business Segment revenues Sales and other operating revenues Less: sales and other operating revenues between segments Third party sales and other operating revenues Earnings from joint ventures and associates – after interest and tax Segment results Replacement cost profit (loss) before interest and taxation Inventory holding gains (losses)a Profit (loss) before interest and taxation Finance costs Net finance expense relating to pensions and other post- retirement benefits Profit (loss) before taxation Other income statement items Depreciation, depletion and amortization US Non-US Charges for provisions, net of write-back of unused provisions, including change in discount rate Segment assets Investments in joint ventures and associates Additions to non-current assetsb Upstream Downstream Rosneft Other businesses and corporate Consolidation adjustment and eliminations 43,235 (21,949) 21,286 200,569 (68) 200,501 – – – 2,048 (941) 1,107 192 491 1,330 (202) (937) (30) (967) 7,111 (1,863) 5,248 1,310 4 1,314 (13,477) – (13,477) (22,958) 22,958 – – (36) – (36) 4,007 8,866 906 1,162 824 611 – – – 8,304 17,635 3,214 2,130 5,797 – 77 201 11,781 519 315 – – – – – a See explanation of inventory holding gains and losses on page 142. b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates. $ million 2016 Total group 183,008 – 183,008 1,960 (2,027) 1,597 (430) (1,675) (190) (2,295) 5,323 9,182 7,829 22,701 21,204 $ million 2015 Total group 222,894 – 222,894 1,811 (6,029) (1,889) (7,918) (1,347) (306) (9,571) 4,990 10,229 13,216 17,834 20,080 i F n a n c a i l s t a t e m e n t s BP Annual Report and Form 20-F 2016 143 5. Segmental analysis – continued By business Segment revenues Sales and other operating revenues Less: sales and other operating revenues between segments Third party sales and other operating revenues Earnings from joint ventures and associates – after interest and tax Segment results Replacement cost profit (loss) before interest and taxation Inventory holding gains (losses)a Profit (loss) before interest and taxation Finance costs Net finance expense relating to pensions and other post- retirement benefits Profit before taxation Other income statement items Depreciation, depletion and amortization US Non-US Charges for provisions, net of write-back of unused provisions, including change in discount rate Segment assets Investments in joint ventures and associates Additions to non-current assetsb Upstream Downstream Rosneft Other businesses and corporate Consolidation adjustment and eliminations 65,424 (36,643) 28,781 323,486 173 323,659 – – – 1,989 (861) 1,128 1,089 265 2,101 (83) 8,934 (86) 8,848 3,738 (6,100) (2,362) 2,100 (24) 2,076 (2,791) – (2,791) (37,331) 37,331 – – 641 – 641 4,129 8,404 984 1,336 260 713 – – – 7,877 22,587 3,244 3,121 7,312 – 97 213 1,652 723 784 – – – – – $ million 2014 Total group 353,568 – 353,568 3,372 12,622 (6,210) 6,412 (1,148) (314) 4,950 5,210 9,953 2,625 19,156 26,492 a See explanation of inventory holding gains and losses on page 142. b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates. 144 BP Annual Report and Form 20-F 2016 5. Segmental analysis – continued By geographical area Revenues Third party sales and other operating revenuesa Other income statement items Production and similar taxes Results US Non-US $ million 2016 Total 65,132 117,876 183,008 155 528 683 Replacement cost profit (loss) before interest and taxation (8,311) 6,284 (2,027) Non-current assets Non-current assetsb c 64,628 118,152 182,780 a Non-US region includes UK $37,119 million. b Non-US region includes UK $18,615 million. c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments. By geographical area Revenues Third party sales and other operating revenuesa Other income statement items Production and similar taxes Results US Non-US $ million 2015 Total 74,162 148,732 222,894 215 821 1,036 Replacement cost profit (loss) before interest and taxation (12,243) 6,214 (6,029) Non-current assets Non-current assetsb c 67,776 111,106 178,882 a Non-US region includes UK $51,550 million. b Non-US region includes UK $19,152 million. c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments. By geographical area Revenues US Non-US $ million 2014 Total Third party sales and other operating revenuesa 122,951 230,617 353,568 Other income statement items Production and similar taxes Results Replacement cost profit before interest and taxation Non-current assets Non-current assetsb c 690 2,268 2,958 5,251 7,371 12,622 69,125 114,462 183,587 a Non-US region includes UK $77,522 million. b Non-US region includes UK $18,430 million. c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments. 6. Income statement analysis Interest and other income Interest income Other income Currency exchange losses charged to the income statementa Expenditure on research and development Finance costs Interest payable Capitalized at 1.81% (2015 1.75% and 2014 1.94%)b Unwinding of discount on provisions and other payables a Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss. b Tax relief on capitalized interest is approximately $56 million (2015 $42 million and 2014 $43 million). 2016 2015 183 323 506 698 400 226 385 611 8 418 $ million 2014 258 585 843 36 663 1,221 (244) 698 1,675 1,065 (179) 461 1,347 1,025 (185) 308 1,148 BP Annual Report and Form 20-F 2016 145 i F n a n c a i l s t a t e m e n t s 7. Exploration for and evaluation of oil and natural gas resources The following financial information represents the amounts included within the group totals relating to activity associated with the exploration for and evaluation of oil and natural gas resources. All such activity is recorded within the Upstream segment. For information on significant judgements made in relation to oil and natural gas accounting see Intangible assets within Note 1. Exploration and evaluation costs Exploration expenditure written offa Other exploration costs Exploration expense for the year Impairment losses Intangible assets – exploration and appraisal expenditure Liabilities Net assets Cash used in operating activities Cash used in investing activities 2016 2015 1,274 447 1,721 62 1,829 524 2,353 – $ million 2014 3,029 603 3,632 – 16,960 17,286 19,344 102 145 227 16,858 17,141 19,117 447 2,920 524 1,216 603 2,786 a 2016 included a $601-million write-off in Brazil relating to the BM-C-34 licence and various write-offs in the Gulf of Mexico totalling $611 million and India totalling $216 million, partially offset by a write-back of $319 million in India relating to block KG D6 as a result of increased confidence in the progress of the projects. An impairment reversal of $234 million was also recorded in 2016 in relation to KG D6 in India. 2015 included a $432-million write-off in Libya as there was significant uncertainty about the timing of future drilling operations. It also included a $345-million write-off relating to the Gila discovery in the deepwater Gulf of Mexico and a $336-million write-off relating to the Pandora discovery in Angola as development of these prospects was considered challenging. 2014 included a $544-million write-off relating to disappointing appraisal results of Utica shale in the US Lower 48 and the subsequent decision not to proceed with its development plans, a $524-million write-off relating to the Bourarhat Sud block licence in the Illizi Basin of Algeria, a $395-million write-off relating to Block KG D6 in India and a $295-million write-off relating to the Moccasin discovery in the deepwater Gulf of Mexico. For further information see Upstream – Exploration on page 26. During February 2017, following completion of drilling of certain exploration wells in Egypt, BP determined that no commercial hydrocarbons had been found. The costs incurred, totalling $269 million, will be included in the group income statement for 2017. The carrying amount, by location, of exploration and appraisal expenditure capitalized as intangible assets at 31 December 2016 is shown in the table below. Carrying amount $1 - 2 billion $2 - 3 billion $3 - 4 billion 8. Taxation Tax on profit Current tax Charge for the year Adjustment in respect of prior yearsa Deferred tax Origination and reversal of temporary differences in the current year Adjustment in respect of prior yearsa b Tax charge (credit) on profit or loss Location Angola; India; Egypt; Middle East Canada; Brazil US – Gulf of Mexico 2016 2015 1,762 (123) 1,639 (3,709) (397) (4,106) (2,467) 1,910 (329) 1,581 (5,090) 338 (4,752) (3,171) $ million 2014 4,444 48 4,492 (3,194) (351) (3,545) 947 a The adjustments in respect of prior years reflect the reassessment of the current tax and deferred tax balances for prior years in light of changes in facts and circumstances during the year. b 2016 includes the reassessment of the recognition of deferred tax assets in relation to foreign tax credits in the US. In 2016, the total tax credit recognized within other comprehensive income was $752 million (2015 $1,140 million charge and 2014 $1,481 million credit). See Note 31 for further information. The total tax credit recognized directly in equity was $5 million (2015 $9 million charge and 2014 $36 million charge). For information on significant estimates and judgements made in relation to taxation see Income taxes within Note 1. Reconciliation of the effective tax rate The following table provides a reconciliation of the group weighted average statutory corporate income tax rate to the effective tax rate of the group on profit or loss before taxation. For 2016 and 2015 the items presented in the reconciliation are affected as a result of the overall tax credit for the year and the loss before taxation. In order to provide a more meaningful analysis of the effective tax rate, the table also presents separate reconciliations for the group excluding the impacts of the Gulf of Mexico oil spill and impairment losses and reversals, and for the impacts of the Gulf of Mexico oil spill and impairment losses and reversals in isolation. For 2014, the items presented in the reconciliation are affected as a result of the tax credits related to the impairment losses recognized in the year and the effect of the impairment losses on the profit for the year. In order to provide a more meaningful analysis of the effective tax rate for 146 BP Annual Report and Form 20-F 2016 8. Taxation – continued 2014, the table also presents separate reconciliations for the group excluding the effects of the impairment losses and for the effects of the impairment losses in isolation. 2016 excluding impacts of Gulf of Mexico oil spill and impairments 2,914 (117) (4)% 2016 impacts of Gulf of Mexico oil spill and impairments (5,209) (2,350) 45% 2015 excluding impacts of Gulf of Mexico oil spill and impairments 4,031 945 23% 2015 impacts of Gulf of Mexico oil spill and impairments (13,602) (4,116) 30% 2016 (2,295) (2,467) 107% 2014 excluding impairments 13,166 5,036 38% 2014 impacts of impairments (8,216) (4,089) 50% 2015 (9,571) (3,171) 33% $ million 2014 4,950 947 19% 18 (15) 5 26 (9) – (24) 1 8 (15) 1 (4) 33 – 13 3 – (2) – – – – (2) 45 52 19 23 (27) 11 (4) 30 (2) (11) 19 (3) 107 17 (7) 1 17 (8) – (3) 18 10 (23) 1 23 % of profit or loss before taxation 38 46 38 55 10 – – (5) – (2) – – – – (1) 30 3 – (14) 3 (3) 1 (8) (4) 10 (1) 33 (5) (2) 4 (4) – (1) 4 4 – – 38 – – (3) – – – – (2) – – 50 (14) (6) 17 (10) 1 (1) 10 12 – – 19 Profit (loss) before taxation Tax charge (credit) on profit or loss Effective tax rate Tax rate computed at the weighted average statutory ratea Increase (decrease) resulting from Tax reported in equity-accounted entities Adjustments in respect of prior years Movement in deferred tax not recognized Tax incentives for investment Gulf of Mexico oil spill non- deductible costs Disposal impactsb Foreign exchange Items not deductible for tax purposes Decrease in rate of UK supplementary chargec Other Effective tax rate a Calculated based on the statutory corporate income tax rate applicable in the countries in which the group operates, weighted by the profits and losses before tax in the respective countries. It reflects the mix of profits and losses arising in higher tax rate jurisdictions (primarily the Upstream segment) and lower tax rate jurisdictions (primarily the Downstream segment). b In 2016 this relates primarily to the tax impact on the contribution of BP’s Norwegian upstream business into Aker BP ASA. c This relates to the deferred tax impact of the reductions in the UK supplementary charge tax rate applicable to profits arising in the North Sea from 20% to 10% in 2016 and from 32% to 20% in 2015. Deferred tax Analysis of movements during the year in the net deferred tax liability At 1 January Exchange adjustments Charge (credit) for the year in the income statement Charge (credit) for the year in other comprehensive income Charge (credit) for the year in equity Acquisitions and disposals At 31 December 2016 8,054 (71) (4,106) (714) (5) (661) 2,497 $ million 2015 11,584 86 (4,752) 1,140 9 (13) 8,054 The following table provides an analysis of deferred tax in the income statement and the balance sheet by category of temporary difference: Deferred tax liability Depreciation Pension plan surpluses Derivative financial instruments Other taxable temporary differences Deferred tax asset Pension plan and other post-retirement benefit plan deficits Decommissioning, environmental and other provisions Derivative financial instruments Tax creditsa Loss carry forward Other deductible temporary differences Net deferred tax charge (credit) and net deferred tax liability Of which – deferred tax liabilities – deferred tax assets Income statement $ million Balance sheet 2016 2015 2014 2016 2015 81 (12) (230) (122) (283) 98 591 (6) (5,177) 249 422 (3,823) (4,106) (102) 84 (326) 59 (285) 12 (2,513) 62 256 (2,239) (45) (4,467) (4,752) (2,178) (272) 527 (1,805) (3,728) 492 52 166 589 (1,397) 281 183 (3,545) 26,864 171 761 1,254 29,050 (1,889) (12,108) (734) (5,225) (5,458) (1,139) (26,553) 2,497 7,238 4,741 28,712 878 961 1,266 31,817 (1,972) (13,737) (710) (43) (5,985) (1,316) (23,763) 8,054 9,599 1,545 a The increase in tax credits in 2016 reflects the impact of a loss carry-back claim in the US, displacing foreign tax credits utilized in prior periods which are now carried forward. BP Annual Report and Form 20-F 2016 147 i F n a n c a i l s t a t e m e n t s 8. Taxation – continued The recognition of deferred tax assets of $3,839 million (2015 $1,067 million), in entities which have suffered a loss in either the current or preceding period, is supported by forecasts which indicate that sufficient future taxable profits will be available to utilize such assets. Of this amount, $2,974 million relates to the US (2015 $nil). A summary of temporary differences, unused tax credits and unused tax losses for which deferred tax has not been recognized is shown in the table below. At 31 December Unused US state tax lossesa Unused tax losses – other jurisdictionsb Unused tax credits of which – arising in the UKc – arising in the USd Deductible temporary differencese Taxable temporary differences associated with investments in subsidiaries and equity-accounted entities 2016 9.6 5.2 19.2 17.1 2.0 26.7 3.1 $ billion 2015 9.6 2.1 20.4 17.5 2.8 23.2 3.9 a These losses expire in the period 2017–2036 with applicable tax rates ranging from 4% to 12%. b The majority of the unused tax losses have no fixed expiry date. c The UK unused tax credits arise predominantly in overseas branches of UK entities based in jurisdictions with higher statutory corporate income tax rates than the UK. No deferred tax asset has been recognized on these tax credits as they are unlikely to have value in the future; UK taxes on these overseas branches are largely mitigated by double tax relief in respect of overseas tax. These tax credits have no fixed expiry date. d The US unused tax credits expire in the period 2017-2026. e The majority comprises fixed asset temporary differences in the UK. Substantially all of the temporary differences have no expiry date. Impact of previously unrecognized deferred tax or write-down of deferred tax assets on current year charge Current tax benefit relating to the utilization of previously unrecognized tax credits and losses Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets Deferred tax benefit relating to the recognition of previously unrecognized tax credits and losses Deferred tax expense arising from the write-down of a previously recognized deferred tax asset 2016 40 269 394 55 2015 123 – – 768 $ million 2014 171 – – 153 9. Dividends The quarterly dividend paid on 31 March 2017 in respect of the fourth quarter 2016 was 10 cents per ordinary share ($0.60 per American Depositary Share (ADS)). The corresponding amount in sterling was announced on 20 March 2017. A scrip dividend alternative is available, allowing shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs. Pence per share Cents per share 2016 2015 2014 2016 2015 2014 2016 2015 $ million 2014 Dividends announced and paid in cash Preference shares Ordinary shares March June September December Dividend announced, paid in March 2017 7.0125 6.9167 7.5578 7.9313 29.4183 6.6699 6.5295 6.5488 6.6342 26.3824 5.7065 5.8071 5.9593 6.3769 23.8498 1 2 2 10.00 10.00 10.00 10.00 40.00 10.00 10.00 10.00 10.00 10.00 40.00 9.50 9.75 9.75 10.00 39.00 1,099 1,168 1,161 1,182 4,611 1,303 1,708 1,691 1,717 1,541 6,659 1,426 1,572 1,122 1,728 5,850 The details of the scrip dividends issued are shown in the table below. Number of shares issued (thousand) Value of shares issued ($ million) 2016 548,005 2,858 2015 102,810 642 2014 165,644 1,318 The financial statements for the year ended 31 December 2016 do not reflect the dividend announced on 7 February 2017 and paid in March 2017; this will be treated as an appropriation of profit in the year ended 31 December 2017. 10. Earnings per ordinary share Per ordinary share Basic earnings per share Diluted earnings per share Per ADS Basic earnings per share Diluted earnings per share 2016 0.61 0.60 2016 0.04 0.04 Cents per share 2015 (35.39) (35.39) 2014 20.55 20.42 Dollars per share 2015 (2.12) (2.12) 2014 1.23 1.23 Basic earnings per ordinary share amounts are calculated by dividing the profit (loss) for the year attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year. The average number of shares outstanding includes certain shares that will be issuable in the future under employee share-based payment plans and excludes treasury shares, which includes shares held by the Employee Share Ownership Plan trusts (ESOPs). 148 BP Annual Report and Form 20-F 2016 10. Earnings per ordinary share – continued For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the average number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method. If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share. A dilutive effect relating to potentially issuable shares has not been included, therefore, in the calculation of diluted earnings per share for 2015. Profit (loss) attributable to BP shareholders Less: dividend requirements on preference shares Profit (loss) for the year attributable to BP ordinary shareholders Basic weighted average number of ordinary shares Potential dilutive effect of ordinary shares issuable under employee share-based payment plans Weighted average number of ordinary shares outstanding used to calculate diluted earnings per share Basic weighted average number of ordinary shares - ADS equivalent Potential dilutive effect of ordinary shares (ADS equivalent) issuable under employee share-based payment plans Weighted average number of ordinary shares (ADS equivalent) outstanding used to calculate 2016 115 1 114 2015 (6,482) 2 (6,484) $ million 2014 3,780 2 3,778 2016 2015 2014 18,744,800 18,323,646 18,385,458 Shares thousand 110,519 – 111,836 18,855,319 18,323,646 18,497,294 2016 2015 2014 3,124,133 3,053,941 3,064,243 Shares thousand 18,420 – 18,639 diluted earnings per share 3,142,553 3,053,941 3,082,882 The number of ordinary shares outstanding at 31 December 2016, excluding treasury shares, and including certain shares that will be issuable in the future under employee share-based payment plans was 19,438,990,091. Between 31 December 2016 and 16 March 2017, the latest practicable date before the completion of these financial statements, there was a net increase of 71,878,542 in the number of ordinary shares outstanding as a result of share issues in relation to employee share-based payment plans. Employee share-based payment plans The group operates share and share option plans for directors and certain employees to obtain ordinary shares and ADSs in the company. Information on these plans for directors is shown in the Directors remuneration report on pages 80-110. The following table shows the number of shares potentially issuable under equity-settled employee share option plans, including the number of options outstanding, the number of options exercisable at the end of each year, and the corresponding weighted average exercise prices. The dilutive effect of these plans at 31 December is also shown. Share options Outstanding Exercisable Dilutive effect 2016 Weighted average exercise price $ 3.85 4.59 n/a Number of optionsa b thousand 26,284 498 3,380 2015 Weighted average exercise price $ 8.54 10.21 n/a Number of optionsa b thousand 70,049 46,520 2,659 a Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares). b At 31 December 2016 the quoted market price of one BP ordinary share was £5.10 (2015 £3.54). In addition, the group operates a number of equity-settled employee share plans under which share units are granted to the group’s senior leaders and certain other employees. These plans typically have a three-year performance or restricted period during which the units accrue net notional dividends which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for qualifying reasons. The number of shares that are expected to vest each year under employee share plans are shown in the table below. The dilutive effect of the employee share plans at 31 December is also shown. Share plans Vesting Within one year 1 to 2 years 2 to 3 years 3 to 4 years 4 to 5 years Dilutive effect 2016 2015 Number of sharesa thousand Number of sharesa thousand 92,529 94,760 102,342 680 319 290,630 113,012 78,823 76,779 89,654 41,479 695 287,430 101,984 a Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares). There has been a net decrease of 28,236,653 in the number of potential ordinary shares relating to employee share-based payment plans between 31 December 2016 and 16 March 2017. BP Annual Report and Form 20-F 2016 149 i F n a n c a i l s t a t e m e n t s 11. Property, plant and equipment Land and land Improvements Buildings Oil and gas propertiesa Plant, machinery and equipment Fixtures, fittings and office equipment Transportation 3,194 (119) 106 46 – – (161) 3,066 642 (9) 40 – 9 (2) – (96) 584 2,877 (37) 24 – – – (629) 2,235 1,157 (44) 166 – 123 – – (340) 1,062 215,566 – 12,036 – – 1,629 (13,667) 215,564 123,831 – 11,213 – 518 (2,923) 5 (10,216) 122,428 45,744 (342) 1,699 793 (1,505) – (2,664) 43,725 20,652 (264) 1,740 (1,319) 11 (12) – (2,122) 18,686 2,866 (127) 192 – – – (261) 2,670 2,084 (96) 214 – 79 – – (259) 2,022 14,038 (9) 156 – – – (185) 14,000 9,439 (6) 397 – 256 (101) – (162) 9,823 Oil depots, storage tanks and service stations 8,418 (375) 568 – – – (988) 7,623 5,140 (218) 384 – 4 (4) – (785) 4,521 $ million Total 292,703 (1,009) 14,781 839 (1,505) 1,629 (18,555) 288,883 162,945 (637) 14,154 (1,319) 1,000 (3,042) 5 (13,980) 159,126 2,482 1,173 93,136 25,039 648 4,177 3,102 129,757 Cost At 1 January 2016 Exchange adjustments Additions Acquisitions Remeasurementsb Transfers Deletions At 31 December 2016 Depreciation At 1 January 2016 Exchange adjustments Charge for the year Remeasurementsb Impairment losses Impairment reversals Transfers Deletions At 31 December 2016 Net book amount at 31 December 2016 Cost At 1 January 2015 Exchange adjustments Additions Acquisitions Transfers Reclassified as assets held for sale Deletions 3,415 (259) 96 – – – (58) 3,061 (144) 122 – – (66) (96) 200,514 – 14,574 – 1,039 – (561) 48,815 (1,828) 1,114 27 – (1,364) (1,020) At 31 December 2015 3,194 2,877 215,566 45,744 3,031 (89) 129 – – (31) (174) 2,866 1,983 (56) 238 1 – – (24) (58) 13,819 (61) 493 – – – (213) 9,046 (772) 551 – – 281,701 (3,153) 17,079 27 1,039 – (407) (1,461) (2,529) 14,038 8,418 292,703 8,933 (33) 426 283 (18) – – (152) 9,439 5,724 (452) 323 7 (159) – 151,009 (1,516) 14,923 2,645 (1,258) 21 – (303) (1,095) (1,784) 5,140 162,945 1,197 (51) 135 2 – – (33) (93) 111,175 – 12,004 2,113 (1,079) 21 – (403) 21,358 (914) 1,760 225 (2) – (1,038) (737) 639 (10) 37 14 – – – (38) 642 1,157 123,831 20,652 2,084 2,552 1,720 91,735 25,092 782 4,599 3,278 129,758 – – 2 2 21 84 266 297 – – 241 242 – – 530 625 29,177 27,755 a For information on significant estimates and judgements made in relation to the estimation of oil and natural reserves see Property, plant and equipment within Note 1. b Relates to the remeasurement to fair value of previously held interests in certain assets as a result of the dissolution on 31 December 2016 of the group’s German refining joint operation with Rosneft. 12. Capital commitments Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been signed at 31 December 2016 amounted to $11,207 million (2015 $10,379 million). BP’s share of capital commitments of joint ventures amounted to $522 million (2015 $586 million). 150 BP Annual Report and Form 20-F 2016 Depreciation At 1 January 2015 Exchange adjustments Charge for the year Impairment losses Impairment reversals Transfers Reclassified as assets held for sale Deletions At 31 December 2015 Net book amount at 31 December 2015 Assets held under finance leases at net book amount included above At 31 December 2016 At 31 December 2015 Assets under construction included above At 31 December 2016 At 31 December 2015 13. Goodwill and impairment review of goodwill Cost At 1 January Exchange adjustments Acquisitions Deletions At 31 December Impairment losses At 1 January Exchange adjustments Deletions At 31 December Net book amount at 31 December Net book amount at 1 January Impairment review of goodwill Goodwill at 31 December Upstream Downstream Other businesses and corporate 2016 $ million 2015 12,236 (544) 247 (134) 11,805 12,482 (237) 5 (14) 12,236 609 5 (3) 611 614 – (5) 609 11,194 11,627 11,627 11,868 2016 7,726 3,401 67 $ million 2015 7,812 3,761 54 11,194 11,627 Goodwill acquired through business combinations has been allocated to groups of cash-generating units that are expected to benefit from the synergies of the acquisition. For Upstream, goodwill is allocated to all oil and gas assets in aggregate at the segment level. For Downstream, goodwill has been allocated to Lubricants and Other. For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment, intangibles and goodwill within Note 1. Upstream Goodwill Excess of recoverable amount over carrying amount i F n a n c a i l 2016 7,726 26,035 $ million 2015 7,812 12,894 s t a t e m e n t s The table above shows the carrying amount of goodwill for the segment at year-end and the excess of the recoverable amount, based upon a fair value less costs of disposal calculation, over the carrying amount (the headroom) at the date of the test. The fair value less costs of disposal is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates of cessation of production of each producing field, based on current estimates of reserves and resources, appropriately risked for the purposes of goodwill impairment testing. Midstream and supply and trading activities and equity-accounted entities are generally not included in the impairment review of goodwill, because they are not part of the grouping of cash-generating units to which the goodwill relates and which is used to monitor the goodwill for internal management purposes. Where such activities form part of a wider Upstream cash- generating unit, they are reflected in the test. The fair value calculation is based primarily on level 3 inputs as defined by the IFRS 13 ‘Fair value measurement’ hierarchy. As the production profile and related cash flows can be estimated from BP’s experience, management believes that the estimated cash flows expected to be generated over the life of each field is the appropriate basis upon which to assess goodwill for impairment. The estimated date of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons, production costs, the contractual duration of the production concession and the selling price of the hydrocarbons produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of the fields are computed using appropriate individual economic models and key assumptions agreed by BP management. Capital expenditure, operating costs and expected hydrocarbon production profiles are derived from the business segment plan. Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis are developed to be consistent with this. The production profiles used are consistent with the reserve and resource volumes approved as part of BP’s centrally controlled process for the estimation of proved and probable reserves and total resources. Intangible assets are deemed to have a recoverable amount equal to their carrying amount. The 2016 review for impairment was carried out during the third quarter following the change in price assumptions and discount rate as disclosed in Note 1. In prior years the review was carried out during the fourth quarter. In the absence of any indicators of impairment in other quarters, the review will be carried out in the third quarter in future years. The key assumptions used in the fair value less costs of disposal calculation are oil and natural gas prices, production volumes and the discount rate. Price assumptions and discount rate assumptions used were as disclosed in Note 1. The fair value less costs of disposal calculations have been prepared solely for the purposes of determining whether the goodwill balance was impaired. Estimated future cash flows were prepared on the basis of certain assumptions prevailing at the time of the test. The actual outcomes may differ from the assumptions made. For example, reserves and resources estimates and production forecasts are subject to revision as further technical information becomes available and economic conditions change, and future commodity prices may differ from the forecasts used in the calculations. BP Annual Report and Form 20-F 2016 151 13. Goodwill and impairment review of goodwill – continued The sensitivities to different variables have been estimated using certain simplifying assumptions. For example, lower oil and gas price sensitivities do not reflect the specific impacts for each contractual arrangement and will not capture fully any favourable impacts that may arise from cost deflation. Therefore a detailed calculation at any given price or production profile may produce a different result. It is estimated that if the oil price assumption for all future years (the first five years, and the long-term assumption from 2022 onwards) was approximately $13 per barrel lower in each year, this would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment. It is estimated that if the gas price assumption for all future years was approximately $2 per mmBtu lower in each year, this would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment. Estimated production volumes are based on detailed data for each field and take into account development plans agreed by management as part of the long-term planning process. The average production for the purposes of goodwill impairment testing over the next 15 years is 889mmboe per year (2015 911mmboe per year). It is estimated that if production volume were to be reduced by approximately 4% for this period, this would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment. It is estimated that if the post-tax discount rate was approximately 9% for the entire portfolio, an increase of 3% for all countries not considered ‘higher risk’ and 1% for countries considered ‘higher risk’, this would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment. Downstream Goodwill Lubricants 2,571 Other 830 2016 Total Lubricants 3,401 3,109 Other 652 $ million 2015 Total 3,761 Cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of two to five years. To determine the value in use for each of the cash-generating units, cash flows for a period of 10 years are discounted and aggregated with a terminal value. Lubricants As permitted by IAS 36, the detailed calculations of Lubricants’ recoverable amount performed in the most recent detailed calculation in 2013 were used for the 2016 impairment test as the criteria in that standard were considered satisfied: the headroom was substantial in 2013; there have been no significant changes in the assets and liabilities; and the likelihood that the recoverable amount would be less than the carrying amount at the time was remote. The key assumptions to which the calculation of value in use for the Lubricants unit is most sensitive are operating unit margins, sales volumes, and discount rate. The values assigned to these key assumptions reflect BP’s experience. No reasonably possible change in any of these key assumptions would cause the unit’s carrying amount to exceed its recoverable amount. Cash flows beyond the two-year plan period were extrapolated using a nominal 3% growth rate. 14. Intangible assets Cost At 1 January Exchange adjustments Acquisitions Additions Transfers Reclassified as assets held for sale Deletions At 31 December Amortization At 1 January Exchange adjustments Charge for the year Impairment losses Transfers Reclassified as assets held for sale Deletions At 31 December Net book amount at 31 December Net book amount at 1 January a For further information see Intangible assets within Note 1 and Note 7. 152 BP Annual Report and Form 20-F 2016 Exploration and appraisal expenditurea Other intangibles 19,856 – – 2,896 (1,629) – (2,599) 18,524 2,570 – 1,274 62 (5) – (2,337) 1,564 16,960 17,286 4,055 (149) 15 251 – – (137) 4,035 2,681 (96) 351 – – – (124) 2,812 1,223 1,374 2016 Total 23,911 (149) 15 3,147 (1,629) – (2,736) 22,559 5,251 (96) 1,625 62 (5) – (2,461) 4,376 18,183 18,660 Exploration and appraisal expenditurea Other intangibles 21,723 – – 1,197 (1,039) – (2,025) 19,856 2,379 – 1,829 – (21) – (1,617) 2,570 17,286 19,344 4,268 (187) – 234 – (18) (242) 4,055 2,705 (75) 296 – – (15) (230) 2,681 1,374 1,563 $ million 2015 Total 25,991 (187) – 1,431 (1,039) (18) (2,267) 23,911 5,084 (75) 2,125 – (21) (15) (1,847) 5,251 18,660 20,907 15. Investments in joint ventures The following table provides aggregated summarized financial information relating to the group’s share of joint ventures. Sales and other operating revenues Profit before interest and taxation Finance costs Profit before taxation Taxation Profit (loss) for the year Other comprehensive income Total comprehensive income Non-current assets Current assets Total assets Current liabilities Non-current liabilities Total liabilities Net assets Group investment in joint ventures Group share of net assets (as above) Loans made by group companies to joint ventures $ million 2014 12,208 1,210 125 1,085 515 570 (15) 555 2016 10,081 1,612 156 1,456 490 966 5 971 10,874 3,257 14,131 2,087 3,520 5,607 8,524 8,524 85 8,609 2015a 9,588 785 188 597 625 (28) (1) (29) 11,163 2,515 13,678 1,855 3,500 5,355 8,323 8,323 89 8,412 a The loss for 2015 shown in the table above included $711 million relating to BP`s share of impairment losses recognized by joint ventures, a significant element of which related to the Angola LNG plant. Transactions between the group and its joint ventures are summarized below. Sales to joint ventures Product LNG, crude oil and oil products, natural gas Purchases from joint ventures Product LNG, crude oil and oil products, natural gas, refinery operating costs, plant processing fees 2016 Amount receivable at 31 December 291 2016 Amount payable at 31 December 2015 Amount receivable at 31 December 245 2015 Amount payable at 31 December Sales 2,841 Purchases Sales 2,760 Purchases Sales 3,148 Purchases $ million 2014 Amount receivable at 31 December 300 $ million 2014 Amount payable at 31 December 943 120 861 104 907 129 The terms of the outstanding balances receivable from joint ventures are typically 30 to 45 days. The balances are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above. 16. Investments in associates The following table provides aggregated summarized financial information for the group’s associates as it relates to the amounts recognized in the group income statement and on the group balance sheet. Rosneft Other associates Income statement Earnings from associates – after interest and tax 2016 647 347 994 2015 1,330 509 1,839 2014 2,101 701 2,802 2016 8,243 5,849 14,092 $ million Balance sheet Investments in associates 2015 5,797 3,625 9,422 The associate that is material to the group at both 31 December 2016 and 2015 is Rosneft. BP owns 19.75% of the voting shares of Rosneft which are listed on the MICEX stock exchange in Moscow and its global depository receipts are listed on the London Stock Exchange. The Russian federal government, through its investment company JSC Rosneftegaz, owned 50.0% plus one share of the voting shares of Rosneft at 31 December 2016. BP classifies its investment in Rosneft as an associate because, in management’s judgement, BP has significant influence over Rosneft; see Interests in other entities within Note 1 for further information. The group’s investment in Rosneft is a foreign operation whose functional BP Annual Report and Form 20-F 2016 153 i F n a n c a i l s t a t e m e n t s 16. Investments in associates – continued currency is the Russian rouble. The increase in the group`s equity-accounted investment balance for Rosneft at 31 December 2016 compared with 31 December 2015 principally relates to foreign exchange effects which have been recognized in other comprehensive income. The value of BP’s 19.75% shareholding in Rosneft based on the quoted market share price of $6.50 per share (2015 $3.48 per share) was $13,604 million at 31 December 2016 (2015 $7,283 million). The following table provides summarized financial information relating to Rosneft. This information is presented on a 100% basis and reflects adjustments made by BP to Rosneft’s own results in applying the equity method of accounting. BP adjusts Rosneft’s results for the accounting required under IFRS relating to BP’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the disposal of BP’s interest in TNK-BP. These adjustments have increased the reported profit for 2016, as shown in the table below, compared with the equivalent amount in Russian roubles that we expect Rosneft to report in its own financial statements under IFRS. Sales and other operating revenues Profit before interest and taxation Finance costs Profit before taxation Taxation Non-controlling interests Profit for the year Other comprehensive income Total comprehensive income Non-current assets Current assets Total assets Current liabilities Non-current liabilities Total liabilities Net assets Less: non-controlling interests $ million Gross amount 2014 142,856 19,367 5,230 14,137 3,428 71 10,638 (13,038) (2,400) 2016 74,380 7,094 1,747 5,347 1,797 273 3,277 4,203 7,480 129,403 37,914 167,317 46,284 71,980 118,264 49,053 7,316 41,737 2015 84,071 12,253 3,696 8,557 1,792 30 6,735 (4,111) 2,624 84,689 34,891 119,580 25,691 63,554 89,245 30,335 982 29,353 The group received dividends, net of withholding tax, of $332 million from Rosneft in 2016 (2015 $271 million and 2014 $693 million). Summarized financial information for the group’s share of associates is shown below. $ million BP share 2014 Total 37,938 4,763 1,040 3,723 907 14 2,802 (2,565) 237 Rosneft Other 28,214 3,825 1,033 2,792 677 14 2,101 (2,575) (474) 9,724 938 7 931 230 – 701 10 711 Sales and other operating revenues Profit before interest and taxation Finance costs Profit before taxation Taxation Non-controlling interests Profit for the year Other comprehensive income Total comprehensive income Non-current assets Current assets Total assets Current liabilities Non-current liabilities Total liabilities Net assets Less: non-controlling interests Group investment in associates Group share of net assets (as above) Loans made by group companies to associates Rosnefta Other 14,690 1,401 345 1,056 355 54 647 830 1,477 25,557 7,488 33,045 9,141 14,216 23,357 9,688 1,445 8,243 5,377 525 22 503 156 – 347 (2) 345 7,848 2,002 9,850 1,827 2,934 4,761 5,089 – 5,089 2016 Total 20,067 1,926 367 1,559 511 54 994 828 1,822 33,405 9,490 42,895 10,968 17,150 28,118 14,777 1,445 13,332 Rosnefta Other 16,604 2,420 730 1,690 354 6 1,330 (812) 518 16,726 6,891 23,617 5,074 12,552 17,626 5,991 194 5,797 6,000 661 6 655 146 – 509 (2) 507 3,914 1,621 5,535 1,134 1,311 2,445 3,090 – 3,090 2015 Total 22,604 3,081 736 2,345 500 6 1,839 (814) 1,025 20,640 8,512 29,152 6,208 13,863 20,071 9,081 194 8,887 8,243 5,089 13,332 5,797 3,090 8,887 – 8,243 760 5,849 760 14,092 – 5,797 535 3,625 535 9,422 a From 1 October 2014, Rosneft adopted hedge accounting in relation to a portion of highly probable future export revenue denominated in US dollars over a five-year period. Foreign exchange gains and losses arising on the retranslation of borrowings denominated in currencies other than the Russian rouble and designated as hedging instruments are recognized initially in other comprehensive income, and are reclassified to the income statement as the hedged revenue is recognized. 154 BP Annual Report and Form 20-F 2016 16. Investments in associates – continued Transactions between the group and its associates are summarized below. Sales to associates Product LNG, crude oil and oil products, natural gas Purchases from associates Product Crude oil and oil products, natural gas, transportation tariff 2016 Amount receivable at 31 December 765 2016 Amount payable at 31 December 2015 Amount receivable at 31 December 1,058 2015 Amount payable at 31 December Sales 5,302 Purchases Sales 9,589 Purchases $ million 2014 Amount receivable at 31 December 1,258 $ million 2014 Amount payable at 31 December 2,000 11,619 2,026 22,703 2,307 Sales 4,210 Purchases 8,873 In addition to the transactions shown in the table above, in 2016 the group completed the dissolution of its German refining joint operation with Rosneft. In 2015, the group acquired a 20% participatory interest in Taas-Yuryakh Neftegazodobycha, a Rosneft subsidiary. The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above. The majority of the sales to and purchases from associates relate to crude oil and oil products transactions with Rosneft. BP has commitments amounting to $12,768 million (2015 $11,446 million), primarily in relation to contracts with its associates for the purchase of transportation capacity. 17. Other investments Equity investmentsa Other a The majority of equity investments are unlisted. 2016 $ million 2015 Current Non-current Current Non-current 2 42 44 405 628 1,033 – 219 219 397 605 1,002 Other non-current investments includes $628 million relating to life insurance policies (2015 $605 million) which have been designated as financial assets at fair value through profit and loss. Their valuation methodology is in level 3 of the fair value hierarchy. 18. Inventories Crude oil Natural gas Refined petroleum and petrochemical products Supplies Trading inventories 2016 5,531 155 9,198 14,884 2,388 17,272 383 17,655 $ million 2015 3,467 251 7,470 11,188 2,626 13,814 328 14,142 Cost of inventories expensed in the income statement 132,219 164,790 The inventory valuation at 31 December 2016 is stated net of a provision of $501 million (2015 $1,295 million) to write inventories down to their net realizable value. The net credit to the income statement in the year in respect of inventory net realizable value provisions was $769 million (2015 $1,507 million credit). Trading inventories are valued using quoted benchmark bid prices adjusted as appropriate for location and quality differentials. They are predominantly categorized within level 2 of the fair value hierarchy. BP Annual Report and Form 20-F 2016 155 i F n a n c a i l s t a t e m e n t s 19. Trade and other receivables Financial assets Trade receivables Amounts receivable from joint ventures and associates Other receivables Non-financial assets Gulf of Mexico oil spill trust fund reimbursement asseta Other receivables 2016 $ million 2015 Current Non-current Current Non-current 13,393 1,056 5,352 19,801 194 680 874 – – 815 815 – 659 659 13,682 1,303 5,908 20,893 686 744 1,430 72 – 1,249 1,321 – 895 895 20,675 1,474 22,323 2,216 a See Note 2 for further information. Trade and other receivables are predominantly non-interest bearing. See Note 28 for further information. 20. Valuation and qualifying accounts At 1 January Charged to costs and expenses Charged to other accountsa Deductions At 31 December a Principally exchange adjustments. 2016 2015 $ million 2014 Accounts receivable Fixed asset investments Accounts receivable Fixed asset investments Accounts receivable Fixed asset investments 447 120 (7) (168) 392 435 55 (2) (153) 335 331 243 (23) (104) 447 517 195 (4) (273) 435 343 127 (24) (115) 331 168 438 (2) (87) 517 Valuation and qualifying accounts comprise impairment provisions for accounts receivable and fixed asset investments, and are deducted in the balance sheet from the assets to which they apply. For information on significant judgements made in relation to the recoverability of trade receivables see Impairment of loans and receivables within Note 1. 21. Trade and other payables Financial liabilities Trade payables Amounts payable to joint ventures and associates Other payablesa Non-financial liabilities Other payables 2016 $ million 2015 Current Non-current Current Non-current 21,575 2,120 12,079 35,774 – – 13,760 13,760 16,838 2,130 10,775 29,743 2,141 37,915 186 13,946 2,206 31,949 – – 2,351 2,351 559 2,910 a The majority of non-current other payables relate to the Gulf of Mexico oil spill. See Note 2 for further information. Trade and other payables, other than those relating to the Gulf of Mexico oil spill, are predominantly interest free. See Note 28 for further information. 156 BP Annual Report and Form 20-F 2016 22. Provisions At 1 January 2016 Exchange adjustments Acquisitions Increase (decrease) in existing provisions Write-back of unused provisions Unwinding of discount Change in discount rate Utilization Reclassified to other payables Deletions At 31 December 2016 Of which – current – non-current Of which – Gulf of Mexico oil spilla Decommissioning Environmental Litigation and claims Clean Water Act penalties 18,946 (607) – (804) – 162 738 (17) (624) (1,352) 16,442 244 16,198 – 7,557 (3) 6 262 (96) 62 18 (239) (5,970) (13) 1,584 315 1,269 – 7,134 – 4 6,650 (36) 36 20 (5,625) (5,012) (9) 3,162 2,460 702 2,442 4,129 – – – – 38 – – (4,167) – – – – – $ million Total 41,114 (693) 42 7,386 (431) 310 808 (6,764) (15,962) (1,386) 24,424 4,012 20,412 2,442 Other 3,348 (83) 32 1,278 (299) 12 32 (883) (189) (12) 3,236 993 2,243 – a Further information on the financial impacts of the Gulf of Mexico oil spill is provided in Note 2. The decommissioning provision comprises the future cost of decommissioning oil and natural gas wells, facilities and related pipelines. The environmental provision includes provisions for costs related to the control, abatement, clean-up or elimination of environmental pollution relating to soil, groundwater, surface water and sediment contamination. The litigation and claims category includes provisions for matters related to, for example, commercial disputes, product liability, and allegations of exposures of third parties to toxic substances. Included within the other category at 31 December 2016 are provisions for deferred employee compensation of $422 million (2015 $484 million). For information on significant estimates and judgements made in relation to provisions, including those for the Gulf of Mexico oil spill, see Provisions and contingencies within Note 1. 23. Pensions and other post-retirement benefits Most group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned. Pension benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and other types of schemes with committed pension benefit payments). For defined contribution plans, retirement benefits are determined by the value of funds arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such factors as an employee’s pensionable salary and length of service. Defined benefit plans may be funded or unfunded. The assets of funded plans are generally held in separately administered trusts. For information on significant estimates and judgements made in relation to accounting for these plans see Pensions and other post-retirement benefits within Note 1. The primary pension arrangement in the UK is a funded final salary pension plan under which retired employees draw the majority of their benefit as an annuity. This pension plan is governed by a corporate trustee whose board is composed of four member-nominated directors, four company-nominated directors, an independent director and an independent chairman nominated by the company. The trustee board is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as investment policies of the plan. The UK plan is closed to new joiners but remains open to ongoing accrual for current members. New joiners in the UK are eligible for membership of a defined contribution plan. In the US, all employees now accrue benefits under a cash balance formula. Benefits previously accrued under final salary formulas are legally protected. Retiring US employees typically take their pension benefit in the form of a lump sum payment upon retirement. The plan is funded and its assets are overseen by a fiduciary Investment Committee composed of six BP employees appointed by the president of BP Corporation North America Inc. (the appointing officer). The Investment Committee is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as the investment policies of the plan. US employees are also eligible to participate in a defined contribution (401k) plan in which employee contributions are matched with company contributions. In the US, group companies also provide post-retirement healthcare to retired employees and their dependants (and, in certain cases, life insurance coverage); the entitlement to these benefits is usually based on the employee remaining in service until a specified age and completion of a minimum period of service. In the Eurozone, there are defined benefit pension plans in Germany, France, the Netherlands and other countries. In Germany and France, the majority of the pensions are unfunded, in line with market practice. In Germany, the group’s largest Eurozone plan, employees receive a pension and also have a choice to supplement their core pension through salary sacrifice. For employees who joined since 2002 the core pension benefit is a career average plan with retirement benefits based on such factors as an employee’s pensionable salary and length of service. The returns on the notional contributions made by both the company and employees are based on the interest rate which is set out in German tax law. Retired German employees take their pension benefit typically in the form of an annuity. The German plans are governed by legal agreements between BP and the works council or between BP and the trade union. The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall due. During 2016 the aggregate level of contributions was $651 million (2015 $1,066 million and 2014 $1,252 million). The aggregate level of contributions in 2017 is expected to be approximately $1,050 million, and includes contributions in all countries that we expect to be required to make contributions by law or under contractual agreements, as well as an allowance for discretionary funding. For the primary UK plan there is a funding agreement between the group and the trustee. On an annual basis the latest funding position is reviewed and a schedule of contributions covering the next seven years is agreed. The funding agreement can be terminated unilaterally by either party with two years’ notice. Contractually committed funding therefore represents nine years of future contributions, which amounted to $5,761 million at 31 December 2016, of which $2,410 million relates to past service. This amount is included in the group’s committed cash BP Annual Report and Form 20-F 2016 157 i F n a n c a i l s t a t e m e n t s 23. Pensions and other post-retirement benefits – continued flows relating to pensions and other post-retirement benefit plans as set out in the table of contractual obligations on page 243. The surplus relating to the primary UK pension plan is recognized on the balance sheet on the basis that the company is entitled to a refund of any remaining assets once all members have left the plan. Pension contributions in the US are determined by legislation and are supplemented by discretionary contributions. All of the contributions made into the US pension plan in 2016 were discretionary and no statutory funding requirement is expected in the next 12 months. There was no minimum funding requirement for the US plan, and no significant minimum funding requirements in other countries at 31 December 2016. The obligation and cost of providing pensions and other post-retirement benefits is assessed annually using the projected unit credit method. The date of the most recent actuarial review was 31 December 2016. The UK plans are subject to a formal actuarial valuation every three years; valuations are required more frequently in many other countries. The most recent formal actuarial valuation of the UK pension plans was as at 31 December 2014. A valuation of the US plan is carried out annually. The material financial assumptions used to estimate the benefit obligations of the various plans are set out below. The assumptions are reviewed by management at the end of each year, and are used to evaluate the accrued benefit obligation at 31 December and pension expense for the following year. Financial assumptions used to determine benefit obligation 2016 2015 Discount rate for plan liabilities Rate of increase in salaries Rate of increase for pensions in payment Rate of increase in deferred pensions Inflation for plan liabilities Financial assumptions used to determine benefit expense Discount rate for plan service cost Discount rate for plan other finance expense Inflation for plan service cost 2.7 4.6 3.0 3.0 3.2 2016 4.0 3.9 3.1 3.9 4.4 3.0 3.0 3.0 2015 3.9 3.6 3.1 UK 2014 3.6 4.5 3.0 3.0 3.0 UK 2014 4.8 4.6 3.4 2016 2015 3.9 4.2 – – 1.8 2016 4.2 4.0 1.5 4.0 3.9 – – 1.5 2015 3.8 3.7 1.6 US 2014 3.7 4.0 – – 1.6 US 2014 4.6 4.3 2.1 2016 2015 1.7 3.0 1.5 0.5 1.6 2016 2.7 2.4 1.8 2.4 3.2 1.6 0.6 1.8 2015 2.3 2.0 2.0 % Eurozone 2014 2.0 3.4 1.8 0.7 2.0 % Eurozone 2014 3.9 3.6 2.0 The discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and the Eurozone we use yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans are based on the difference between the yields on index-linked and fixed-interest long-term government bonds. In other countries, including the Eurozone, we use this approach, or advice from the local actuary depending on the information available. The inflation assumptions are used to determine the rate of increase for pensions in payment and the rate of increase in deferred pensions where there is such an increase. For 2016 the assumed rate of increase for the UK plans also reflects the probability of exceeding a cap or breaching a floor for pension increases as set out in the plan rules; this change resulted in a reduction in the pension obligation of $865 million. The assumptions for the rate of increase in salaries are based on the inflation assumption plus an allowance for expected long-term real salary growth. These include allowance for promotion-related salary growth, of up to 0.8% depending on country. In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best practice in the countries in which we provide pensions, and have been chosen with regard to applicable published tables adjusted where appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. BP’s most substantial pension liabilities are in the UK, the US and the Eurozone where our mortality assumptions are as follows: Mortality assumptions 2016 2015 UK 2014 2016 2015 US 2014 2016 2015 Years Eurozone 2014 Life expectancy at age 60 for a male currently aged 60 28.0 28.5 28.3 25.7 25.7 25.6 25.0 24.9 24.7 Life expectancy at age 60 for a male currently aged 40 30.0 31.0 30.9 27.5 27.5 27.4 27.6 27.5 27.3 Life expectancy at age 60 for a female currently aged 60 29.5 29.5 29.4 29.3 29.2 29.1 28.9 28.8 28.7 Life expectancy at age 60 for a female currently aged 40 31.9 31.9 31.8 31.0 30.9 30.9 31.3 31.2 31.1 Pension plan assets are generally held in trusts. The primary objective of the trusts is to accumulate pools of assets sufficient to meet the obligations of the various plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management. A significant proportion of the assets are held in equities, which are expected to generate a higher level of return over the long term, with an acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment portfolios are highly diversified. For the primary UK pension plan there is an agreement with the trustee to reduce the proportion of plan assets held as equities and increase the proportion held as bonds over time, with a view to better matching the asset portfolio with the pension liabilities. There is a similar agreement in place in the US. During 2016, the UK and the US plans switched 4% and nil respectively from equities to bonds. BP’s primary plan in the UK uses a liability driven investment (LDI) approach for part of the portfolio, a form of investing designed to match the movement in pension plan assets with the impact of interest rate changes and inflation assumption changes on the projected benefit obligation. 158 BP Annual Report and Form 20-F 2016 23. Pensions and other post-retirement benefits – continued The current asset allocation policy for the major plans at 31 December 2016 was as follows: Asset category Total equity (including private equity) Bonds/cash (including LDI) Property/real estate UK % 58 35 7 US % 55 45 – The amounts invested under the LDI programme as at 31 December 2016 were $423 million (2015 $329 million) of government-issued nominal bonds and $9,384 million (2015 $6,421 million) of index-linked bonds. This is partly funded by short-term sale and repurchase agreements, proceeds from which are shown separately in the table below. In addition, the primary UK plan entered into interest rate swaps in the year to offset the long-term fixed interest rate exposure for $4,450 million (2015 $2,651 million) of the corporate bond portfolio. At 31 December 2016 the fair value liability of these swaps was $144 million (2015 $17 million fair value asset) and is included in other assets in the table below. Some of the group’s pension plans in other countries also use derivative financial instruments as part of their asset mix to manage the level of risk. The group’s main pension plans do not invest directly in either securities or property/real estate of the company or of any subsidiary. The fair values of the various categories of assets held by the defined benefit plans at 31 December are presented in the table below, including the effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on page 160. Fair value of pension plan assets At 31 December 2016 Listed equities – developed markets – emerging markets Private equity Government issued nominal bonds Government issued index-linked bonds Corporate bonds Property Cash Other Debt (repurchase agreements) used to fund liability driven investments At 31 December 2015 Listed equities – developed markets – emerging markets Private equity Government issued nominal bonds Government issued index-linked bonds Corporate bonds Property Cash Other Debt (repurchase agreements) used to fund liability driven investments At 31 December 2014 Listed equities – developed markets – emerging markets Private equity Government issued nominal bonds Government issued index-linked bonds Corporate bonds Property Cash Other UKa USb Eurozone Other 11,494 2,549 2,754 489 9,384 4,042 1,970 547 (68) (2,981) 30,180 13,474 2,305 2,933 393 6,425 4,357 2,453 564 110 (1,791) 31,223 16,190 2,719 2,983 642 892 4,687 2,403 1,145 112 31,773 2,283 220 1,442 1,438 – 1,732 6 105 90 – 7,316 2,329 226 1,522 1,527 – 1,717 6 116 67 – 7,510 3,026 293 1,571 1,535 – 1,726 7 134 63 8,355 436 54 1 821 4 427 45 17 74 – 363 46 – 448 – 259 28 83 83 – 1,879 1,310 423 49 1 685 5 551 48 10 102 – 371 50 4 492 – 367 58 139 50 – 1,874 1,531 415 45 2 753 9 541 51 85 72 420 47 26 604 – 340 69 191 38 1,973 1,735 $ million Total 14,576 2,869 4,197 3,196 9,388 6,460 2,049 752 179 (2,981) 40,685 16,597 2,630 4,460 3,097 6,430 6,992 2,565 829 329 (1,791) 42,138 20,051 3,104 4,582 3,534 901 7,294 2,530 1,555 285 43,836 a Bonds held by the UK pension plans are all denominated in sterling. Property held by the UK pension plans is in the United Kingdom. b Bonds held by the US pension plans are denominated in US dollars. BP Annual Report and Form 20-F 2016 159 i F n a n c a i l s t a t e m e n t s 23. Pensions and other post-retirement benefits – continued Analysis of the amount charged to profit (loss) before interest and taxation Current service costa Past service costb Settlement Operating charge relating to defined benefit plans Payments to defined contribution plans Total operating charge Interest income on plan assetsa Interest on plan liabilities Other finance expense Analysis of the amount recognized in other comprehensive income Actual asset return less interest income on plan assets Change in financial assumptions underlying the present value of the plan liabilities Change in demographic assumptions underlying the present value of the plan liabilities Experience gains and losses arising on the plan liabilities Remeasurements recognized in other comprehensive income Movements in benefit obligation during the year Benefit obligation at 1 January Exchange adjustments Operating charge relating to defined benefit plans Interest cost Contributions by plan participantsc Benefit payments (funded plans)d Benefit payments (unfunded plans)d Acquisitions Disposals Remeasurements Benefit obligation at 31 Decembera e Movements in fair value of plan assets during the year Fair value of plan assets at 1 January Exchange adjustments Interest income on plan assetsa f Contributions by plan participantsc Contributions by employers (funded plans) Benefit payments (funded plans)d Disposals Remeasurementsf Fair value of plan assets at 31 Decemberg Surplus (deficit) at 31 December Represented by Asset recognized Liability recognized The surplus (deficit) may be analysed between funded and unfunded plans as follows Funded Unfunded The defined benefit obligation may be analysed between funded and unfunded plans as follows Funded Unfunded UK US Eurozone Other $ million 2016 Total 790 1 8 799 264 1,063 (1,471) 1,661 190 4,813 (7,789) 446 34 (2,496) 48,346 (5,947) 799 1,661 26 (2,208) (615) 4 (399) 7,309 48,976 42,138 (5,977) 1,471 26 651 (2,208) (229) 4,813 40,685 (8,291) 584 (8,875) (8,291) 310 (24) – 286 194 480 (287) 417 130 330 (239) 9 (62) 38 10,643 – 286 417 – (821) (284) – – 292 10,533 7,510 – 287 – 10 (821) – 330 7,316 (3,217) – (3,217) (3,217) 76 7 9 92 7 99 (47) 159 112 53 (622) 12 26 (531) 6,640 (282) 92 159 2 (78) (301) 4 – 584 6,820 1,874 (76) 47 2 57 (78) – 53 1,879 (4,941) 22 (4,963) (4,941) 71 1 (1) 71 33 104 (51) 80 29 8 4 (5) 15 22 2,089 23 71 80 6 (117) (24) – (399) (14) 1,715 1,531 15 51 6 45 (117) (229) 8 1,310 (405) 32 (437) (405) 333 17 – 350 30 380 (1,086) 1,005 (81) 4,422 (6,932) 430 55 (2,025) 28,974 (5,688) 350 1,005 18 (1,192) (6) – – 6,447 29,908 31,223 (5,916) 1,086 18 539 (1,192) – 4,422 30,180 272 530 (258) 272 519 (247) 272 (36) (3,181) (3,217) (316) (4,625) (4,941) (83) (322) (405) 84 (8,375) (8,291) (29,661) (247) (29,908) (7,352) (3,181) (10,533) (2,195) (4,625) (6,820) (1,393) (322) (1,715) (40,601) (8,375) (48,976) a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation. b Past service costs have arisen from restructuring programmes and represent a combination of credits as a result of the curtailment in the pension arrangements of a number of employees mostly in the US and charges for special termination benefits representing the increased liability arising as a result of early retirements mostly in the UK and Eurozone. The UK also includes $12 million of cost resulting from benefit harmonization within the primary plan. c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice. d The benefit payments amount shown above comprises $2,754 million benefits and $14 million settlements, plus $55 million of plan expenses incurred in the administration of the benefit. e The benefit obligation for the US is made up of $7,902 million for pension liabilities and $2,631 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical liabilities). The benefit obligation for the Eurozone includes $4,289 million for pension liabilities in Germany which is largely unfunded. f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above. g The fair value of plan assets includes borrowings related to the LDI programme as described on page 159. 160 BP Annual Report and Form 20-F 2016 23. Pensions and other post-retirement benefits – continued Analysis of the amount charged to profit (loss) before interest and taxation Current service costa Past service costb Settlement Operating charge relating to defined benefit plans Payments to defined contribution plans Total operating charge Interest income on plan assetsa Interest on plan liabilities Other finance expense Analysis of the amount recognized in other comprehensive income Actual asset return less interest income on plan assets Change in financial assumptions underlying the present value of the plan liabilities Change in demographic assumptions underlying the present value of the plan liabilities Experience gains and losses arising on the plan liabilities Remeasurements recognized in other comprehensive income Movements in benefit obligation during the year Benefit obligation at 1 January Exchange adjustments Operating charge relating to defined benefit plans Interest cost Contributions by plan participantsc Benefit payments (funded plans)d Benefit payments (unfunded plans)d Acquisitions Reclassified as assets held for sale Remeasurements Benefit obligation at 31 Decembera e Movements in fair value of plan assets during the year Fair value of plan assets at 1 January Exchange adjustments Interest income on plan assetsa f Contributions by plan participantsc Contributions by employers (funded plans) Benefit payments (funded plans)d Acquisitions Remeasurementsf Fair value of plan assets at 31 Decemberg Surplus (deficit) at 31 December Represented by Asset recognized Liability recognized The surplus (deficit) may be analysed between funded and unfunded plans as follows Funded Unfunded The defined benefit obligation may be analysed between funded and unfunded plans as follows Funded Unfunded UK US Eurozone Other 485 12 – 497 31 528 (1,124) 1,146 22 315 2,054 – 336 2,705 32,416 (1,451) 497 1,146 32 (1,269) (7) – – (2,390) 28,974 31,773 (1,506) 1,124 32 754 (1,269) – 315 31,223 2,249 2,516 (267) 2,249 371 (27) – 344 205 549 (289) 423 134 (139) 607 60 (48) 480 11,875 – 344 423 – (1,124) (256) – – (619) 10,643 8,355 – 289 – 129 (1,124) – (139) 7,510 (3,133) 66 (3,199) (3,133) 96 47 (1) 142 8 150 (37) 151 114 25 592 15 47 679 8,327 (843) 142 151 2 (81) (306) – (98) (654) 6,640 1,973 (205) 37 2 123 (81) – 25 1,874 (4,766) 25 (4,791) (4,766) 2,506 (257) 2,249 49 (3,182) (3,133) (254) (4,512) (4,766) 96 (7) (3) 86 41 127 (55) 91 36 33 213 – 29 275 2,638 (294) 86 91 5 (178) (26) 9 – (242) 2,089 1,735 (186) 55 5 60 (178) 7 33 1,531 (558) 40 (598) (558) (187) (371) (558) $ million 2015 Total 1,048 25 (4) 1,069 285 1,354 (1,505) 1,811 306 234 3,466 75 364 4,139 55,256 (2,588) 1,069 1,811 39 (2,652) (595) 9 (98) (3,905) 48,346 43,836 (1,897) 1,505 39 1,066 (2,652) 7 234 42,138 (6,208) 2,647 (8,855) (6,208) 2,114 (8,322) (6,208) (28,717) (257) (28,974) (7,461) (3,182) (10,643) (2,128) (4,512) (6,640) (1,718) (371) (2,089) (40,024) (8,322) (48,346) a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation. b Past service costs have arisen from restructuring programmes and represent a combination of credits as a result of the curtailment in the pension arrangements of a number of employees mostly in the US and Trinidad and charges for special termination benefits representing the increased liability arising as a result of early retirements mostly in the UK and Eurozone. c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice. d The benefit payments amount shown above comprises $3,128 million benefits and $57 million settlements, plus $62 million of plan expenses incurred in the administration of the benefit. e The benefit obligation for the US is made up of $8,061 million for pension liabilities and $2,582 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical liabilities). The benefit obligation for the Eurozone includes $4,151 million for pension liabilities in Germany which is largely unfunded. f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above. g The fair value of plan assets includes borrowings related to the LDI programme as described on page 159. BP Annual Report and Form 20-F 2016 161 i F n a n c a i l s t a t e m e n t s 23. Pensions and other post-retirement benefits – continued Analysis of the amount charged to profit (loss) before interest and taxation Current service costa Past service costb Settlementc Operating charge relating to defined benefit plans Payments to defined contribution plans Total operating charge Interest income on plan assetsa Interest on plan liabilities Other finance expense Analysis of the amount recognized in other comprehensive income Actual asset return less interest income on plan assets Change in financial assumptions underlying the present value of the plan UK US Eurozone Other 494 – – 494 30 524 (1,425) 1,378 (47) 356 (33) (66) 257 214 471 (317) 458 141 72 20 – 92 11 103 (70) 255 185 87 1 – 88 54 142 (80) 115 35 $ million 2014 Total 1,009 (12) (66) 931 309 1,240 (1,892) 2,206 314 1,269 768 119 31 2,187 liabilities (3,188) (1,004) (1,845) (350) (6,387) Change in demographic assumptions underlying the present value of the plan liabilities Experience gains and losses arising on the plan liabilities Remeasurements recognized in other comprehensive income 42 (41) (1,918) (264) 13 (487) (20) (86) (9) (25) (251) (139) (1,832) (353) (4,590) a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation. b Past service costs in the US include a credit of $21 million as the result of a curtailment in the pension arrangement of a number of employees following a business reorganization and a credit of $12 million reflecting a plan amendment to a medical plan. A charge of $21 million for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes mostly in the Eurozone. c Settlements represent a gain of $66 million arising from an offer to a group of plan members in the US to settle annuity liabilities with lump sum payments. At 31 December 2016, reimbursement balances due from or to other companies in respect of pensions amounted to $28 million reimbursement assets (2015 $377 million) and $13 million reimbursement liabilities (2015 $13 million). These balances are not included as part of the pension surpluses and deficits, but are reflected within other receivables and other payables in the group balance sheet. Sensitivity analysis The discount rate, inflation, salary growth and the mortality assumptions all have a significant effect on the amounts reported. A one-percentage point change, in isolation, in certain assumptions as at 31 December 2016 for the group’s plans would have had the effects shown in the table below. The effects shown for the expense in 2017 comprise the total of current service cost and net finance income or expense. Discount ratea Effect on pension and other post-retirement benefit expense in 2017 Effect on pension and other post-retirement benefit obligation at 31 December 2016 Inflation rateb Effect on pension and other post-retirement benefit expense in 2017 Effect on pension and other post-retirement benefit obligation at 31 December 2016 Salary growth Effect on pension and other post-retirement benefit expense in 2017 Effect on pension and other post-retirement benefit obligation at 31 December 2016 $ million One percentage point Decrease Increase (360) (7,515) 308 9,888 279 5,805 104 1,300 (232) (5,048) (91) (1,165) a The amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation. b The amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions. One additional year of longevity in the mortality assumptions would increase the 2017 pension and other post-retirement benefit expense by $55 million and the pension and other post-retirement benefit obligation at 31 December 2016 by $1,558 million. Estimated future benefit payments and the weighted average duration of defined benefit obligations The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2026 and the weighted average duration of the defined benefit obligations at 31 December 2016 are as follows: Estimated future benefit payments 2017 2018 2019 2020 2021 2022-2026 UK 906 949 986 1,005 1,041 5,586 US Eurozone Other 912 889 861 846 848 3,869 341 327 321 309 300 1,420 107 108 111 110 110 561 $ million Total 2,266 2,273 2,279 2,270 2,299 11,436 Years Weighted average duration 20.3 9.9 14.9 13.3 162 BP Annual Report and Form 20-F 2016 24. Cash and cash equivalents Cash Term bank deposits Cash equivalents 2016 5,592 15,947 1,945 23,484 $ million 2015 4,653 16,749 4,987 26,389 Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; term deposits of three months or less with banks and similar institutions; money market funds and commercial paper. The carrying amounts of cash and term bank deposits approximate their fair values. Substantially all of the other cash equivalents are categorized within level 1 of the fair value hierarchy. Cash and cash equivalents at 31 December 2016 includes $2,059 million (2015 $2,439 million) that is restricted. The restricted cash balances include amounts required to cover initial margin on trading exchanges and certain cash balances which are subject to exchange controls. The group holds $3,649 million (2015 $4,329 million) of cash and cash equivalents outside the UK and it is not expected that any significant tax will arise on repatriation. 25. Finance debt Borrowings Net obligations under finance leases Current Non-current 6,592 42 6,634 51,074 592 51,666 2016 Total 57,666 634 58,300 Current Non-current 6,898 46 6,944 45,567 657 46,224 $ million 2015 Total 52,465 703 53,168 The main elements of current borrowings are the current portion of long-term borrowings that is due to be repaid in the next 12 months of $5,587 million (2015 $5,942 million) and issued commercial paper of $971 million (2015 $869 million). Finance debt does not include accrued interest, which is reported within other payables. The following table shows the weighted average interest rates achieved through a combination of borrowings and derivative financial instruments entered into to manage interest rate and currency exposures. Fixed rate debt Floating rate debt Total US dollar Other currencies US dollar Other currencies Weighted average interest rate % Weighted average time for which rate is fixed Years 3 7 3 6 4 16 4 17 Weighted average interest rate % 2 1 1 1 Amount $ million 8,693 809 9,502 10,442 826 11,268 i F n a n c a i l s t a t e m e n t s Amount $ million 47,749 1,049 48,798 40,623 1,277 41,900 Amount $ million 2016 56,442 1,858 58,300 2015 51,065 2,103 53,168 The floating rate debt denominated in other currencies represents euro debt not swapped to US dollars, which is naturally hedged with respect to foreign currency risk by holding equivalent euro cash and cash equivalent amounts. Fair values The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet. Long-term borrowings in the table below include the portion of debt that matures in the 12 months from 31 December 2016, whereas in the balance sheet the amount is reported within current finance debt. The carrying amount of the group’s short-term borrowings, comprising mainly commercial paper, approximates their fair value. The fair values of the majority of the group’s long-term borrowings are determined using quoted prices in active markets, and so fall within level 1 of the fair value hierarchy. Where quoted prices are not available, quoted prices for similar instruments in active markets are used and such measurements are therefore categorized in level 2 of the fair value hierarchy. The fair value of the group’s finance lease obligations is estimated using discounted cash flow analyses based on the group’s current incremental borrowing rates for similar types and maturities of borrowing and are consequently categorized in level 2 of the fair value hierarchy. Short-term borrowings Long-term borrowings Net obligations under finance leases Total finance debt 2016 Carrying amount 1,006 56,660 634 58,300 Fair value 956 51,404 1,178 53,538 Fair value 1,006 57,723 1,097 59,826 $ million 2015 Carrying amount 956 51,509 703 53,168 BP Annual Report and Form 20-F 2016 163 26. Capital disclosures and analysis of changes in net debt The group defines capital as total equity. We maintain our financial framework to support the pursuit of value growth for shareholders, while ensuring a secure financial base. The group monitors capital on the basis of the net debt ratio, that is, the ratio of net debt to net debt plus equity. Net debt is calculated as gross finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. Net debt and net debt ratio are non-GAAP measures. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. All components of equity are included in the denominator of the calculation. We aim to manage the net debt ratio within a 20-30% band while weak market conditions remain and maintain a significant liquidity buffer. At 31 December 2016, the net debt ratio was 26.8% (2015 21.6%). At 31 December Gross debt Less: fair value asset (liability) of hedges related to finance debta Less: cash and cash equivalents Net debt Equity Net debt ratio 2016 58,300 (697) 58,997 23,484 35,513 96,843 26.8% $ million 2015 53,168 (379) 53,547 26,389 27,158 98,387 21.6% a Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $1,962 million (2015 liability of $1,617 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments. An analysis of changes in net debt is provided below. Movement in net debt At 1 January Exchange adjustments Net cash flow Other movements At 31 December Finance debta (53,547) 80 (5,808) 278 Cash and cash equivalents 26,389 (820) (2,085) – 2016 Net debt (27,158) (740) (7,893) 278 Finance debta (52,409) 1,065 (2,220) 17 Cash and cash equivalents 29,763 (672) (2,702) – (58,997) 23,484 (35,513) (53,547) 26,389 $ million 2015 Net debt (22,646) 393 (4,922) 17 (27,158) a Including the fair value of associated derivative financial instruments for which hedge accounting is applied. 27. Operating leases The cost recognized in relation to minimum lease payments for the year was $5,113 million (2015 $6,008 million and 2014 $6,324 million). The future minimum lease payments at 31 December 2016, before deducting related rental income from operating sub-leases of $186 million (2015 $166 million), are shown in the table below. This does not include future contingent rentals. Where the lease rentals are dependent on a variable factor, the future minimum lease payments are based on the factor as at inception of the lease. Future minimum lease payments Payable within 1 year 2 to 5 years Thereafter 2016 3,315 6,651 4,289 $ million 2015 4,144 7,743 3,535 14,255 15,422 In the case of an operating lease entered into by BP as the operator of a joint operation, the amounts included in the totals disclosed represent the net operating lease expense and net future minimum lease payments. These net amounts are after deducting amounts reimbursed, or to be reimbursed, by joint operators, whether the joint operators have co-signed the lease or not. Where BP is not the operator of a joint operation, BP’s share of the lease expense and future minimum lease payments is included in the amounts shown, whether BP has co-signed the lease or not. Typical durations of operating leases are up to forty years for leases of land and buildings, up to fifteen years for leases of ships and commercial vehicles and up to ten years for leases of plant and machinery. The group has entered into a number of structured operating leases for ships and in some cases the lease rental payments vary with market interest rates. The variable portion of the lease payments above or below the amount based on the market interest rate prevailing at inception of the lease is treated as contingent rental expense. The group also routinely enters into bareboat charters, time-charters and voyage-charters for ships on standard industry terms. The most significant items of plant and machinery hired under operating leases are international oil and gas ships managed by the BP Shipping function and drilling rigs used in the Upstream segment. At 31 December 2016, the future minimum lease payments relating to these amounted to $3,582 million (2015 $3,036 million) and $2,969 million (2015 $4,783 million) respectively. 164 BP Annual Report and Form 20-F 2016 27. Operating leases – continued Commercial vehicles hired under operating leases are primarily railcars. Retail service station sites and office accommodation are the main items in the land and buildings category. The terms and conditions of these operating leases do not impose any significant financial restrictions on the group. Some of the leases of ships and buildings allow for renewals at BP’s option, and some of the group’s operating leases contain escalation clauses. 28. Financial instruments and financial risk factors The accounting classification of each category of financial instruments, and their carrying amounts, are set out below. At 31 December 2016 Financial assets Other investments – equity shares – other Loans Trade and other receivables Derivative financial instruments Cash and cash equivalents Financial liabilities Trade and other payables Derivative financial instruments Accruals Finance debt At 31 December 2015 Financial assets Other investments – equity shares – other Loans Trade and other receivables Derivative financial instruments Cash and cash equivalents Financial liabilities Trade and other payables Derivative financial instruments Accruals Finance debt Loans and receivables Note Available- for-sale financial assets Held-to- maturity investments At fair value through profit or loss Derivative hedging instruments Financial liabilities measured at amortized cost $ million Total carrying amount 17 17 19 29 24 21 29 25 17 17 19 29 24 21 29 25 – – 791 20,616 – 21,539 – – – – 407 42 – – – 1,749 – – – – – – – – – 196 – – – 42,946 2,198 196 – – 801 22,214 – 21,402 – – – – 397 219 – – – 2,859 – – – – – – – – – 2,128 – – – – 44,417 3,475 2,128 – 628 – – 6,490 – – (6,507) – – 611 – 605 – – 7,700 – – (6,139) – – 2,166 – – – – 885 – – – – – – – – (1,997) – – (1,112) (49,534) – (5,605) (58,300) (113,439) – – – – 951 – – (1,383) – – (432) – – – – – – (32,094) – (7,151) (53,168) (92,413) 407 670 791 20,616 7,375 23,484 (49,534) (8,504) (5,605) (58,300) (68,600) 397 824 801 22,214 8,651 26,389 (32,094) (7,522) (7,151) (53,168) (40,659) The fair value of finance debt is shown in Note 25. For all other financial instruments, the carrying amount is either the fair value, or approximates the fair value. Financial risk factors The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments including market risks relating to commodity prices, foreign currency exchange rates and interest rates; credit risk; and liquidity risk. The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The GFRC is chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the group finance, tax and the integrated supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk governance framework for the group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to the board, that the group’s financial risk-taking activity is governed by appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with group policies and group risk appetite. The group’s trading activities in the oil, natural gas, LNG and power markets are managed within the integrated supply and trading function, while the activities in the financial markets are managed by the treasury function, working under the compliance and control structure of the integrated supply and trading function. All derivative activity is carried out by specialist teams that have the appropriate skills, experience and supervision. These teams are subject to close financial and management control. The integrated supply and trading function maintains formal governance processes that provide oversight of market risk, credit risk and operational risk associated with trading activity. A policy and risk committee monitors and validates limits and risk exposures, reviews incidents and validates risk-related policies, methodologies and procedures. A commitments committee approves value-at-risk delegations, the trading of new products, instruments and strategies and material commitments. In addition, the integrated supply and trading function undertakes derivative activity for risk management purposes under a control framework as described more fully below. BP Annual Report and Form 20-F 2016 165 i F n a n c a i l s t a t e m e n t s 28. Financial instruments and financial risk factors – continued (a) Market risk Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The primary commodity price risks that the group is exposed to include oil, natural gas and power prices that could adversely affect the value of the group’s financial assets, liabilities or expected future cash flows. The group enters into derivatives in a well-established entrepreneurial trading operation. In addition, the group has developed a control framework aimed at managing the volatility inherent in certain of its natural business exposures. In accordance with the control framework the group enters into various transactions using derivatives for risk management purposes. The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed below. (i) Commodity price risk The group’s integrated supply and trading function uses conventional financial and commodity instruments and physical cargoes and pipeline positions available in the related commodity markets. Oil and natural gas swaps, options and futures are used to mitigate price risk. Power trading is undertaken using a combination of over-the-counter forward contracts and other derivative contracts, including options and futures. This activity is on both a standalone basis and in conjunction with gas derivatives in relation to gas-generated power margin. In addition, NGLs are traded around certain US inventory locations using over-the-counter forward contracts in conjunction with over-the-counter swaps, options and physical inventories. The group measures market risk exposure arising from its trading positions in liquid periods using value-at-risk techniques. These techniques make a statistical assessment of the market risk arising from possible future changes in market prices over a one-day holding period. The value- at-risk measure is supplemented by stress testing. Trading activity occurring in liquid periods is subject to value-at-risk limits for each trading activity and for this trading activity in total. The board has delegated a limit of $100 million value at risk in support of this trading activity. Alternative measures are used to monitor exposures which are outside liquid periods and which cannot be actively risk-managed. (ii) Foreign currency exchange risk Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading value-at-risk techniques as explained above. Since BP has global operations, fluctuations in foreign currency exchange rates can have a significant effect on the group’s reported results. The effects of most exchange rate fluctuations are absorbed in business operating results through changing cost competitiveness, lags in market adjustment to movements in rates and translation differences accounted for on specific transactions. For this reason, the total effect of exchange rate fluctuations is not identifiable separately in the group’s reported results. The main underlying economic currency of the group’s cash flows is the US dollar. This is because BP’s major product, oil, is priced internationally in US dollars. BP’s foreign currency exchange management policy is to limit economic and material transactional exposures arising from currency movements against the US dollar. The group co-ordinates the handling of foreign currency exchange risks centrally, by netting off naturally-occurring opposite exposures wherever possible and then managing any material residual foreign currency exchange risks. The group manages these exposures by constantly reviewing the foreign currency economic value at risk and aims to manage such risk to keep the 12-month foreign currency value at risk below $400 million. At no point over the past three years did the value at risk exceed the maximum risk limit. The most significant exposures relate to capital expenditure commitments and other UK, Eurozone and Australian operational requirements, for which hedging programmes are in place and hedge accounting is applied as outlined in Note 1. For highly probable forecast capital expenditures the group fixes the US dollar cost of non-US dollar supplies by using currency forwards. The exposures are sterling, euro, Australian dollar and Norwegian krone. At 31 December 2016 the most significant open contracts in place were for $1,204 million sterling (2015 $627 million sterling). For other UK, Eurozone and Australian operational requirements the group uses cylinders (purchased call and sold put options) to manage the estimated exposures on a 12-month rolling basis. At 31 December 2016, the open positions relating to cylinders consisted of receive sterling, pay US dollar cylinders for $1,885 million (2015 $2,479 million); receive euro, pay US dollar cylinders for $585 million (2015 $560 million); receive Australian dollar, pay US dollar cylinders for $274 million (2015 $312 million). In addition, most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2016, the total foreign currency borrowings not swapped into US dollars net of those hedged with cash in the same currency expected to be held until the maturity of those borrowings amounted to $809 million (2015 $826 million). (iii) Interest rate risk Where the group enters into money market contracts for entrepreneurial trading purposes the activity is controlled using value-at-risk techniques as described above. BP is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial instruments, principally finance debt. While the group issues debt in a variety of currencies based on market opportunities, it uses derivatives to swap the debt to a floating rate exposure, mainly to US dollar floating, but in certain defined circumstances maintains a US dollar fixed rate exposure for a proportion of debt. The proportion of floating rate debt net of interest rate swaps at 31 December 2016 was 84% of total finance debt outstanding (2015 79%). The weighted average interest rate on finance debt at 31 December 2016 was 2% (2015 2%) and the weighted average maturity of fixed rate debt was five years (2015 five years). The group’s earnings are sensitive to changes in interest rates on the floating rate element of the group’s finance debt. If the interest rates applicable to floating rate instruments were to have increased by one percentage point on 1 January 2017, it is estimated that the group’s finance costs for 2017 would increase by approximately $488 million (2015 $419 million increase). (b) Credit risk Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss to the group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally from credit exposures to customers relating to outstanding receivables. Credit exposure also exists in relation to guarantees issued by group companies under which the outstanding exposure incremental to that recognized on the balance sheet at 31 December 2016 was $309 million (2015 $35 million) in respect of liabilities of joint ventures and associates and $370 million (2015 $163 million) in respect of liabilities of other third parties. 166 BP Annual Report and Form 20-F 2016 28. Financial instruments and financial risk factors – continued The group has a credit policy, approved by the CFO that is designed to ensure that consistent processes are in place throughout the group to measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business contract the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy include segregation of credit approval authorities from any sales, marketing or trading teams authorized to incur credit risk; the establishment of credit systems and processes to ensure that all counterparty exposure is rated and that all counterparty exposure and limits can be monitored and reported; and the timely identification and reporting of any non-approved credit exposures and credit losses. While each segment is responsible for its own credit risk management and reporting consistent with group policy, the treasury function holds group-wide credit risk authority and oversight responsibility for exposure to banks and financial institutions. The maximum credit exposure associated with financial assets is equal to the carrying amount. The group does not aim to remove credit risk entirely but expects to experience a certain level of credit losses. As at 31 December 2016, the group had in place credit enhancements designed to mitigate approximately $11.6 billion of credit risk (2015 $10.9 billion). Reports are regularly prepared and presented to the GFRC that cover the group’s overall credit exposure and expected loss trends, exposure by segment, and overall quality of the portfolio. Management information used to monitor credit risk indicates that 79% (2015 81%) of total unmitigated credit exposure relates to counterparties of investment-grade credit quality. Trade and other receivables at 31 December Neither impaired nor past due Impaired (net of provision) Not impaired and past due in the following periods within 30 days 31 to 60 days 61 to 90 days over 90 days 2016 19,459 71 446 116 56 468 $ million 2015 21,064 22 414 75 118 521 20,616 22,214 Movements in the impairment provision for trade receivables are shown in Note 20. Financial instruments subject to offsetting, enforceable master netting arrangements and similar agreements The following table shows the amounts recognized for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the balance sheet. Amounts which cannot be offset under IFRS, but which could be settled net under the terms of master netting agreements if certain conditions arise, and collateral received or pledged, are also presented in the table to show the total net exposure of the group. At 31 December 2016 Derivative assets Derivative liabilities Trade and other receivables Trade and other payables At 31 December 2015 Derivative assets Derivative liabilities Trade and other receivables Trade and other payables Gross amounts of recognized financial assets (liabilities) 9,025 (10,236) 8,815 (9,664) 10,206 (9,280) 7,091 (5,720) Amounts set off (1,882) 1,882 (4,468) 4,468 (1,859) 1,859 (3,689) 3,689 Related amounts not set off in the balance sheet Net amounts presented on the balance sheet Master netting arrangements Cash collateral (received) pledged 7,143 (8,354) 4,347 (5,196) 8,347 (7,421) 3,402 (2,031) (1,058) 1,058 (1,039) 1,039 (1,109) 1,109 (322) 322 (133) – (118) – (297) – (161) – $ million Net amount 5,952 (7,296) 3,190 (4,157) 6,941 (6,312) 2,919 (1,709) (c) Liquidity risk Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is managed centrally with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local regulations, generally subsidiaries pool their cash surpluses to the treasury function, which will then arrange to fund other subsidiaries’ requirements, or invest any net surplus in the market or arrange for necessary external borrowings, while managing the group’s overall net currency positions. Standard & Poor’s Ratings long-term credit rating for BP is A negative (stable outlook) and Moody’s Investors Service rating is A2 (positive outlook). During 2016, $12 billion of long-term taxable bonds were issued with terms ranging from three to twelve years. Commercial paper is issued at competitive rates to meet short-term borrowing requirements as and when needed. As a further liquidity measure, the group continues to maintain suitable levels of cash and cash equivalents, amounting to $23.5 billion at 31 December 2016 (2015 $26.4 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate and short notice. At 31 December 2016, the group had substantial amounts of undrawn borrowing facilities available, consisting of $7,375 million of standby facilities, of which $6,975 million is available to draw and repay until the first half of 2018, and $400 million is available to draw and repay until April 2017. These facilities are with 26 international banks, and borrowings under them would be at pre-agreed rates. The group also has committed letter of credit (LC) facilities totalling $6,750 million with a number of banks, allowing LCs to be issued for a maximum two-year duration. There were also uncommitted secured LC facilities in place at 31 December 2016 for $2,410 million, which are secured against inventories or receivables when utilized. The facilities only terminate by either party giving a stipulated termination notice to the other. BP Annual Report and Form 20-F 2016 167 i F n a n c a i l s t a t e m e n t s 28. Financial instruments and financial risk factors – continued The amounts shown for finance debt in the table below include future minimum lease payments with respect to finance leases. The table also shows the timing of cash outflows relating to trade and other payables and accruals. Within one year 1 to 2 years 2 to 3 years 3 to 4 years 4 to 5 years 5 to 10 years Over 10 years Trade and other payablesa 35,774 2,005 1,278 1,239 1,229 5,826 7,248 54,599 Accruals 5,136 186 91 53 33 75 31 5,605 Finance debt 6,634 5,973 6,734 6,301 6,780 22,378 3,500 58,300 2016 Interest 1,217 1,083 942 801 658 1,843 816 7,360 Trade and other payablesa 29,743 971 1,231 56 17 38 38 32,094 Accruals 6,261 380 138 98 74 167 33 7,151 Finance debt 6,944 5,796 6,208 6,103 6,354 17,651 4,112 53,168 $ million 2015 Interest 928 812 704 592 478 1,068 402 4,984 a 2016 includes $21,644 million and 2015 includes $2,750 million in relation to Gulf of Mexico oil spill. The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected maturities of both derivative assets and liabilities as indicated in Note 29. Management does not currently anticipate any cash flows that could be of a significantly different amount, or could occur earlier than the expected maturity analysis provided. The table below shows the timing of cash outflows for derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt, whether or not hedge accounting is applied, based upon contractual payment dates. The amounts reflect the gross settlement amount where the pay leg of a derivative will be settled separately from the receive leg, as in the case of cross-currency swaps hedging non-US dollar finance debt. The swaps are with high investment-grade counterparties and therefore the settlement-day risk exposure is considered to be negligible. Not shown in the table are the gross settlement amounts (inflows) for the receive leg of derivatives that are settled separately from the pay leg, which amount to $18,014 million at 31 December 2016 (2015 $15,706 million) to be received on the same day as the related cash outflows. For further information on our derivative financial instruments, see Note 29. Cash outflows for derivative financial instruments at 31 December Within one year 1 to 2 years 2 to 3 years 3 to 4 years 4 to 5 years 5 to 10 years Over 10 years 2016 2,677 1,505 1,700 1,678 2,384 9,985 1,413 $ million 2015 2,959 2,685 1,505 1,700 1,678 5,500 2,739 21,342 18,766 29. Derivative financial instruments In the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate debt, consistent with risk management policies and objectives. An outline of the group’s financial risks and the objectives and policies pursued in relation to those risks is set out in Note 28. Additionally, the group has a well-established entrepreneurial trading operation that is undertaken in conjunction with these activities using a similar range of contracts. For information on significant estimates and judgements made in relation to the application of hedge accounting and the valuation of derivatives see Derivative financial instruments within Note 1. The fair values of derivative financial instruments at 31 December are set out below. Exchange traded derivatives are valued using closing prices provided by the exchange as at the balance sheet date. These derivatives are categorized within level 1 of the fair value hierarchy. Over-the-counter (OTC) financial swaps and physical commodity sale and purchase contracts are generally valued using readily available information in the public markets and quotations provided by brokers and price index developers. These quotes are corroborated with market data and are categorized within level 2 of the fair value hierarchy. In certain less liquid markets, or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC financial swaps and physical commodity sale and purchase contracts are valued using internally developed methodologies that consider historical relationships between various commodities, and that result in management’s best estimate of fair value. These contracts are categorized within level 3 of the fair value hierarchy. 168 BP Annual Report and Form 20-F 2016 29. Derivative financial instruments – continued Financial OTC and physical commodity options are valued using industry standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic factors. The degree to which these inputs are observable in the forward markets determines whether the option is categorized within level 2 or level 3 of the fair value hierarchy. Derivatives held for trading Currency derivatives Oil price derivatives Natural gas price derivatives Power price derivatives Other derivatives Embedded derivatives Commodity price contracts Other embedded derivatives Cash flow hedges Currency forwards, futures and cylinders Cross-currency interest rate swaps Fair value hedges Currency forwards, futures and swaps Interest rate swaps Of which – current – non-current Fair value asset 2016 Fair value liability 167 1,543 3,780 768 232 6,490 – – – 32 – 32 22 831 853 7,375 3,016 4,359 (2,000) (952) (2,845) (560) – (6,357) (50) (100) (150) (451) (154) (605) (1,159) (233) (1,392) (8,504) (2,991) (5,513) Fair value asset 144 2,390 3,942 920 292 7,688 12 – 12 9 – 9 33 909 942 8,651 4,242 4,409 $ million 2015 Fair value liability (1,811) (1,257) (2,536) (434) – (6,038) (101) – (101) (71) (147) (218) (1,108) (57) (1,165) (7,522) (3,239) (4,283) i F n a n c a i l Derivatives held for trading The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective, and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of contract types in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of these exposures is monitored using market value-at-risk techniques as described in Note 28. The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes. Derivative assets held for trading have the following fair values and maturities. s t a t e m e n t s Currency derivatives Oil price derivatives Natural gas price derivatives Power price derivatives Other derivatives Currency derivatives Oil price derivatives Natural gas price derivatives Power price derivatives Other derivatives Less than 1 year 102 1,178 1,238 305 132 2,955 Less than 1 year 132 1,729 1,707 459 182 4,209 1-2 years 2-3 years 3-4 years 4-5 years 34 201 647 164 – 1,046 20 91 424 114 – 649 2 49 313 58 – 422 7 22 267 53 – 349 1-2 years 2-3 years 3-4 years 4-5 years 10 432 639 164 110 1,355 1 130 390 103 – 624 1 58 283 79 – 421 – 37 202 47 – 286 $ million 2016 Total 167 1,543 3,780 768 232 6,490 $ million 2015 Total 144 2,390 3,942 920 292 7,688 Over 5 years 2 2 891 74 100 1,069 Over 5 years – 4 721 68 – 793 At 31 December 2016 and 2015 the group had contingent consideration receivable in respect of the disposal of the Texas City refinery. The sale agreement contained an embedded derivative – the whole agreement has, consequently, been designated at fair value through profit or loss and shown within other derivatives held for trading, and falls within level 3 of the fair value hierarchy. The valuation depends on refinery throughput and future margins. BP Annual Report and Form 20-F 2016 169 29. Derivative financial instruments – continued Derivative liabilities held for trading have the following fair values and maturities. Currency derivatives Oil price derivatives Natural gas price derivatives Power price derivatives Currency derivatives Oil price derivatives Natural gas price derivatives Power price derivatives Less than 1 year (379) (787) (947) (201) (2,314) Less than 1 year (499) (1,053) (1,037) (246) (2,835) 1-2 years 2-3 years 3-4 years 4-5 years (36) (105) (421) (126) (688) (402) (40) (257) (81) (780) (101) (11) (258) (39) (409) (338) (3) (197) (31) (569) 1-2 years 2-3 years 3-4 years 4-5 years (2) (163) (382) (70) (617) (2) (26) (210) (31) (269) (347) (10) (146) (34) (537) (79) (2) (162) (17) (260) Over 5 years (744) (6) (765) (82) (1,597) Over 5 years (882) (3) (599) (36) (1,520) The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by methodology of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty. Less than 1 year 3,962 448 4,410 (1,455) 2,955 (3,610) (159) (3,769) 1,455 (2,314) 641 Less than 1 year 109 4,946 684 5,739 (1,530) 4,209 (104) (4,083) (178) (4,365) 1,530 (2,835) 1,374 1-2 years 2-3 years 3-4 years 4-5 years 1,035 265 1,300 (254) 1,046 (778) (164) (942) 254 (688) 358 509 249 758 (109) 649 (701) (188) (889) 109 (780) (131) 208 243 451 (29) 422 (249) (189) (438) 29 (409) 13 117 241 358 (9) 349 (401) (177) (578) 9 (569) (220) 1-2 years 2-3 years 3-4 years 4-5 years – 1,137 449 1,586 (231) 1,355 – (700) (148) (848) 231 (617) 738 – 402 271 673 (49) 624 – (177) (141) (318) 49 (269) 355 – 213 240 453 (32) 421 – (423) (146) (569) 32 (537) (116) – 68 230 298 (12) 286 – (124) (148) (272) 12 (260) 26 Over 5 years 189 906 1,095 (26) 1,069 (872) (751) (1,623) 26 (1,597) (528) Over 5 years – 50 748 798 (5) 793 – (889) (636) (1,525) 5 (1,520) (727) Fair value of derivative assets Level 2 Level 3 Less: netting by counterparty Fair value of derivative liabilities Level 2 Level 3 Less: netting by counterparty Net fair value Fair value of derivative assets Level 1 Level 2 Level 3 Less: netting by counterparty Fair value of derivative liabilities Level 1 Level 2 Level 3 Less: netting by counterparty Net fair value 170 BP Annual Report and Form 20-F 2016 $ million 2016 Total (2,000) (952) (2,845) (560) (6,357) $ million 2015 Total (1,811) (1,257) (2,536) (434) (6,038) $ million 2016 Total 6,020 2,352 8,372 (1,882) 6,490 (6,611) (1,628) (8,239) 1,882 (6,357) 133 $ million 2015 Total 109 6,816 2,622 9,547 (1,859) 7,688 (104) (6,396) (1,397) (7,897) 1,859 (6,038) 1,650 29. Derivative financial instruments – continued Level 3 derivatives The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair value hierarchy. Fair value of contracts at 1 January 2016 Gains (losses) recognized in the income statement Settlements Transfers out of level 3 Net fair value of contracts at 31 December 2016 Deferred day-one gains (losses) Derivative asset (liability) Fair value of contracts at 1 January 2015 Gains (losses) recognized in the income statement Settlements Transfers out of level 3 Net fair value of contracts at 31 December 2015 Deferred day-one gains (losses) Derivative asset (liability) Oil price 169 (37) (63) (1) 68 Oil price 146 44 (20) (1) 169 Natural gas price 214 1 (51) (19) 145 Natural gas price 74 288 (40) (108) 214 Power price 91 (82) (145) (11) (147) Power price 109 76 (72) (22) 91 Other 292 139 (200) – 231 Other 389 92 (189) – 292 $ million Total 766 21 (459) (31) 297 427 724 $ million Total 718 500 (321) (131) 766 459 1,225 The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2016 was a $253-million loss (2015 $293-million gain related to derivatives still held at 31 December 2015). Derivative gains and losses Gains and losses relating to derivative contracts are included within sales and other operating revenues in the income statement depending upon the nature of the activity and type of contract involved. The contract types treated in this way include futures, options, swaps and certain forward sales and forward purchases contracts, and relate to both currency and commodity trading activities. Gains or losses arise on contracts entered into for risk management purposes, optimization activity and entrepreneurial trading. They also arise on certain contracts that are for normal procurement or sales activity for the group but that are required to be fair valued under accounting standards. Also included within sales and other operating revenues are gains and losses on inventory held for trading purposes. The total amount relating to all these items (excluding gains and losses on realized physical derivative contracts that have been reflected gross in the income statement within sales and purchases) was a net gain of $1,435 million (2015 $5,508 million net gain and 2014 $6,154 million net gain). This number does not include gains and losses on realized physical derivative contracts that have been reflected gross in the income statement within sales and purchases or the change in value of transportation and storage contracts which are not recognized under IFRS, but does include the associated financially settled contracts. The net amount for actual gains and losses relating to derivative contracts and all related items therefore differs significantly from the amount disclosed above. Embedded derivatives The group has embedded derivatives relating to certain natural gas contracts. The fair value gain on commodity price embedded derivatives included within distribution and administration expenses was a gain of $32 million (2015 gain of $120 million, 2014 gain of $430 million). Cash flow hedges At 31 December 2016, the group held currency forwards, futures contracts and cylinders and cross-currency interest rate swaps that were being used to hedge the foreign currency risk of highly probable forecast transactions and floating rate finance debt. Note 28 outlines the group’s approach to foreign currency exchange risk management. For cash flow hedges the group only claims hedge accounting for the intrinsic value on the currency with any fair value attributable to time value taken immediately to the income statement. The amounts remaining in equity at 31 December 2016 in relation to these cash flow hedges consist of deferred losses of $343 million maturing in 2017, deferred losses of $71 million maturing in 2018 and deferred losses of $22 million maturing in 2019 and beyond. Fair value hedges At 31 December 2016, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk on fixed rate debt issued by the group. The loss on the hedging derivative instruments recognized in the income statement in 2016 was $316 million (2015 $788 million loss and 2014 $14 million loss) offset by a gain on the fair value of the finance debt of $270 million (2015 $833 million gain and 2014 $8 million gain). The interest rate and cross-currency interest rate swaps mature within one to twelve years, and have the same maturity terms as the debt that they are hedging. They are used to convert sterling, euro, Swiss franc, Australian dollar, Canadian dollar, Norwegian krone and Hong Kong dollar denominated fixed rate borrowings into floating rate debt. Note 28 outlines the group’s approach to interest rate and foreign currency exchange risk management. BP Annual Report and Form 20-F 2016 171 i F n a n c a i l s t a t e m e n t s 30. Called-up share capital The allotted, called up and fully paid share capital at 31 December was as follows: Issued 8% cumulative first preference shares of £1 eacha 9% cumulative second preference shares of £1 eacha Ordinary shares of 25 cents each At 1 January Issue of new shares for the scrip dividend programme Issue of new shares for employee share-based payment plansb Issue of new shares – otherc Repurchase of ordinary share capitald At 31 December Shares thousand 7,233 5,473 2016 $ million 12 9 21 Shares thousand 7,233 5,473 2015 $ million 12 9 21 Shares thousand 7,233 5,473 20,108,771 548,005 5,028 137 20,005,961 102,810 5,002 26 20,426,632 165,644 – 392,920 – 21,049,696 – – – 20,108,771 – 98 – 5,263 5,284 – – – 5,028 5,049 25,598 – (611,913) 20,005,961 2014 $ million 12 9 21 5,108 41 6 – (153) 5,002 5,023 a The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of preference shares. b Consideration received relating to the issue of new shares for employee share-based payment plans amounted to $207 million in 2014. c Relates to the issue of new ordinary shares in consideration for a 10% interest in the Abu Dhabi onshore oil concession. See Note 31 for further information. d In 2014 shares were repurchased for a total consideration of $4,796 million, including transaction costs of $26 million. All shares purchased were for cancellation. Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each. In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value. Treasury sharesa At 1 January Purchases for settlement of employee share plans Shares re-issued for employee share-based payment plans At 31 December Of which – shares held in treasury by BP – shares held in ESOP trusts – shares held by BP’s US share plan administratorb 2016 2015 2014 Shares thousand Nominal value $ million Shares thousand Nominal value $ million Shares thousand Nominal value $ million 1,756,327 9,631 (151,339) 1,614,619 1,576,411 21,432 16,814 439 1,811,297 51,142 (106,112) 2 (38) 453 1,833,544 49,559 (71,806) 13 (27) 403 1,756,327 439 1,811,297 394 1,727,763 18,453 10,111 5 4 432 1,771,103 34,169 6,025 4 3 458 12 (17) 453 443 9 1 a See Note 31 for definition of treasury shares. b Held in the form of ADSs to meet the requirements of employee share-based payment plans in the US. For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by BP during the year, representing 8.6% (2015 8.9% and 2014 8.8%) of the called-up ordinary share capital of the company. During 2016, the movement in shares held in treasury by BP represented less than 0.8% (2015 less than 0.2% and 2014 less than 0.1%) of the ordinary share capital of the company. 172 BP Annual Report and Form 20-F 2016 i F n a n c a i l THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY s t a t e m e n t s BP Annual Report and Form 20-F 2016 173 31. Capital and reserves At 1 January 2016 Profit (loss) for the year Items that may be reclassified subsequently to profit or loss Currency translation differences (including recycling) Available-for-sale investments (including recycling) Cash flow hedges (including recycling) Share of items relating to equity-accounted entities, net of taxa Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Total comprehensive income Dividends Share-based payments, net of taxb c Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests At 31 December 2016 At 1 January 2015 Profit (loss) for the year Items that may be reclassified subsequently to profit or loss Currency translation differences (including recycling)a Available-for-sale investments (including recycling) Cash flow hedges (including recycling) Share of items relating to equity-accounted entities, net of taxa Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Share of items relating to equity-accounted entities, net of tax Total comprehensive income Dividends Share-based payments, net of taxc Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests At 31 December 2015 At 1 January 2014 Profit (loss) for the year Items that may be reclassified subsequently to profit or loss Currency translation differences (including recycling)a Cash flow hedges (including recycling) Share of items relating to equity-accounted entities, net of taxa Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Share of items relating to equity-accounted entities, net of tax Total comprehensive income Dividends Repurchases of ordinary share capital Share-based payments, net of taxd Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests At 31 December 2014 Share capital 5,049 – Share premium account 10,234 – Capital redemption reserve 1,413 – Total share capital and capital reserves 43,902 – Merger reserve 27,206 – – – – – – – – 137 98 – – 5,284 Share capital 5,023 – – – – – – – – – 26 – – – 5,049 Share capital 5,129 – – – – – – – – 41 (153) 6 – – 5,023 – – – – – – – (137) 2,122 – – 12,219 – – – – – – – – – – – 1,413 Share premium account 10,260 – Capital redemption reserve 1,413 – – – – – – – – – (26) – – – 10,234 – – – – – – – – – – – – 1,413 Share premium account 10,061 – Capital redemption reserve 1,260 – – – – – – – – (41) – 240 – – 10,260 – – – – – – – – 153 – – – 1,413 – – – – – – – – – – – 27,206 Merger reserve 27,206 – – – – – – – – – – – – – 27,206 Merger reserve 27,206 – – – – – – – – – – – – – 27,206 – – – – – – – – 2,220 – – 46,122 Total share capital and capital reserves 43,902 – – – – – – – – – – – – – 43,902 Total share capital and capital reserves 43,656 – – – – – – – – – – 246 – – 43,902 a Principally foreign exchange effects relating to the Russian rouble. b Includes ordinary shares issued to the government of Abu Dhabi in consideration for a 10% interest in the Abu Dhabi onshore oil concession. The share-based payment transaction was valued at the fair value of the interest in the assets, with reference to a market transaction for an identical interest. c Movements in treasury shares relate to employee share-based payment plans. d New share issues and movements in treasury shares relate to employee share-based payment plans. 174 BP Annual Report and Form 20-F 2016 Treasury shares (19,964) – – – – – – – – – 1,521 – – (18,443) Treasury shares (20,719) – – – – – – – – – – 755 – – (19,964) Treasury shares (20,971) – – – – – – – – – – 252 – – (20,719) Foreign currency translation reserve (7,267) – Available- for-sale investments 2 – Cash flow hedges (825) – – – (331) – – – (331) – – – – (1,156) Cash flow hedges (898) – – – 73 – – – – 73 – – – – (825) Total fair value reserves (823) – – 1 (331) – – – (330) – – – – (1,153) Total fair value reserves (897) – – 1 73 – – – – 74 – – – – (823) Profit and loss account 81,368 115 BP shareholders’ equity 97,216 115 Non- controlling interests 1,171 57 – – – 833 (96) (1,757) (905) (4,611) (750) 106 430 75,638 389 1 (331) 833 (96) (1,757) (846) (4,611) 2,991 106 430 95,286 (27) – – – – – 30 (107) – – 463 1,557 Profit and loss account 92,564 (6,482) BP shareholders’ equity 111,441 (6,482) Non- controlling interests 1,201 82 – – – (814) 80 2,742 (1) (4,475) (6,659) (99) 40 (3) 81,368 (3,858) 1 73 (814) 80 2,742 (1) (8,259) (6,659) 656 40 (3) 97,216 (41) – – – – – – 41 (91) – – 20 1,171 – 1 – – – – 1 – – – – 3 Available- for-sale investments 1 – – 1 – – – – – 1 – – – – 2 Available- for-sale investments – – Cash flow hedges (695) – Total fair value reserves (695) – Profit and loss account 103,787 3,780 BP shareholders’ equity 129,302 3,780 Non- controlling interests 1,105 223 1 – – – – – 1 – – – – – 1 – (203) – – – – (203) – – – – – (898) 1 (203) – – – – (202) – – – – – (897) – – (2,584) 289 (3,256) 4 (1,767) (5,850) (3,366) (313) 73 – 92,564 (6,933) (203) (2,584) 289 (3,256) 4 (8,903) (5,850) (3,366) 185 73 – 111,441 (32) – – – – – 191 (255) – – – 160 1,201 389 – – – – – 389 – – – – (6,878) Foreign currency translation reserve (3,409) – (3,858) – – – – – – (3,858) – – – – (7,267) Foreign currency translation reserve 3,525 – (6,934) – – – – – (6,934) – – – – – (3,409) $ million Total equity 98,387 172 362 1 (331) 833 (96) (1,757) (816) (4,718) 2,991 106 893 96,843 Total equity 112,642 (6,400) (3,899) 1 73 (814) 80 2,742 (1) (8,218) (6,750) 656 40 17 98,387 Total equity 130,407 4,003 (6,965) (203) (2,584) 289 (3,256) 4 (8,712) (6,105) (3,366) 185 73 160 112,642 i F n a n c a i l s t a t e m e n t s BP Annual Report and Form 20-F 2016 175 31. Capital and reserves – continued Share capital The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury shares. Share premium account The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares. Capital redemption reserve The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled. Merger reserve The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in an acquisition made by the issue of shares. Treasury shares Treasury shares represent BP shares repurchased and available for specific and limited purposes. For accounting purposes shares held in Employee Share Ownership Plans (ESOPs) and BP’s US share plan administrator to meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are, therefore, included in the financial statements as treasury shares. The ESOPs are funded by the group and have waived their rights to dividends in respect of such shares held for future awards. Until such time as the shares held by the ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders’ equity. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group. Foreign currency translation reserve The foreign currency translation reserve records exchange differences arising from the translation of the financial statements of foreign operations. Upon disposal of foreign operations, the related accumulated exchange differences are recycled to the income statement. Available-for-sale investments This reserve records the changes in fair value of available-for-sale investments except for impairment losses, foreign exchange gains or losses, or changes arising from revised estimates of future cash flows. On disposal or impairment of the investments, the cumulative changes in fair value are recycled to the income statement. Cash flow hedges This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. It includes $651 million relating to the acquisition of an 18.5% interest in Rosneft in 2013 which will only be reclassified to the income statement if the investment in Rosneft is either sold or impaired. For further information on the accounting for cash flow hedges see Note 1 - Derivative financial instruments and hedging activities. Profit and loss account The balance held on this reserve is the accumulated retained profits of the group. 176 BP Annual Report and Form 20-F 2016 31. Capital and reserves – continued The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below. Items that may be reclassified subsequently to profit or loss Currency translation differences (including recycling) Available-for-sale investments (including recycling) Cash flow hedges (including recycling) Share of items relating to equity-accounted entities, net of tax Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Other comprehensive income Items that may be reclassified subsequently to profit or loss Currency translation differences (including recycling) Available-for-sale investments (including recycling) Cash flow hedges (including recycling) Share of items relating to equity-accounted entities, net of tax Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Share of items relating to equity-accounted entities, net of tax Other comprehensive income Items that may be reclassified subsequently to profit or loss Currency translation differences (including recycling) Cash flow hedges (including recycling) Share of items relating to equity-accounted entities, net of tax Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Share of items relating to equity-accounted entities, net of tax Other comprehensive income 32. Contingent liabilities $ million 2016 Pre-tax Tax Net of tax 284 1 (362) 833 – (2,496) (1,740) 78 – 31 – (96) 739 752 362 1 (331) 833 (96) (1,757) (988) $ million 2015 Pre-tax Tax Net of tax (4,096) 1 93 (814) – 4,139 (1) (678) 197 – (20) – 80 (1,397) – (1,140) (3,899) 1 73 (814) 80 2,742 (1) (1,818) $ million 2014 Pre-tax Tax Net of tax (6,787) (239) (2,584) – (4,590) 4 (14,196) (178) 36 – 289 (6,965) (203) (2,584) 289 1,334 – 1,481 (3,256) 4 (12,715) Contingent liabilities related to the Gulf of Mexico oil spill See Note 2 for information on contingent liabilities related to the Gulf of Mexico oil spill. Contingent liabilities not related to the Gulf of Mexico oil spill There were contingent liabilities at 31 December 2016 in respect of guarantees and indemnities entered into as part of the ordinary course of the group’s business. No material losses are likely to arise from such contingent liabilities. Further information on financial guarantees is included in Note 28. In the normal course of the group’s business, legal proceedings are pending or may be brought against BP group entities arising out of current and past operations, including matters related to commercial disputes, product liability, antitrust, commodities trading, premises-liability claims, consumer protection, general environmental claims and allegations of exposures of third parties to toxic substances, such as lead pigment in paint, asbestos and other chemicals. BP believes that the impact of these legal proceedings on the group‘s results of operations, liquidity or financial position will not be material. With respect to lead pigment in paint in particular, Atlantic Richfield, a subsidiary of BP, has been named as a co-defendant in numerous lawsuits brought in the US alleging injury to persons and property. Although it is not possible to predict the outcome of the legal proceedings, Atlantic Richfield believes it has valid defences that render the incurrence of a liability remote; however, the amounts claimed and the costs of implementing the remedies sought in the various cases could be substantial. The majority of the lawsuits have been abandoned or dismissed against Atlantic Richfield. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgment in any proceeding. Atlantic Richfield intends to defend such actions vigorously. The group files tax returns in many jurisdictions throughout the world. Various tax authorities are currently examining the group’s tax returns. Tax returns contain matters that could be subject to differing interpretations of applicable tax laws and regulations and the resolution of tax positions through negotiations with relevant tax authorities, or through litigation, can take several years to complete. While it is difficult to predict the ultimate outcome in some cases, the group does not anticipate that there will be any material impact upon the group‘s results of operations, financial position or liquidity. BP Annual Report and Form 20-F 2016 177 i F n a n c a i l s t a t e m e n t s 32. Contingent liabilities – continued The group is subject to numerous national and local environmental laws and regulations concerning its products, operations and other activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of prior disposal or release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites including refineries, chemical plants, oil fields, service stations, terminals and waste disposal sites. In addition, the group may have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its cost are inherently difficult to estimate. However, the estimated cost of known environmental obligations has been provided in these accounts in accordance with the group‘s accounting policies. While the amounts of future costs that are not provided for could be significant and could be material to the group‘s results of operations in the period in which they are recognized, it is not possible to estimate the amounts involved. BP does not expect these costs to have a material effect on the group’s financial position or liquidity. If oil and natural gas production facilities and pipelines are sold to third parties and the subsequent owner is unable to meet their decommissioning obligations it is possible that, in certain circumstances, BP could be partially or wholly responsible for decommissioning. BP is not currently aware of any such cases that have a greater than remote chance of reverting to the Group. Furthermore, as described in Provisions and contingencies within Note 1, decommissioning provisions associated with downstream and petrochemical facilities are not generally recognized as the potential obligations cannot be measured given their indeterminate settlement dates. 33. Remuneration of senior management and non-executive directors Remuneration of directors Total for all directors Emoluments Amounts received under incentive schemesa Total a Excludes amounts relating to past directors. 2016 2015 10 14 24 10 14 24 $ million 2014 14 10 24 Emoluments These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits earned during the relevant financial year, plus cash bonuses awarded for the year. Pension contributions During 2016 one executive director participated in a non-contributory pension scheme established for UK employees by a separate trust fund to which contributions are made by BP based on actuarial advice. One executive director participated in 2016 in a US defined benefit pension plan and retirement savings plans established for US employees. Further information Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 80. Remuneration of directors and senior management Total for all senior management and non-executive directors Short-term employee benefits Pensions and other post-retirement benefits Share-based payments Total 2016 2015 28 3 39 70 33 4 36 73 $ million 2014 34 3 34 71 Senior management comprises members of the executive team, see pages 58-59 for further information. Short-term employee benefits These amounts comprise fees and benefits paid to the non-executive chairman and non-executive directors, as well as salary, benefits and cash bonuses for senior management. Deferred annual bonus awards, to be settled in shares, are included in share-based payments. Short term employee benefits includes compensation for loss of office of $2.2 million in 2016 (2015 $nil and 2014 $1.5 million). Pensions and other post-retirement benefits The amounts represent the estimated cost to the group of providing pensions and other post-retirement benefits to senior management in respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’. Share-based payments This is the cost to the group of senior management’s participation in share-based payment plans, as measured by the fair value of options and shares granted, accounted for in accordance with IFRS 2 ‘Share-based Payments’. 178 BP Annual Report and Form 20-F 2016 34. Employee costs and numbers Employee costs Wages and salariesa Social security costs Share-based paymentsb Pension and other post-retirement benefit costs Average number of employeesc US Non-US Upstream Downstreamd e Other businesses and corporatee f 6,700 6,600 1,900 15,200 13,500 36,600 12,100 62,200 2016 Total 20,200 43,200 14,000 77,400 US Non-US 7,900 7,800 1,700 17,400 15,100 38,200 11,900 65,200 2015 Total 23,000 46,000 13,600 82,600 2016 8,456 760 764 1,253 2015 9,556 879 833 1,660 11,233 12,928 US Non-US 9,100 8,200 1,800 19,100 15,600 39,900 10,100 65,600 $ million 2014 10,710 983 689 1,554 13,936 2014 Total 24,700 48,100 11,900 84,700 a Includes termination payments of $545 million (2015 $857 million and 2014 $527 million). b The group provides certain employees with shares and share options as part of their remuneration packages. The majority of these share-based payment arrangements are equity-settled. c Reported to the nearest 100. d Includes 15,800 (2015 15,000 and 2014 14,200) service station staff. e Around 800 centralized function employees were reallocated from Upstream and Downstream to Other businesses and corporate during 2016, and around 2,000 employees from the global business services organization were reallocated from Downstream to Other businesses and corporate during 2015. f Includes 4,900 (2015 5,300 and 2014 5,100) agricultural, operational and seasonal workers in Brazil. 35. Auditor’s remuneration Fees – Ernst & Young The audit of the company annual accountsa The audit of accounts of subsidiaries of the company Total audit Audit-related assurance servicesb Total audit and audit-related assurance services Taxation compliance services Taxation advisory services Services relating to corporate finance transactions Total non-audit and other assurance services Total non-audit or non-audit-related assurance services Services relating to BP pension plansc 2016 2015 $ million 2014 25 12 37 7 44 1 – – 1 2 1 27 13 40 7 47 1 – 1 1 3 1 27 13 40 7 47 1 1 1 2 5 1 47 51 53 a Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements. b Includes interim reviews and reporting on internal financial controls and non-statutory audit services. c The pension plan services include tax compliance service of $nil (2015 $0.4 million and 2014 $0.4 million). 2016 includes $1 million of additional fees for 2015 and 2015 includes $2 million of additional fees for 2014. Auditors’ remuneration is included in the income statement within distribution and administration expenses. The tax services relate to income tax and indirect tax compliance, employee tax services and tax advisory services. The audit committee has established pre-approval policies and procedures for the engagement of Ernst & Young to render audit and certain assurance and tax services. The audit fees payable to Ernst & Young are reviewed by the audit committee in the context of other global companies for cost-effectiveness. Ernst & Young performed further assurance and tax services that were not prohibited by regulatory or other professional requirements and were pre-approved by the Committee. Ernst & Young is engaged for these services when its expertise and experience of BP are important. Most of this work is of an audit nature. Tax services were awarded either through a full competitive tender process or following an assessment of the expertise of Ernst & Young compared with that of other potential service providers. These services are for a fixed term. Under SEC regulations, the remuneration of the auditor of $47 million (2015 $51 million and 2014 $53 million) is required to be presented as follows: audit $37 million (2015 $40 million and 2014 $40 million); other audit-related $7 million (2015 $7 million and 2014 $7 million); tax $1 million (2015 $1 million and 2014 $2 million); and all other fees $2 million (2015 $3 million and 2014 $4 million). BP Annual Report and Form 20-F 2016 179 i F n a n c a i l s t a t e m e n t s 36. Subsidiaries, joint arrangements and associates The more important subsidiaries and associates of the group at 31 December 2016 and the group percentage of ordinary share capital (to nearest whole number) are set out below. There are no individually significant joint arrangements. Those held directly by the parent company are marked with an asterisk (*), the percentage owned being that of the group unless otherwise indicated. A complete list of undertakings of the group is included in Note 14 in the parent company financial statements of BP p.l.c. which are filed with the Registrar of Companies in the UK, along with the group’s annual report. Subsidiaries International BP Corporate Holdings BP Exploration Operating Company *BP Global Investments *BP International BP Oil International *Burmah Castrol Angola BP Exploration (Angola) Azerbaijan % 100 100 100 100 100 100 Country of incorporation England & Wales England & Wales England & Wales England & Wales England & Wales Scotland Principal activities Investment holding Exploration and production Investment holding Integrated oil operations Integrated oil operations Lubricants 100 England & Wales Exploration and production BP Exploration (Caspian Sea) BP Exploration (Azerbaijan) 100 100 England & Wales England & Wales Exploration and production Exploration and production Canada *BP Holdings Canada Egypt BP Exploration (Delta) Germany BP Europa SE India BP Exploration (Alpha) Trinidad & Tobago BP Trinidad and Tobago UK BP Capital Markets US *BP Holdings North America Atlantic Richfield Company BP America BP America Production Company BP Company North America BP Corporation North America BP Exploration & Production BP Exploration (Alaska) BP Products North America Standard Oil Company BP Capital Markets America Associates Russia Rosneft 100 England & Wales Investment holding 100 England & Wales Exploration and production 100 Germany Refining and marketing 100 England & Wales Exploration and production 70 US Exploration and production 100 England & Wales Finance 100 100 100 100 100 100 100 100 100 100 100 England & Wales US US US US US US US US US US Country of incorporation % Investment holding Exploration and production, refining and marketing pipelines and petrochemicals Finance Principal activities 20 Russia Integrated oil operations 180 BP Annual Report and Form 20-F 2016 37. Condensed consolidating information on certain US subsidiaries BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100%-owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe Bay Royalty Trust. The following financial information for BP p.l.c., BP Exploration (Alaska) Inc. and all other subsidiaries on a condensed consolidating basis is intended to provide investors with meaningful and comparable financial information about BP p.l.c. and its subsidiary issuers of registered securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiary issuer of public debt securities. Non-current assets for BP p.l.c. includes investments in subsidiaries recorded under the equity method for the purposes of the condensed consolidating financial information. Equity-accounted income of subsidiaries is the group’s share of profit related to such investments. The eliminations and reclassifications column includes the necessary amounts to eliminate the intercompany balances and transactions between BP p.l.c., BP Exploration (Alaska) Inc. and other subsidiaries. The financial information presented in the following tables for BP Exploration (Alaska) Inc. incorporates subsidiaries of BP Exploration (Alaska) Inc. using the equity method of accounting and excludes the BP group’s midstream operations in Alaska that are reported through different legal entities and that are included within the ‘other subsidiaries’ column in these tables. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Capital Markets p.l.c. and BP Capital Markets America Inc. These companies are 100%-owned finance subsidiaries of BP p.l.c. Income statement For the year ended 31 December Sales and other operating revenues Earnings from joint ventures – after interest and tax Earnings from associates – after interest and tax Equity-accounted income of subsidiaries – after interest and tax Interest and other income Gains on sale of businesses and fixed assets Total revenues and other income Purchases Production and manufacturing expenses Production and similar taxes Depreciation, depletion and amortization Impairment and losses on sale of businesses and fixed assets Exploration expense Distribution and administration expenses Profit (loss) before interest and taxation Finance costs Net finance (income) expense relating to pensions and other post- retirement benefits Profit (loss) before taxation Taxation Profit (loss) for the year Attributable to BP shareholders Non-controlling interests Statement of comprehensive income For the year ended 31 December Profit (loss) for the year Other comprehensive income Equity-accounted other comprehensive income of subsidiaries Total comprehensive income Attributable to BP shareholders Non-controlling interests Issuer Guarantor BP Exploration (Alaska) Inc. BP p.l.c. Other subsidiaries Eliminations and reclassifications 2,740 – – – 94 – 2,834 888 1,171 102 673 (147) – – 147 103 – 44 (41) 85 85 – 85 – – – 862 343 – 1,205 – – – – – – 808 397 311 (82) 168 53 115 115 – 115 182,999 966 994 – 899 1,132 186,990 134,062 27,906 581 13,832 (1,517) 1,721 9,797 608 1,981 272 (1,645) (2,479) 834 777 57 834 (2,731) – – (862) (830) – (4,423) (2,731) – – – – – (110) (1,582) (720) – (862) – (862) (862) – (862) $ million 2016 BP group 183,008 966 994 – 506 1,132 186,606 132,219 29,077 683 14,505 (1,664) 1,721 10,495 (430) 1,675 190 (2,295) (2,467) 172 115 57 172 $ million 2016 Issuer Guarantor BP Exploration (Alaska) Inc. 85 – – 85 85 – 85 BP p.l.c. 115 (1,505) 544 (846) (846) – (846) Other subsidiaries Eliminations and reclassifications BP group 834 517 – 1,351 1,321 30 1,351 (862) – (544) (1,406) (1,406) – (1,406) 172 (988) – (816) (846) 30 (816) BP Annual Report and Form 20-F 2016 181 i F n a n c a i l s t a t e m e n t s 37. Condensed consolidating information on certain US subsidiaries – continued Income statement continued For the year ended 31 December Sales and other operating revenues Earnings from joint ventures – after interest and tax Earnings from associates – after interest and tax Equity-accounted income of subsidiaries – after interest and tax Interest and other income Gains on sale of businesses and fixed assets Total revenues and other income Purchases Production and manufacturing expenses Production and similar taxes Depreciation, depletion and amortization Impairment and losses on sale of businesses and fixed assets Exploration expense Distribution and administration expenses Profit (loss) before interest and taxation Finance costs Net finance (income) expense relating to pensions and other post- retirement benefits Profit (loss) before taxation Taxation Profit (loss) for the year Attributable to BP shareholders Non-controlling interests a Minor amendments have been made to previously reported amounts. Statement of comprehensive income continued For the year ended 31 December Profit (loss) for the year Other comprehensive income Equity-accounted other comprehensive income of subsidiaries Total comprehensive income Attributable to BP shareholders Non-controlling interests Issuer Guarantor BP Exploration (Alaska) Inc. a 3,438 – – – 29 – 3,467 1,432 1,360 140 569 176 – 56 (266) 35 – (301) (129) (172) (172) – (172) BP p.l.c. – – – (5,404) 185 31 (5,188) – – – – – – 1,125 (6,313) 36 20 (6,369) 82 (6,451) (6,451) – (6,451) Other subsidiaries Eliminations and reclassifications 222,881 (28) 1,839 – 671 666 226,029 166,783 35,680 896 14,650 1,733 2,353 10,449 (6,515) 1,473 286 (8,274) (3,124) (5,150) (5,232) 82 (5,150) (3,425) – – 5,404 (274) (31) 1,674 (3,425) – – – – – (77) 5,176 (197) – 5,373 – 5,373 5,373 – 5,373 Issuer Guarantor BP Exploration (Alaska) Inc. (172) – – (172) (172) – (172) BP p.l.c. (6,451) 1,863 (3,640) (8,228) (8,228) – (8,228) Other subsidiaries Eliminations and reclassifications (5,150) (3,681) – (8,831) (8,872) 41 (8,831) 5,373 – 3,640 9,013 9,013 – 9,013 $ million 2015 BP group 222,894 (28) 1,839 – 611 666 225,982 164,790 37,040 1,036 15,219 1,909 2,353 11,553 (7,918) 1,347 306 (9,571) (3,171) (6,400) (6,482) 82 (6,400) $ million 2015 BP group (6,400) (1,818) – (8,218) (8,259) 41 (8,218) 182 BP Annual Report and Form 20-F 2016 37. Condensed consolidating information on certain US subsidiaries – continued Income statement continued For the year ended 31 December Sales and other operating revenues Earnings from joint ventures – after interest and tax Earnings from associates – after interest and tax Equity-accounted income of subsidiaries – after interest and tax Interest and other income Gains on sale of businesses and fixed assets Total revenues and other income Purchases Production and manufacturing expenses Production and similar taxes Depreciation, depletion and amortization Impairment and losses on sale of businesses and fixed assets Exploration expense Distribution and administration expenses Profit (loss) before interest and taxation Finance costs Net finance (income) expense relating to pensions and other post- retirement benefits Profit (loss) before taxation Taxation Profit (loss) for the year Attributable to BP shareholders Non-controlling interests Statement of comprehensive income continued For the year ended 31 December Profit (loss) for the year Other comprehensive income Equity-accounted other comprehensive income of subsidiaries Total comprehensive income Attributable to BP shareholders Non-controlling interests Issuer Guarantor BP Exploration (Alaska) Inc. 6,227 – – – 2 19 6,248 2,375 1,779 554 545 153 – 48 794 57 – 737 279 458 458 – 458 BP p.l.c. – – – 4,531 193 – 4,724 – – – – – – 929 3,795 23 (50) 3,822 42 3,780 3,780 – 3,780 Other subsidiaries Eliminations and reclassifications 353,529 570 2,802 – 910 876 358,687 285,720 25,596 2,404 14,618 8,812 3,632 11,364 6,541 1,255 364 4,922 626 4,296 4,073 223 4,296 (6,188) – – (4,531) (262) – (10,981) (6,188) – – – – – (75) (4,718) (187) – (4,531) – (4,531) (4,531) – (4,531) $ million 2014 BP group 353,568 570 2,802 – 843 895 358,678 281,907 27,375 2,958 15,163 8,965 3,632 12,266 6,412 1,148 314 4,950 947 4,003 3,780 223 4,003 $ million 2014 i F n a n c a i l s t a t e m e n t s Issuer Guarantor BP Exploration (Alaska) Inc. 458 – – 458 458 – 458 BP p.l.c. 3,780 Other subsidiaries Eliminations and reclassifications 4,296 (4,531) BP group 4,003 (1,840) (10,875) – (12,715) (10,843) (8,903) (8,903) – (8,903) – (6,579) (6,770) 191 (6,579) 10,843 6,312 6,312 – 6,312 – (8,712) (8,903) 191 (8,712) BP Annual Report and Form 20-F 2016 183 37. Condensed consolidating information on certain US subsidiaries – continued Balance sheet At 31 December Non-current assets Property, plant and equipment Goodwill Intangible assets Investments in joint ventures Investments in associates Other investments Subsidiaries – equity-accounted basis Fixed assets Loans Trade and other receivables Derivative financial instruments Prepayments Deferred tax assets Defined benefit pension plan surpluses Current assets Loans Inventories Trade and other receivables Derivative financial instruments Prepayments Current tax receivable Other investments Cash and cash equivalents Total assets Current liabilities Trade and other payables Derivative financial instruments Accruals Finance debt Current tax payable Provisions Non-current liabilities Other payables Derivative financial instruments Accruals Finance debt Deferred tax liabilities Provisions Defined benefit pension plan and other post-retirement benefit plan deficits Total liabilities Net assets Equity BP shareholders’ equity Non-controlling interests 184 BP Annual Report and Form 20-F 2016 Issuer Guarantor BP Exploration (Alaska) Inc. BP p.l.c. Other subsidiaries Eliminations and reclassifications BP group $ million 2016 7,405 – 578 – – – – 7,983 9 – – – – – 7,992 – 249 2,583 – 7 – – – 2,839 – – – – 2 – 156,864 156,866 – 2,951 – – – 528 160,345 – – 487 – – – – 50 537 122,352 11,194 17,605 8,609 14,090 1,033 – 174,883 34,941 1,474 4,359 945 4,741 56 221,399 259 17,406 24,660 3,016 1,479 1,194 44 23,434 71,492 – – – – – – (156,864) (156,864) (34,418) (2,951) – – – – 129,757 11,194 18,183 8,609 14,092 1,033 – 182,868 532 1,474 4,359 945 4,741 584 (194,233) 195,503 – – (7,055) – – – – – (7,055) 259 17,655 20,675 3,016 1,486 1,194 44 23,484 67,813 10,831 160,882 292,891 (201,288) 263,316 722 – 116 – 11 2 851 20 – – – 1,279 1,390 – 2,689 3,540 7,291 7,291 – 7,291 4,096 – 129 – – – 4,225 34,389 – 43 – 179 – 219 34,830 39,055 121,827 121,827 – 121,827 40,152 2,991 4,891 6,634 1,655 4,010 60,333 16,906 5,513 426 51,666 5,780 19,022 8,656 107,969 168,302 124,589 123,032 1,557 124,589 (7,055) – – – – – (7,055) (37,369) – – – – – 37,915 2,991 5,136 6,634 1,666 4,012 58,354 13,946 5,513 469 51,666 7,238 20,412 – 8,875 (37,369) 108,119 (44,424) 166,473 (156,864) 96,843 (156,864) – (156,864) 95,286 1,557 96,843 37. Condensed consolidating information on certain US subsidiaries – continued Balance sheet continued At 31 December Non-current assets Property, plant and equipment Goodwill Intangible assets Investments in joint ventures Investments in associates Other investments Subsidiaries – equity-accounted basis Fixed assets Loans Trade and other receivables Derivative financial instruments Prepayments Deferred tax assets Defined benefit pension plan surpluses Current assets Loans Inventories Trade and other receivables Derivative financial instruments Prepayments Current tax receivable Other investments Cash and cash equivalents Assets classified as held for sale Total assets Current liabilities Trade and other payables Derivative financial instruments Accruals Finance debt Current tax payable Provisions Liabilities directly associated with assets classified as held for sale Non-current liabilities Other payables Derivative financial instruments Accruals Finance debt Deferred tax liabilities Provisions Defined benefit pension plan and other post-retirement benefit plan deficits Total liabilities Net assets Equity BP shareholders’ equity Non-controlling interests a Minor amendments have been made to previously reported amounts. Issuer Guarantor BP Exploration (Alaska) Inc.a BP p.l.c. Other subsidiaries Eliminations and reclassifications BP group $ million 2015 8,345 – 539 – – – – 8,884 3 – – 4 – – 8,891 – 246 9,718 – 7 – – – 9,971 – – – – – 2 – 128,234 128,236 – – – – – 2,516 130,752 – – 1,062 – – – – – 1,062 – 121,413 11,627 18,121 8,412 9,420 1,002 – 169,995 7,245 2,216 4,409 999 1,545 131 186,540 272 13,896 22,393 4,242 1,831 599 219 26,389 69,841 578 – – – – – – (128,234) (128,234) (6,719) – – – – – 129,758 11,627 18,660 8,412 9,422 1,002 – 178,881 529 2,216 4,409 1,003 1,545 2,647 (134,953) 191,230 – – (10,850) – – – – – (10,850) – 272 14,142 22,323 4,242 1,838 599 219 26,389 70,024 578 9,971 1,062 70,419 (10,850) 70,602 18,862 131,814 256,959 (145,803) 261,832 961 – 116 – (21) 1 1,057 – 1,057 8 – – – 1,255 2,326 – 3,589 4,646 127 – 81 – 4 – 212 – 212 6,708 – 33 – 877 – 227 7,845 8,057 14,216 123,757 14,216 – 14,216 123,757 – 123,757 41,711 3,239 6,064 6,944 1,097 5,153 64,208 97 64,305 2,913 4,283 857 46,224 7,467 33,634 8,628 104,006 168,311 88,648 87,477 1,171 88,648 (10,850) – – – – – (10,850) – 31,949 3,239 6,261 6,944 1,080 5,154 54,627 97 (10,850) 54,724 (6,719) – – – – – 2,910 4,283 890 46,224 9,599 35,960 – 8,855 (6,719) 108,721 (17,569) 163,445 (128,234) 98,387 (128,234) – (128,234) 97,216 1,171 98,387 BP Annual Report and Form 20-F 2016 185 i F n a n c a i l s t a t e m e n t s 37. Condensed consolidating information on certain US subsidiaries – continued Cash flow statement For the year ended 31 December Net cash provided by operating activities Net cash provided by (used in) investing activities Net cash provided by (used in) financing activities Currency translation differences relating to cash and cash equivalents Increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of year Cash and cash equivalents at end of year For the year ended 31 December Net cash provided by operating activities Net cash provided by (used in) investing activities Net cash provided by (used in) financing activities Currency translation differences relating to cash and cash equivalents Increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of year Cash and cash equivalents at end of year For the year ended 31 December Net cash provided by operating activities Net cash provided by (used in) investing activities Net cash provided by (used in) financing activities Currency translation differences relating to cash and cash equivalents Increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of year Cash and cash equivalents at end of year Issuer Guarantor BP Exploration (Alaska) Inc. 699 (699) – – – – – BP p.l.c. 4,661 – (4,611) – 50 – 50 Other subsidiaries 5,331 (14,054) 6,588 (820) (2,955) 26,389 23,434 Issuer Guarantor BP Exploration (Alaska) Inc. 925 (925) – – – – – BP p.l.c. 6,628 – (6,659) – (31) 31 – Other subsidiaries 11,580 (16,375) 2,124 (672) (3,343) 29,732 26,389 Issuer Guarantor BP Exploration (Alaska) Inc. 92 (92) – – – – – BP p.l.c. 10,464 – (10,439) – 25 6 31 Other subsidiaries 22,198 (19,482) 5,173 (671) 7,218 22,514 29,732 $ million 2016 BP group 10,691 (14,753) 1,977 (820) (2,905) 26,389 23,484 $ million 2015 BP group 19,133 (17,300) (4,535) (672) (3,374) 29,763 26,389 $ million 2014 BP group 32,754 (19,574) (5,266) (671) 7,243 22,520 29,763 186 BP Annual Report and Form 20-F 2016 Supplementary information on oil and natural gas (unaudited) The regional analysis presented below is on a continent basis, with separate disclosure for countries that contain 15% or more of the total proved reserves (for subsidiaries plus equity-accounted entities), in accordance with SEC and FASB requirements. Oil and gas reserves – certain definitions Unless the context indicates otherwise, the following terms have the meanings shown below: Proved oil and gas reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) (ii) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any; and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favourable than in the reservoir as a whole, the operation of an installed programme in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or programme was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Undeveloped oil and gas reserves Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. Developed oil and gas reserves Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. For details on BP’s proved reserves and production compliance and governance processes, see pages 251-256. BP Annual Report and Form 20-F 2016 187 i F n a n c a i l s t a t e m e n t s Oil and natural gas exploration and production activities Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North America US Russia Rest of Asia $ million 2016 Total Subsidiaries Capitalized costs at 31 Decembera b Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs 34,171 483 34,654 21,745 12,909 Costs incurred for the year ended 31 Decembera b Acquisition of propertiesc Proved Unproved Exploration and appraisal costsd Development Total costs 215 – 215 165 1,284 1,664 – – – – – – – – 5 3 8 Results of operations for the year ended 31 Decembera Sales and other operating revenuese Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income)f Depreciation, depletion and amortization Net impairments and (gains) losses on sale of businesses and fixed assets Profit (loss) before taxationg Allocable taxesh Results of operations 81,633 4,712 86,345 44,988 41,357 3,622 2,377 5,999 272 5,727 12,624 2,450 15,074 6,764 8,310 46,892 3,808 50,700 31,456 19,244 – – – – – 30,870 4,132 35,002 15,942 19,060 5,752 562 6,314 2,826 3,488 215,564 18,524 234,088 123,993 110,095 314 38 352 391 2,372 3,115 640 6,204 6,844 693 2,524 155 1,687 – 10 10 70 28 108 74 2 76 61 114 – 25 66 – 10 10 123 1,519 1,652 747 103 850 672 476 38 115 – 181 181 297 2,957 3,435 1,215 3,391 4,606 87 1,220 – 597 – – – 10 – 10 – – – 10 – – 34 703 1,728 2,431 252 2,788 5,471 97 3,908 4,005 (27) 691 800 115 207 – 207 89 194 490 1,439 1,967 3,406 1,402 11,145 15,953 1,042 309 1,351 89 154 41 153 4,085 15,725 19,810 1,721 6,006 683 2,548 591 2,937 – 2,179 289 11,213 244 1,387 1,631 133 619 (351) (215) 26 421 447 3 208 – 37 1,002 209 3,940 (809) 379 1,252 (286) 1,538 (345) 112 335 (287) 622 (627) 8,372 (1,528) (402) (1,126) (5) 261 (185) (40) (145) (77) 1,815 (965) (194) (771) (765) 4,076 530 670 (140) – 44 (44) (10) (34) (182) 3,576 429 (74) 503 63 789 562 288 274 (2,747) 19,424 386 (335) 721 Upstream and Rosneft segments replacement cost profit (loss) before interest and tax Exploration and production activities – subsidiaries (as above) Midstream and other activities – subsidiariesi Equity-accounted entitiesj k Total replacement cost profit (loss) before interest and tax 1,252 335 (1,528) (185) (965) 530 (44) 429 562 386 (417) – 54 (1) (14) 20 (137) – 187 447 (142) (12) (2) 597 (81) 266 13 – (539) 1,317 835 388 (1,522) (322) (331) 376 551 614 575 1,164 a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes our share of oil and natural gas exploration and production activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia, Australia and Angola. b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. c Rest of Asia amounts include BP’s participating interest in the Abu Dhabi ADCO concession. d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. e Presented net of transportation costs, purchases and sales taxes. f Includes property taxes, other government take and the fair value gain on embedded derivatives of $32 million. The UK region includes a $454-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance programme. g Excludes the unwinding of the discount on provisions and payables amounting to $152 million which is included in finance costs in the group income statement. h UK region includes the deferred tax impact of the enactment of legislation to reduce the UK supplementary charge tax rate applicable to profits arising in the North Sea from 20% to 10%. i Midstream and other activities excludes inventory holding gains and losses. j The profits of equity-accounted entities are included after interest and tax. k Includes the results of BP’s 30% interest in Aker BP ASA from 1 October 2016. 188 BP Annual Report and Form 20-F 2016 Oil and natural gas exploration and production activities – continued Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North America US Russiaa Rest of Asia Equity-accounted entities (BP share) Capitalized costs at 31 Decemberb c Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs – – – – – 2,702 296 2,998 48 2,950 Costs incurred for the year ended 31 Decemberb d e Acquisition of propertiesc Proved Unproved Exploration and appraisal costsd Development Total costs – – – – – – – – – 18 54 72 Results of operations for the year ended 31 Decemberb Sales and other operating revenuesf Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income) Depreciation, depletion and amortization Net impairments and losses on sale of businesses and fixed assets Profit (loss) before taxation Allocable taxes Results of operationsg – – – – – – – – – – – – – 162 – 162 13 36 – (13) 48 – 84 78 75 3 – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – 10,211 6 10,217 4,615 5,602 – – – 7 559 566 1,865 – 1,865 – 559 335 (429) 499 164 1,128 737 319 418 – – – – – – – – – – – – – – – – – – – – – – – – 19,818 369 20,187 4,379 15,808 1,956 70 2,026 105 2,014 4,145 – 8,129 8,129 50 1,106 3,391 368 1,072 25 6,012 2,117 433 1,684 3,009 26 3,035 3,035 – – – – 1 371 372 876 16 892 – 145 352 3 386 – 886 6 3 3 Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities Exploration and production activities – equity-accounted entities after tax (as above) Midstream and other activities after taxh Total replacement cost profit (loss) after interest and tax – – – 3 (4) (1) – 20 20 – – – 418 – 1,684 3 29 (12) (1,087) 263 447 (12) 597 266 – – – – – – – – – – – – – – – – – – – – – – – – – – – $ million 2016 Total 35,740 697 36,437 12,077 24,360 1,956 70 2,026 131 2,998 5,155 2,903 8,145 11,048 63 1,846 4,078 (71) 2,005 189 8,110 2,938 830 2,108 2,108 (791) 1,317 a Amounts reported for Russia in this table include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations as well as downstream activities of Rosneft are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities. c Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. e The amounts shown reflect BP’s share of equity-accounted entities’ costs incurred, and not the costs incurred by BP in acquiring an interest in equity-accounted entities. f Presented net of transportation costs and sales taxes. g Includes the results of BP’s 30% interest in Aker BP ASA from 1 October 2016. h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses. BP Annual Report and Form 20-F 2016 189 i F n a n c a i l s t a t e m e n t s Oil and natural gas exploration and production activities – continued Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North America US Russia Rest of Asia $ million 2015 Total Subsidiaries Capitalized costs at 31 Decembera b Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs 33,214 437 33,651 21,447 12,204 10,568 168 10,736 7,172 80,716 5,602 86,318 43,290 3,564 43,028 3,559 2,377 5,936 191 5,745 11,051 2,964 14,015 6,251 42,807 4,635 47,442 29,406 7,764 18,036 – – – – – – – – 5 – 5 – – – 5 – – 27 28,474 2,740 31,214 15,967 15,247 5,177 933 6,110 2,677 215,566 19,856 235,422 126,401 3,433 109,021 – – – 102 3,439 3,541 800 4,028 4,828 53 1,083 834 76 – – – 125 128 253 407 (54) 353 1,794 13,458 15,605 1,450 340 1,790 52 166 46 215 7,043 17,702 24,745 2,353 7,519 1,036 2,621 Costs incurred for the year ended 31 Decembera b Acquisition of properties Proved Unproved Exploration and appraisal costsc Development Total costs 17 – 17 178 1,784 1,979 – – – 11 73 84 Results of operations for the year ended 31 Decembera 131 56 187 651 3,662 4,500 651 7,427 8,078 960 2,777 215 2,460 – – – 75 324 399 14 2 16 108 77 – 48 13 – (118) (118) 114 1,299 1,295 259 8 267 533 2,749 3,549 1,594 33 1,627 51 703 214 140 1,829 4,005 5,834 1,001 1,521 – 358 496 1,149 1,645 115 879 (273) (795) 209 718 927 8 313 – 92 Sales and other operating revenuesd Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income)e Depreciation, depletion and amortization Net impairments and (gains) losses on sale of businesses and fixed assets Profit (loss) before taxationf Allocable taxesg Results of operations 949 544 3,671 673 3,412 – 2,420 322 12,004 (390) 485 1,160 (930) 2,090 17 340 974 10,423 (47) 159 (2,345) (857) (206) (1,488) – 246 (230) (5) (225) 101 846 1,882 7,138 (255) (28) (227) (1,304) 694 (1,998) – 32 (32) (5) (27) 105 4,571 257 (66) 323 140 941 849 472 377 1,159 26,692 (1,947) (566) (1,381) Upstream and Rosneft segments replacement cost profit (loss) before interest and tax Exploration and production activities – subsidiaries (as above) Midstream and other activities – subsidiariesh Equity-accounted entitiesi Total replacement cost profit (loss) 1,160 (47) (2,345) (230) (255) (1,304) (32) 257 849 (1,947) 401 – 110 (7) 43 19 10 – 211 370 (39) (552) (16) 1,326 67 363 14 – 801 1,519 before interest and tax 1,561 56 (2,283) (220) 326 (1,895) 1,278 687 863 373 a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes our share of oil and natural gas exploration and production activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia, Australia and Angola. b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. d Presented net of transportation costs, purchases and sales taxes. e Includes property taxes, other government take and the fair value gain on embedded derivatives of $120 million. The UK region includes a $832-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance programme. f Excludes the unwinding of the discount on provisions and payables amounting to $164 million which is included in finance costs in the group income statement. g UK region includes the one-off deferred tax impact of the enactment of legislation to reduce the UK supplementary charge tax rate applicable to profits arising in the North Sea from 32% to 20%. h Midstream and other activities excludes inventory holding gains and losses. i BP’s share of the profits of equity-accounted entities are included after interest and tax reported by those entities. 190 BP Annual Report and Form 20-F 2016 Oil and natural gas exploration and production activities – continued Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North America US Equity-accounted entities (BP share) Capitalized costs at 31 Decemberb c Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs – – – – – Costs incurred for the year ended 31 Decemberb d e Acquisition of propertiesc Proved Unproved Exploration and appraisal costsd Development Total costs – – – – – – Results of operations for the year ended 31 Decemberb Sales and other operating revenuesf Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income) Depreciation, depletion and amortization Net impairments and losses on sale of businesses and fixed assets Profit (loss) before taxation Allocable taxes Results of operations – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – 9,824 – 9,824 4,117 5,707 – – – 8 1,128 1,136 2,060 – 2,060 3 647 425 (381) 465 80 1,239 821 504 317 Russiaa Rest of Asia 12,728 437 13,165 2,788 10,377 3,486 26 3,512 3,458 54 16 26 42 123 1,702 1,867 – 8,592 8,592 52 1,083 3,911 284 992 – 6,322 2,270 449 1,821 – – – 1 443 444 1,022 19 1,041 – 168 388 – 484 35 1,075 (34) 1 (35) – – – – – – – – – – – – – – – – – – – – – – – – Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities Exploration and production activities – equity – accounted entities after tax (as above) Midstream and other activities after taxg Total replacement cost profit (loss) after interest and tax – – – – (7) (7) – 19 19 – – – 317 – 1,821 (35) 53 (552) (495) 398 370 (552) 1,326 363 $ million 2015 Total 26,038 463 26,501 10,363 16,138 16 26 42 132 3,273 3,447 3,082 8,611 11,693 55 1,898 4,724 (97) 1,941 115 8,636 3,057 954 2,103 2,103 (584) 1,519 – – – – – – – – – – – – – – – – – – – – – – – – – – – a Amounts reported for Russia in this table include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations as well as downstream activities of Rosneft are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities. c Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. e The amounts shown reflect BP’s share of equity-accounted entities’ costs incurred, and not the costs incurred by BP in acquiring an interest in equity-accounted entities. f Presented net of transportation costs and sales taxes. g Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses. BP Annual Report and Form 20-F 2016 191 i F n a n c a i l s t a t e m e n t s Oil and natural gas exploration and production activities – continued Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North America US Russia Rest of Asia $ million 2014 Total Subsidiaries Capitalized costs at 31 Decembera b Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs 31,496 395 31,891 21,068 10,823 10,578 165 10,743 6,610 76,476 6,294 82,770 39,383 4,133 43,387 3,205 2,454 5,659 190 5,469 9,796 2,984 12,780 5,482 39,020 5,769 44,789 25,105 7,298 19,684 Costs incurred for the year ended 31 Decembera b Acquisition of properties Proved Unproved Exploration and appraisal costsc Development Total costs 42 – 42 279 2,067 2,388 – – – 16 293 309 6 346 352 888 4,792 6,032 Results of operations for the year ended 31 Decembera d Sales and other operating revenuese Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income)f Depreciation, depletion and amortization Net impairments and (gains) losses on sale of businesses and fixed assets Profit (loss) before taxationg Allocable taxes Results of operations 529 1,069 1,598 94 979 (234) (1,515) 77 1,662 1,218 14,894 1,739 16,112 47 436 – 77 1,294 3,492 690 3,260 506 676 3,805 2,537 2,367 2,278 (28) 3,514 12,513 (769) (1,383) (1,775) (1,108) 614 (667) 3,599 1,269 2,330 – – – 109 706 815 4 15 19 63 34 – 55 4 – 156 (137) 15 (152) – 75 75 325 983 1,383 2,802 450 3,252 502 783 175 284 – 57 57 899 2,881 3,837 2,536 6,289 8,825 860 1,542 – 120 – – – – – – – – – – – – – – – – – 57 24,177 2,773 26,950 13,501 13,449 5,061 888 5,949 2,215 199,809 21,722 221,531 113,554 3,734 107,977 557 – 557 194 3,205 3,956 1,135 6,951 8,086 712 1,289 2,234 (69) – – – 201 169 370 605 478 1,083 2,911 15,096 19,090 2,574 624 3,198 60 232 93 343 10,875 31,954 42,829 3,632 8,787 2,958 2,612 678 3,343 – 2,461 255 11,728 11 2,433 819 865 (46) 1,128 6,993 1,832 1,216 616 – 57 (57) 3 (60) 391 7,018 1,068 67 1,001 – 6,317 983 36,034 2,215 1,161 1,054 6,795 2,105 4,690 Upstream and Rosneft segments replacement cost profit (loss) before interest and tax Exploration and production activities – subsidiaries (as above) Midstream and other activities – subsidiariesh Equity-accounted entitiesi Total replacement cost profit (loss) before interest and tax (769) (1,775) 3,599 (137) 819 1,832 (57) 1,068 2,215 6,795 163 – 99 62 703 23 130 – 175 480 (170) (33) (26) 2,125 (63) 557 14 – 1,025 3,214 (606) (1,614) 4,325 (7) 1,474 1,629 2,042 1,562 2,229 11,034 a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes our share of oil and natural gas exploration and production activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia, Australia and Angola. b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. d Amendments have been made to previously published amounts for the Australasia region with no overall effect on total replacement cost before interest and tax. e Presented net of transportation costs, purchases and sales taxes. f Includes property taxes, other government take and the fair value gain on embedded derivatives of $430 million. The UK region includes a $1,016-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance programme. g Excludes the unwinding of the discount on provisions and payables amounting to $207 million which is included in finance costs in the group income statement. h Midstream and other activities excludes inventory holding gains and losses. i BP’s share of the profits of equity-accounted entities are included after interest and tax reported by those entities. 192 BP Annual Report and Form 20-F 2016 Oil and natural gas exploration and production activities – continued Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North America US Equity-accounted entities (BP share) Capitalized costs at 31 Decemberb c Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs – – – – – Costs incurred for the year ended 31 Decemberb c Acquisition of propertiesd Proved Unproved Exploration and appraisal costse Developmentf Total costs – – – – – – Results of operations for the year ended 31 Decemberb Sales and other operating revenuesg Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income) Depreciation, depletion and amortization Net impairments and losses on sale of businesses and fixed assets Profit (loss) before taxation Allocable taxes Results of operations – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – 8,719 5 8,724 3,652 5,072 – – – 5 1,026 1,031 2,472 – 2,472 4 567 721 4 370 25 1,691 781 402 379 Russiaa Rest of Asia 12,971 376 13,347 2,031 11,316 3,073 25 3,098 2,986 112 (46) 87 41 128 1,913 2,082 – – – 4 326 330 – 10,972 10,972 1,257 19 1,276 62 1,318 5,214 302 1,509 – 8,405 2,567 637 1,930 1 152 692 – 371 – 1,216 60 29 31 – – – – – – – – – – – – – – – – – – – – – – – – Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities Exploration and production activities – equity-accounted entities after tax (as above) Midstream and other activities after taxh Total replacement cost profit (loss) after interest and tax – – – – 62 62 – 23 23 – – – 379 101 – 1,930 31 (33) 195 526 480 (33) 2,125 557 $ million 2014 Total 24,763 406 25,169 8,669 16,500 (46) 87 41 137 3,265 3,443 3,729 10,991 14,720 67 2,037 6,627 306 2,250 25 11,312 3,408 1,068 2,340 2,340 874 3,214 – – – – – – – – – – – – – – – – – – – – – – – – – – – a Amounts reported for Russia in this table include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations as well as downstream activities of Rosneft are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities. c The amounts shown reflect BP’s share of equity-accounted entities’ costs incurred, and not the costs incurred by BP in acquiring an interest in equity-accounted entities. d Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. e Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. f An amendment has been made to the amount previously disclosed for the Rest of Asia region. g Presented net of transportation costs and sales taxes. h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses. BP Annual Report and Form 20-F 2016 193 i F n a n c a i l s t a t e m e n t s Movements in estimated net proved reserves Crude oila b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimatesd Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione Sales of reserves-in-place At 31 Decemberf Developed Undeveloped Equity-accounted entities (BP share)g At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberh Developed Undeveloped Europe North America South America Africa Asia Australasia million barrels 2016 Total 141 298 440 13 – 3 2 (29) – (11) 155 274 429 – – – – – – – – – – – – – Rest of Europe UK USc 890 577 86 19 106 1,467 – – – – (9) (97) (106) (30) 1 3 – (119) (1) (145) Rest of North America 46 205 252 – – – 4 (5) – (1) 826 497 1,322 42 209 251 – – – – – – – – 116 – (3) – 114 45 69 114 – – – – – – – – – – – – – 890 577 – – – – – – – – – – – – – 47 205 252 42 209 251 Russia Rest of Asia 340 89 429 22 3 – – (96) – (71) 317 42 358 2 – 2 – – – – – – – 1 – 1 342 89 431 318 42 360 – – – – – – – – – – – – – 2,844 1,981 4,825 33 4 456 285 (305) (2) 471 3,162 2,134 5,296 2,844 1,981 4,825 3,162 2,134 5,296 598 192 790 543 70 25 – (75) (1) 562 1,107 245 1,352 68 – 68 13 – – – (37) (1) (25) 43 1 44 666 192 858 1,150 246 1,395 8 18 26 (2) – – – (4) – (6) 9 11 20 311 311 622 (2) 1 36 16 (28) – 24 321 325 646 319 329 648 330 336 666 35 16 51 2 – 1 – (6) (2) (5) 32 14 46 – – – – – – – – – – – – – 35 16 51 32 14 46 2,146 1,414 3,560 548 74 32 6 (341) (102) 218 2,487 1,291 3,778 3,225 2,292 5,517 45 5 609 301 (373) (2) 584 3,573 2,529 6,101 5,371 3,707 9,078 6,060 3,819 9,879 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 141 298 86 19 At 31 December Developed Undeveloped 440 106 1,467 155 274 429 45 69 826 497 114 1,322 a Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 9 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Rest of Asia includes additions from Abu Dhabi ADCO concession. e Includes 6 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. g Includes 347 million barrels of crude oil in respect of the 6.58% non-controlling interest in Rosneft, including 28 mmbbl held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha. h Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,330 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 62 million barrels in Venezuela and 5,268 million barrels in Russia. 194 BP Annual Report and Form 20-F 2016 Movements in estimated net proved reserves – continued Natural gas liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionc Sales of reserves-in-place At 31 Decemberd Developed Undeveloped Equity-accounted entities (BP share)e At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberf Developed Undeveloped Europe North America South America Africa Asia Australasia million barrels 2016 Total Rest of Europe 11 1 12 – – – – (1) (10) (12) – – – – – – – – 5 – – – 5 3 2 5 UK 5 4 10 7 – 1 – (2) – 7 13 3 16 – – – – – – – – – – – – – Rest of North America Russia Rest of Asia – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – 7 28 35 – – – – (2) – (2) 5 28 33 – – – – – – – – – – – – – 7 28 35 5 28 33 5 10 15 1 – – – (2) – (1) 13 1 14 13 – 13 (2) – – – – – (2) 11 – 11 18 10 28 24 1 25 – – – – – – – – – – – – – 32 15 47 18 – – – – – 18 50 15 65 32 15 47 50 15 65 – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – US 269 70 339 (24) 3 4 – (24) – (40) 226 73 299 – – – – – – – – – – – – – 269 70 339 226 73 299 9 2 12 – – – – (1) – (1) 9 2 11 – – – – – – – – – – – – – 9 2 12 9 2 11 308 115 422 (14) 3 6 – (34) (10) (49) 266 107 373 45 15 60 16 – 5 – – – 21 65 17 81 352 130 482 331 123 454 i F n a n c a i l s t a t e m e n t s Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 5 4 11 1 At 31 December Developed Undeveloped 10 13 3 16 12 3 2 5 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. d Includes 10 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Total proved NGL reserves held as part of our equity interest in Rosneft is 65 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 65 million barrels in Russia. BP Annual Report and Form 20-F 2016 195 Movements in estimated net proved reserves – continued Total liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimatesd Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione Sales of reserves-in-place At 31 Decemberf Developed Undeveloped Equity-accounted entities (BP share)g At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberh i Developed Undeveloped Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North America USc Russia Rest of Asia million barrels 2016 Total 147 303 449 20 – 5 2 (31) – (4) 168 277 445 – – – – – – – – – – – – – 98 20 117 1,159 647 1,806 46 205 252 – – – – (10) (108) (117) (54) 5 7 – (143) (1) (185) – – – 4 (5) – (1) – – – – – – – – 122 – (3) – 119 48 71 119 1,051 569 1,621 42 209 251 – – – – – – – – – – – – – – – – – – – – – – – – – – 1,159 647 1,806 1,051 569 1,621 47 205 252 42 209 251 15 46 61 (2) – – – (6) – (8) 14 39 53 311 312 622 (2) 1 36 16 (28) – 24 321 325 646 326 357 684 335 364 699 346 99 444 23 3 – – (98) – (72) 330 43 372 14 – 14 (2) – – – – – (2) 12 – 12 360 99 459 342 43 385 – – – – – – – – – – – – – 2,876 1,996 4,872 51 4 456 285 (305) (2) 489 3,213 2,148 5,361 2,876 1,996 4,872 3,213 2,148 5,361 598 192 790 543 70 25 – (75) (1) 562 1,107 245 1,352 68 – 68 13 – – – (37) (1) (25) 43 1 44 666 192 858 1,150 246 1,395 45 18 63 3 – 1 – (7) (2) (5) 42 16 57 – – – – – – – – – – – – – 45 18 63 42 16 57 2,453 1,529 3,982 533 78 38 6 (375) (112) 168 2,753 1,398 4,151 3,270 2,307 5,577 61 5 614 301 (374) (2) 605 3,637 2,545 6,183 5,723 3,836 9,560 6,390 3,943 10,333 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 147 302 98 20 At 31 December Developed Undeveloped 449 117 168 277 445 48 71 119 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 9 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Rest of Asia includes additions from Abu Dhabi ADCO concession. e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. f Also includes 16 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. h Includes 347 million barrels in respect of the non-controlling interest in Rosneft, including 28 mmboe held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha. i Total proved liquid reserves held as part of our equity interest in Rosneft is 5,395 million barrels, comprising less than 1 million barrels in Canada, 62 million barrels in Venezuela, less than 1 million barrels in Vietnam and 5,333 million barrels in Russia. 196 BP Annual Report and Form 20-F 2016 Movements in estimated net proved reserves – continued Natural gasa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionc Sales of reserves-in-place At 31 Decemberd Developed Undeveloped Equity-accounted entities (BP share)e At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionc Sales of reserves-in-place At 31 Decemberf g Developed Undeveloped Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North America US Russia Rest of Asia 2016 Total billion cubic feet 2,071 5,989 8,060 847 2,305 3,152 (1,042) 42 – 355 (624) (37) (1,306) (19) 1 – 43 (219) – (194) 1,784 4,970 6,755 767 2,191 2,958 – – – – – – – – – – – – – 1,463 598 2,061 386 – 386 4,962 6,176 11,139 62 1 19 128 (190) – 20 34 – – – (8) – 26 736 10 81 343 (461) (1) 709 1,546 534 2,080 412 – 412 5,544 6,304 11,847 1,803 3,455 5,257 548 22 – – (152) (17) 401 1,890 3,769 5,659 44 4 48 5 – – – (15) (8) (18) 26 4 30 274 14 288 6,257 2,105 8,363 348 343 691 133 – 95 – (71) – 158 499 350 848 – – – – – – – – – – – – – – – – – (33) (256) (288) – – – – – – – – 115 – (4) – 110 89 21 110 (231) 469 91 1 (676) (2) (348) 5,447 2,567 8,014 – – – – – – – – – – – – – 6,257 2,105 8,363 5,447 2,567 8,014 – – – 3 – – – (4) – – – – – 1 – 1 – – – – – – – – – 1 1 – 1 – – – 3,408 1,343 4,751 15,009 15,553 30,563 396 – 252 – (306) (439) (211) 534 438 399 (2,085) (750) (97) (1,675) 3,012 1,643 4,654 13,398 15,490 28,888 – – – – – – – – – – – – – i F n a n c a i l s t a t e m e n t s 6,856 6,778 13,634 836 11 216 471 (680) (8) 846 7,617 6,863 14,480 21,865 22,331 44,197 21,015 22,353 43,368 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 348 343 274 14 At 31 December Developed Undeveloped 691 288 499 350 848 89 21 110 3,534 6,587 1,233 2,305 4,962 6,176 10,121 3,538 11,139 3,330 5,505 8,835 1,179 2,191 5,544 6,304 3,370 11,847 1,847 3,459 5,305 1,916 3,772 5,688 3,408 1,343 4,751 3,012 1,643 4,654 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes 176 billion cubic feet of natural gas consumed in operations, 145 billion cubic feet in subsidiaries, 31 billion cubic feet in equity-accounted entities. d Includes 2,026 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Includes 300 billion cubic feet of natural gas in respect of the 2.53% non-controlling interest in Rosneft including 3 billion cubic feet held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha. g Total proved gas reserves held as part of our equity interest in Rosneft is 11,900 billion cubic feet, comprising 1 billion cubic feet in Canada, 33 billion cubic feet in Venezuela, 23 billion cubic feet in Vietnam and 11,843 billion cubic feet in Russia. BP Annual Report and Form 20-F 2016 197 Movements in estimated net proved reserves – continued million barrels of oil equivalentc Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North America USd Russia Rest of Asia Total hydrocarbonsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimatese Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionf g Sales of reserves-in-place At 31 Decemberh Developed Undeveloped Equity-accounted entities (BP share)i At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiong Sales of reserves-in-place At 31 Decemberj k Developed Undeveloped 207 362 568 43 – 21 2 (43) – 23 254 338 592 – – – – – – – – – – – – – 145 22 167 2,238 1,010 3,248 46 205 252 373 1,078 1,451 – – – – (16) (152) (167) (94) 86 23 – (260) (1) (245) 1 – – 4 (5) – (1) (181) 7 – 61 (114) (7) (233) – – – – – – – – 142 – (3) – 138 63 75 138 1,990 1,012 3,002 42 209 251 321 896 1,217 – – – – – – – – – – – – – – – – – – – – – – – – – – 2,238 1,010 3,248 1,990 1,012 3,002 47 205 252 42 209 251 563 415 978 9 1 39 38 (61) – 27 588 417 1,005 936 1,493 2,429 909 1,313 2,222 492 496 988 20 3 – 8 (136) – (105) 462 420 882 81 – 81 4 – – – (2) – 2 83 – 83 573 496 1,069 545 420 966 – – – – – – – – – – – – – 3,732 3,061 6,792 178 6 470 344 (385) (2) 611 4,168 3,235 7,404 3,732 3,061 6,792 4,168 3,235 7,404 909 788 1,696 637 74 25 – (101) (4) 631 1,433 895 2,327 76 1 77 14 – – – (40) (2) (28) 47 1 49 984 788 1,773 1,480 896 2,376 2016 Total 5,041 4,211 9,252 497 170 113 75 (735) (241) (121) 5,063 4,068 9,131 4,452 3,476 7,928 205 7 652 382 (491) (4) 751 4,951 3,729 8,679 632 250 882 71 – 44 – (60) (78) (22) 561 299 860 – – – – – – – – – – – – – 632 250 882 561 299 860 9,493 7,687 17,180 10,014 7,797 17,810 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 207 362 145 22 At 31 December Developed Undeveloped 568 167 254 338 592 63 75 138 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent. d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 9 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. e Rest of Asia includes additions from Abu Dhabi ADCO concession. f Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. g Includes 30 million barrels of oil equivalent of natural gas consumed in operations, 25 million barrels of oil equivalent in subsidiaries, 5 million barrels of oil equivalent in equity-accounted entities. h Includes 366 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. i Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. j Includes 402 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 29 mmboe held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha. k Total proved reserves held as part of our equity interest in Rosneft is 7,447 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 68 million barrels of oil equivalent in Venezuela, 4 million barrels of oil equivalent in Vietnam and 7,375 million barrels of oil equivalent in Russia. 198 BP Annual Report and Form 20-F 2016 Movements in estimated net proved reserves – continued Crude oila b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione Sales of reserves-in-place At 31 Decemberf Developed Undeveloped Equity-accounted entities (BP share)g At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberh Developed Undeveloped Europe North America South America Africa Asia Australasia Rest of Europe UK USc Rest of North America Russia Rest of Asiad million barrels 2015 Total 159 329 488 (23) – 1 – (27) (1) (48) 141 298 440 – – – – – – – – – – – – – 95 22 117 1,030 664 1,694 9 163 172 2 – – – (14) – (12) 86 19 (130) 15 – 3 (115) – (227) 890 577 106 1,467 – – – – – – – – – – – – – – – – – – – – – – – – – – 1,030 664 1,694 39 – – 42 (1) – 80 46 205 252 – – 1 – – – – – – – – – – 9 164 173 47 205 252 10 22 32 (2) – – – (5) – (6) 8 18 26 316 314 630 9 3 – 9 (28) – (8) 311 311 622 326 336 662 319 329 648 317 120 437 80 2 6 2 (98) – (8) 340 89 429 2 – 2 – – – – – – – 2 – 2 319 120 439 342 89 431 – – – – – – – – – – – – – 2,997 1,933 4,930 (23) – 28 185 (295) (1) (105) 2,844 1,981 4,825 2,997 1,933 4,930 2,844 1,981 4,825 384 197 581 295 – – – (87) – 208 598 192 790 89 11 101 3 – – – (35) – (32) 68 – 68 473 208 682 666 192 858 40 19 59 (2) – – – (6) – (8) 35 16 51 – – – – – – – – – – – – – 40 19 59 35 16 51 2,044 1,538 3,582 260 18 7 47 (353) (1) (21) 2,146 1,414 3,560 3,405 2,258 5,663 (11) 3 28 194 (358) (1) (146) 3,225 2,292 5,517 5,448 3,796 9,244 5,371 3,707 9,078 i F n a n c a i l s t a t e m e n t s Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 159 329 95 22 488 117 At 31 December Developed Undeveloped 141 298 440 86 19 890 577 106 1,467 a Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 23 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to comparative periods. There was no impact on 2015 proved reserves totals. e Includes 8 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. g Includes 70 million barrels of crude oil in respect of the 1.27% non-controlling interest in Rosneft, including 28 mmbbl held through BP’s equity accounted interest in Taas-Yuryakh Neftegazodobycha. h Total proved crude oil reserves held as part of our equity interest in Rosneft is 4,823 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 26 million barrels in Venezuela and 4,797 million barrels in Russia. BP Annual Report and Form 20-F 2016 199 Movements in estimated net proved reserves – continued Natural gas liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionc Sales of reserves-in-place At 31 Decemberd Developed Undeveloped Equity-accounted entities (BP share)e At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberf Developed Undeveloped Europe North America South America Africa Asia Australasia million barrels 2015 Total Rest of Europe UK 6 3 9 2 – – – (2) – – 5 4 10 – – – – – – – – – – – – – 13 1 14 – – – – (2) – (2) 11 1 12 – – – – – – – – – – – – – Rest of North America Russia Rest of Asia – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – 11 28 39 – – – – (4) – (4) 7 28 35 – – – – – – – – – – – – – 11 28 39 7 28 35 5 7 12 6 – – – (3) – 3 5 10 15 15 – 15 (3) – – – – – (3) 13 – 13 20 7 27 18 10 28 – – – – – – – – – – – – – 30 16 46 1 – – – – – 1 32 15 47 30 16 46 32 15 47 – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – US 323 104 427 (80) 12 3 – (23) (1) (88) 269 70 339 – – – – – – – – – – – – – 323 104 427 269 70 339 6 3 10 3 – – – (1) – 2 9 2 12 – – – – – – – – – – – – – 6 3 10 9 2 12 364 146 510 (69) 12 4 – (34) (1) (88) 308 115 422 46 16 62 (2) – – – – – (2) 45 15 60 410 163 572 352 130 482 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 6 3 13 1 At 31 December Developed Undeveloped 9 5 4 10 14 11 1 12 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 4 thousand barrels per day for equity-accounted entities. d Includes 11 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Total proved NGL reserves held as part of our equity interest in Rosneft is 47 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 47 million barrels in Russia. 200 BP Annual Report and Form 20-F 2016 Movements in estimated net proved reserves – continued Total liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione Sales of reserves-in-place At 31 Decemberf Developed Undeveloped Equity-accounted entities (BP share)g At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberh i Developed Undeveloped Europe North America South America Africa Asia Australasia Rest of Europe UK USc Rest of North America Russia Rest of Asiad million barrels 2015 Total 166 332 497 (20) – 1 – (29) (1) (48) 147 302 449 – – – – – – – – – – – – – 108 23 131 1,352 769 2,121 9 163 172 2 – – – (16) – (14) (210) 28 3 4 (138) (1) (315) 39 – – 42 (1) – 80 98 20 117 1,159 647 1,806 46 205 252 – – – – – – – – – – – – – – – – – – – – – – – – – – – – 1 – – – – – – (1) – – – 1,352 769 2,121 1,159 647 1,806 9 164 173 47 205 252 21 50 71 (2) – – – (8) – (10) 15 46 61 316 314 630 9 3 – 9 (28) – (8) 311 312 622 337 364 701 326 357 684 322 127 449 86 2 6 2 (101) – (5) 346 99 444 17 – 17 (3) – – – – – (3) 14 – 14 339 127 466 360 99 459 – – – – – – – – – – – – – 3,028 1,949 4,976 (22) – 28 185 (295) (1) (104) 2,876 1,996 4,872 3,028 1,949 4,976 2,876 1,996 4,872 384 197 581 295 – – – (87) – 208 598 192 790 89 11 101 3 – – – (35) – (32) 68 – 68 473 208 682 666 192 858 46 22 68 1 – – – (7) – (6) 45 18 63 – – – – – – – – – – – – – 46 22 68 45 18 63 2,407 1,684 4,092 191 30 11 48 (387) (2) (109) 2,453 1,529 3,982 3,451 2,274 5,725 (13) 3 28 194 (358) (1) (147) 3,270 2,307 5,577 5,858 3,958 9,817 5,723 3,836 9,560 i F n a n c a i l s t a t e m e n t s Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 166 332 108 23 At 31 December Developed Undeveloped 497 131 147 302 449 98 20 117 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 23 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to comparative periods. There was no impact on 2015 proved reserves totals. e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 4 thousand barrels per day for equity-accounted entities. f Also includes 19 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. h Includes 70 million barrels in respect of the non-controlling interest in Rosneft, including 28 mmboe held through BP’s equity accounted interest in Taas-Yuryakh Neftegazodobycha. i Total proved liquid reserves held as part of our equity interest in Rosneft is 4,871 million barrels, comprising less than 1 million barrels in Canada, 26 million barrels in Venezuela, less than 1 million barrels in Vietnam and 4,844 million barrels in Russia. BP Annual Report and Form 20-F 2016 201 Movements in estimated net proved reserves – continued Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North America US Russia Rest of Asia billion cubic feet 2015 Total Natural gasa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionc Sales of reserves-in-place At 31 Decemberd Developed Undeveloped Equity-accounted entities (BP share)e At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionc Sales of reserves-in-place At 31 Decemberf g Developed Undeveloped 2,352 6,313 8,666 901 1,597 2,497 132 – 29 – (709) (58) (605) 203 7 554 174 (248) (35) 654 2,071 5,989 8,060 847 2,305 3,152 – – – – – – – – – – – – – 1,228 717 1,945 400 – 400 4,674 5,111 9,785 81 8 – 209 (182) (1) 116 (14) – – – – – (14) 1,604 – 5 175 (430) – 1,354 1,463 598 2,061 386 – 386 4,962 6,176 11,139 1,688 3,892 5,580 (165) – – – (157) – (322) 1,803 3,455 5,257 60 9 69 (2) – – – (19) – (21) 44 4 48 382 386 768 (12) 4 – – (65) (5) (77) 348 343 691 – – – – – – – – – – – – – 300 19 318 7,168 2,447 9,615 14 – – – (44) – (30) (1,120) 432 65 5 (628) (6) (1,252) 274 14 288 6,257 2,105 8,363 – – – – – – – – – – – – – – – – – – – – – – – – – – 7,168 2,447 9,615 6,257 2,105 8,363 17 – 17 (13) – – – (4) – (17) – – – 1 1 1 (1) – – – – – (1) 1 – 1 18 1 18 1 – 1 3,316 1,719 5,035 16,124 16,372 32,496 13 – – – (297) – (284) (948) 443 648 179 (2,151) (104) (1,933) 3,408 1,343 4,751 15,009 15,553 30,563 – – – – – – – – – – – – – 6,363 5,837 12,200 1,669 8 5 384 (632) (1) 1,434 6,856 6,778 13,634 22,487 22,209 44,695 21,865 22,331 44,197 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 382 386 300 19 At 31 December Developed Undeveloped 768 318 348 343 691 274 14 288 3,581 7,030 10,610 1,301 1,597 2,897 4,674 5,111 9,785 3,534 6,587 1,233 2,305 4,962 6,176 10,121 3,538 11,139 1,748 3,901 5,648 1,847 3,459 5,305 3,316 1,719 5,035 3,408 1,343 4,751 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes 175 billion cubic feet of natural gas consumed in operations, 146 billion cubic feet in subsidiaries, 29 billion cubic feet in equity-accounted entities. d Includes 2,359 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Includes 129 billion cubic feet of natural gas in respect of the 0.23% non-controlling interest in Rosneft including 5 billion cubic feet held through BP’s equity accounted interest in Taas-Yuryakh Neftegazodobycha. g Total proved gas reserves held as part of our equity interest in Rosneft is 11,169 billion cubic feet, comprising 1 billion cubic feet in Canada, 13 billion cubic feet in Venezuela, 22 billion cubic feet in Vietnam and 11,133 billion cubic feet in Russia. 202 BP Annual Report and Form 20-F 2016 Movements in estimated net proved reserves – continued million barrels of oil equivalentc Europe North America South America Africa Asia Australasia Rest of Europe UK USd Rest of North America Russia Rest of Asiae Total hydrocarbonsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionf g Sales of reserves-in-place At 31 Decemberh Developed Undeveloped Equity-accounted entities (BP share)i At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiong Sales of reserves-in-place At 31 Decemberj k Developed Undeveloped 232 398 630 (22) 1 1 – (40) (1) (62) 207 362 568 – – – – – – – – – – – – – 160 26 186 2,588 1,191 3,779 12 163 175 426 1,139 1,565 4 – – – (23) – (19) (403) 102 15 4 (247) (2) (531) 36 – – 42 (2) – 77 21 – 5 – (130) (10) (114) 145 22 167 2,238 1,010 3,248 46 205 252 373 1,078 1,451 – – – – – – – – – – – – – – – – – – – – – – – – – – – 1 1 (1) – – – – – (1) – – – 528 438 965 23 5 – 45 (60) – 12 563 415 978 477 403 880 121 3 102 32 (144) (6) 108 492 496 988 86 – 86 (5) – – – – – (5) 81 – 81 2015 Total 5,187 4,507 9,695 27 106 122 79 (758) (19) (443) 5,041 4,211 9,252 4,548 3,280 7,828 274 5 29 260 (467) (1) 100 4,452 3,476 7,928 i F n a n c a i l s t a t e m e n t s 618 319 937 4 – – – (58) – (55) 632 250 882 – – – – – – – – – – – – – 618 319 937 632 250 882 9,735 7,788 17,523 9,493 7,687 17,180 – – – – – – – – – – – – – 3,834 2,830 6,663 255 – 29 215 (369) (1) 129 3,732 3,061 6,792 3,834 2,830 6,663 3,732 3,061 6,792 675 868 1,543 267 – – – (114) – 153 909 788 1,696 100 13 112 3 – – – (39) – (36) 76 1 77 775 881 1,656 984 788 1,773 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 232 398 160 26 At 31 December Developed Undeveloped 630 186 207 362 568 145 22 167 2,588 1,191 3,779 2,238 1,010 3,248 12 164 176 47 205 252 954 1,576 2,530 936 1,493 2,429 563 403 966 573 496 1,069 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent. d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 23 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. e Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to comparative periods. There was no impact on 2015 proved reserves totals. f Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 4 thousand barrels per day for equity-accounted entities. g Includes 30 million barrels of oil equivalent of natural gas consumed in operations, 25 million barrels of oil equivalent in subsidiaries, 5 million barrels of oil equivalent in equity-accounted entities. h Includes 425 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. i Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. j Includes 70 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 28 mmboe held through BP’s equity accounted interest in Taas-Yuryakh Neftegazodobycha. k Total proved reserves held as part of our equity interest in Rosneft is 6,796 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 28 million barrels of oil equivalent in Venezuela, 4 million barrels of oil equivalent in Vietnam and 6,764 million barrels of oil equivalent in Russia. BP Annual Report and Form 20-F 2016 203 Movements in estimated net proved reserves – continued Europe North America South America Africa Asia Australasia Rest of Europe UK USc Rest of North America Russia Rest of Asiad million barrels 2014 Total Crude oila b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione Sales of reserves-in-place At 31 Decemberf Developed Undeveloped Equity-accounted entities (BP share)g At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberh Developed Undeveloped 160 374 534 (41) 2 5 5 (17) – (46) 159 329 488 – – – – – – – – – – – – – 147 53 200 1,007 752 1,760 (68) – – – (15) – (82) 87 16 – – (123) (45) (66) 95 22 117 1,030 664 1,694 – – – – – – – – – – – – – – – – – – – – – – – – – – – 188 188 (16) – – – – – (16) 9 163 172 – 1 1 – – – – – – – – – 1 15 17 31 9 1 – 1 (5) (5) 1 10 22 32 316 314 630 4 12 – 10 (26) – – 316 314 630 331 331 661 326 336 662 316 180 495 20 3 – – (81) – (58) 317 120 437 2 2 4 (2) – – – – – (2) 2 – 2 317 182 499 319 120 439 – – – – – – – – – – – – – 2,970 1,858 4,828 213 – – 187 (297) – 103 2,997 1,933 4,930 2,970 1,858 4,828 2,997 1,933 4,930 320 202 522 96 – 12 8 (57) – 59 384 197 581 120 7 127 9 – – – (36) – (27) 89 11 101 440 209 649 473 208 682 49 19 69 (2) – – – (7) – (9) 40 19 59 – – – – – – – – – – – – – 49 19 69 40 19 59 2,013 1,785 3,798 85 23 17 13 (305) (50) (217) 2,044 1,538 3,581 3,407 2,182 5,590 224 12 – 197 (359) – 74 3,405 2,258 5,663 5,421 3,965 9,388 5,448 3,796 9,244 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 160 374 147 53 At 31 December Developed Undeveloped 534 200 159 329 488 95 22 117 1,007 752 1,760 1,030 664 1,694 – 189 189 9 164 173 a Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 65 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to comparative periods. There was no impact on 2014 proved reserves totals. e Includes 10 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. g Includes 38 million barrels of crude oil in respect of the 0.15% non-controlling interest in Rosneft. h Total proved crude oil reserves held as part of our equity interest in Rosneft is 4,961 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 30 million barrels in Venezuela and 4,930 million barrels in Russia. 204 BP Annual Report and Form 20-F 2016 Movements in estimated net proved reserves – continued Natural gas liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionc Sales of reserves-in-place At 31 Decemberd Developed Undeveloped Equity-accounted entities (BP share)e At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberf Developed Undeveloped Europe North America South America Africa Asia Australasia million barrels 2014 Total Rest of Europe 16 2 18 (2) – – – (2) – (4) 13 1 14 – – – – – – – – – – – – – UK 9 6 15 (6) – – – (1) – (6) 6 3 9 – – – – – – – – – – – – – Rest of North America Russia Rest of Asia – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – 14 28 43 – – – – (4) – (4) 11 28 39 – – – – – – – – – – – – – 14 28 43 11 28 39 4 15 20 (6) – – – (2) – (8) 5 7 12 8 8 16 – – – – – – (1) 15 – 15 13 23 36 20 7 27 – – – – – – – – – – – – – 94 21 115 (69) – – – – – (69) 30 16 46 94 21 115 30 16 46 – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – US 290 155 444 15 13 – – (27) (18) (17) 323 104 427 – – – – – – – – – – – – – 290 155 444 323 104 427 8 3 10 – – – – (1) – (1) 6 3 10 – – – – – – – – – – – – – 8 3 10 6 3 10 342 209 551 1 13 1 – (36) (18) (40) 364 146 510 103 29 131 (69) – – – – – (69) 46 16 62 444 238 682 410 163 572 i F n a n c a i l s t a t e m e n t s Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 9 6 16 2 At 31 December Developed Undeveloped 15 6 3 9 18 13 1 14 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 7 thousand barrels per day for equity-accounted entities. d Includes 12 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Total proved NGL reserves held as part of our equity interest in Rosneft is 47 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 46 million barrels in Russia. BP Annual Report and Form 20-F 2016 205 Movements in estimated net proved reserves – continued Europe North America South America Africa Asia Australasia Rest of Europe UK USc Rest of North America Russia Rest of Asiad million barrels 2014 Total Total liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione Sales of reserves-in-place At 31 Decemberf Developed Undeveloped Equity-accounted entities (BP share)g At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberh i Developed Undeveloped 169 380 549 (47) 2 5 5 (17) – (52) 166 332 497 – – – – – – – – – – – – – 163 55 217 1,297 907 2,204 (70) – – – (17) – (86) 101 28 – – (150) (63) (83) 108 23 131 1,352 769 2,121 – – – – – – – – – – – – – – – – – – – – – – – – – – – 188 188 (16) – – – – – (16) 9 163 172 – 1 1 – – – – – – – – – 1 29 46 74 9 1 – 1 (9) (5) (3) 21 50 71 316 314 630 4 12 – 10 (26) – – 316 314 630 345 359 704 337 364 701 320 195 515 14 3 – – (83) – (66) 322 127 449 10 10 20 (3) – – – – – (3) 17 – 17 331 205 535 339 127 466 – – – – – – – – – – – – – 3,063 1,879 4,943 144 – – 187 (297) – 34 3,028 1,949 4,976 3,063 1,879 4,943 3,028 1,949 4,976 320 202 523 96 – 12 8 (57) – 59 384 197 581 120 7 127 9 – – – (36) – (27) 89 11 101 440 209 650 473 208 682 57 22 78 (2) – – – (8) – (10) 46 22 68 – – – – – – – – – – – – – 2,354 1,994 4,348 86 36 18 14 (341) (68) (257) 2,407 1,684 4,092 3,510 2,210 5,721 155 12 – 197 (359) – 4 3,451 2,274 5,725 57 22 78 46 22 68 5,865 4,204 10,069 5,858 3,958 9,817 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 169 380 163 55 At 31 December Developed Undeveloped 549 217 166 332 497 108 23 131 1,297 907 2,204 1,352 769 2,121 – 188 189 9 164 173 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 65 million barrels upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to comparative periods. There was no impact on 2014 proved reserves totals. e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 7 thousand barrels per day for equity-accounted entities. f Also includes 21 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. h Includes 38 million barrels in respect of the non-controlling interest in Rosneft. i Total proved liquid reserves held as part of our equity interest in Rosneft is 5,007 million barrels, comprising 1 million barrels in Canada, 30 million barrels in Venezuela, less than 1 million barrels in Vietnam and 4,976 million barrels in Russia. 206 BP Annual Report and Form 20-F 2016 Movements in estimated net proved reserves – continued Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North America US Russia Rest of Asia billion cubic feet 2014 Total Natural gasa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionc Sales of reserves-in-place At 31 Decemberd Developed Undeveloped Equity-accounted entities (BP share)e At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionc Sales of reserves-in-place At 31 Decemberf g Developed Undeveloped 3,109 6,116 9,225 961 1,807 2,768 (258) 220 – 271 (792) – (559) (84) 28 – 4 (218) – (271) 2,352 6,313 8,666 901 1,597 2,497 – – – – – – – – – – – – – 1,364 747 2,111 230 135 365 4,171 5,054 9,225 (87) 23 – 69 (172) – (166) 38 – – – (3) – 35 767 – – 183 (390) – 560 1,228 717 1,945 400 – 400 4,674 5,111 9,785 1,519 3,671 5,190 (34) – 322 267 (165) – 389 1,688 3,892 5,580 72 14 86 1 – – – (18) – (17) 60 9 69 643 314 957 (260) 7 1 94 (30) – (189) 382 386 768 – – – – – – – – – – – – – 364 39 403 7,122 2,825 9,947 (46) – – – (40) – (85) (29) 582 5 2 (625) (266) (332) 300 19 318 7,168 2,447 9,615 – – – – – – – – – – – – – – – – – – – – – – – – – – 7,122 2,825 9,947 7,168 2,447 9,615 10 – 10 11 – – – (4) – 7 17 – 17 – 1 1 1 – – – – – – 1 1 1 10 1 11 18 1 18 3,932 1,755 5,687 17,660 16,527 34,187 (351) – – – (302) – (652) (1,050) 838 328 637 (2,177) (266) (1,691) 3,316 1,719 5,035 16,124 16,372 32,496 – – – – – – – – – – – – – i F n a n c a i l s t a t e m e n t s 5,837 5,951 11,788 720 23 – 252 (583) – 412 6,363 5,837 12,200 23,497 22,478 45,975 22,487 22,209 44,695 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 643 314 364 39 At 31 December Developed Undeveloped 957 403 382 386 768 300 19 318 4,473 6,863 11,336 3,581 7,030 10,610 1,191 1,942 3,133 1,301 1,597 2,897 4,171 5,054 9,225 4,674 5,111 9,785 1,591 3,685 5,276 1,748 3,901 5,648 3,932 1,755 5,687 3,316 1,719 5,035 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes 181 billion cubic feet of natural gas consumed in operations, 151 billion cubic feet in subsidiaries, 29 billion cubic feet in equity-accounted entities. d Includes 2,519 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Includes 91 billion cubic feet of natural gas in respect of the 0.18% non-controlling interest in Rosneft. g Total proved gas reserves held as part of our equity interest in Rosneft is 9,827 billion cubic feet, comprising 1 billion cubic feet in Canada, 14 billion cubic feet in Venezuela, 26 billion cubic feet in Vietnam and 9,785 billion cubic feet in Russia. BP Annual Report and Form 20-F 2016 207 Movements in estimated net proved reserves – continued Europe North America South America Africa Asia Australasia Rest of Europe UK USd Rest of North America Russia Rest of Asiae 2014 Total million barrels of oil equivalentc Total hydrocarbonsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionf g Sales of reserves-in-place At 31 Decemberh Developed Undeveloped Equity-accounted entities (BP share)i At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiong Sales of reserves-in-place At 31 Decemberj k Developed Undeveloped 280 434 714 (91) 3 6 21 (23) – (84) 232 398 630 – – – – – – – – – – – – – 225 62 287 2,525 1,394 3,919 (78) – – – (24) – (101) 96 129 1 1 (258) (109) (140) 160 26 186 2,588 1,191 3,779 – – – – – – – – – – – – – – – – – – – – – – – – – – 2 188 190 (14) – – – (1) – (14) 12 163 175 – 1 1 – – – – – – – – 1 1 564 1,100 1,664 (36) 39 – 47 (146) (5) (99) 426 1,139 1,565 552 442 994 (11) 16 – 22 (56) – (29) 528 438 965 486 507 993 (1) 8 – 1 (121) – (113) 477 403 880 50 33 83 4 – – – (1) – 3 86 – 86 – – – – – – – – – – – – – 3,782 2,751 6,533 276 – – 219 (365) – 130 3,834 2,830 6,663 3,782 2,751 6,533 3,834 2,830 6,663 582 835 1,417 735 324 5,399 4,844 1,059 10,243 90 – 68 54 (86) – 126 675 868 1,543 133 9 142 9 – – – (39) – (29) 100 13 112 715 844 1,559 775 881 1,656 (62) – – – (60) – (122) 618 319 937 – – – – – – – – – – – – – (96) 180 74 123 (717) (114) (548) 5,187 4,507 9,694 4,517 3,236 7,753 278 16 – 241 (460) – 75 4,548 3,280 7,828 735 324 9,916 8,080 1,059 17,996 618 319 937 9,735 7,788 17,523 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 280 434 225 62 At 31 December Developed Undeveloped 714 287 232 398 630 160 26 186 2,525 1,394 3,919 2,588 1,191 3,779 2 189 191 12 164 176 1,116 1,542 2,658 954 1,576 2,530 536 540 1,076 563 403 966 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent. d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 65 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. e Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to comparative periods. There was no impact on 2014 proved reserves totals. f Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 7 thousand barrels per day for equity-accounted entities. g Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 26 million barrels of oil equivalent in subsidiaries, 5 million barrels of oil equivalent in equity-accounted entities. h Includes 456 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. i Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. j Includes 54 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft. k Total proved reserves held as part of our equity interest in Rosneft is 6,702 million barrels of oil equivalent, comprising 1 million barrels of oil equivalent in Canada, 33 million barrels of oil equivalent in Venezuela, 5 million barrels of oil equivalent in Vietnam and 6,663 million barrels of oil equivalent in Russia 208 BP Annual Report and Form 20-F 2016 Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves The following tables set out the standardized measure of discounted future net cash flows, and changes therein, relating to crude oil and natural gas production from the group’s estimated proved reserves. This information is prepared in compliance with FASB Oil and Gas Disclosures requirements. Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of future production, the estimation of crude oil and natural gas reserves and the application of average crude oil and natural gas prices and exchange rates from the previous 12 months. Furthermore, both proved reserves estimates and production forecasts are subject to revision as further technical information becomes available and economic conditions change. BP cautions against relying on the information presented because of the highly arbitrary nature of the assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial statements. Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North America US Russia Rest of Asia $ million 2016 Total At 31 December Subsidiaries Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd e Standardized measure of discounted future net cash flowse f Equity-accounted entities (BP share)g Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd Standardized measure of discounted future net cash flowsh i 21,600 13,900 3,000 1,700 3,000 900 2,100 – – – – – – – – – – – – – – 5,400 3,000 700 1,300 400 200 200 Total subsidiaries and equity-accounted entities Standardized measure of 72,400 43,100 14,300 500 14,500 4,900 4,500 3,500 1,100 – (100) – 11,700 6,600 3,700 100 1,300 200 23,600 10,000 5,100 2,000 6,500 2,800 9,600 (100) 1,100 3,700 – – – – – – – 78,100 42,600 15,400 17,800 2,300 (600) 24,000 9,400 3,500 3,400 7,700 4,100 235,900 129,100 46,100 25,500 35,200 12,300 2,900 3,600 22,900 – – – – – – – – – – – – – – 34,400 16,500 3,800 3,600 10,500 6,100 4,400 – – – – – – – 159,900 84,300 13,200 10,100 52,300 30,700 1,900 1,200 700 – – – 21,600 – – – – – – – – 201,600 105,000 18,400 15,000 63,200 37,000 26,200 discounted future net cash flows 2,100 200 9,600 (100) 5,500 3,700 21,600 2,900 3,600 49,100 The following are the principal sources of change in the standardized measure of discounted future net cash flows: Sales and transfers of oil and gas produced, net of production costs Development costs for the current year as estimated in previous year Extensions, discoveries and improved recovery, less related costs Net changes in prices and production cost Revisions of previous reserves estimates Net change in taxation Future development costs Net change in purchase and sales of reserves-in-place Addition of 10% annual discount Total change in the standardized measure during the yearj Subsidiaries (15,200) 13,100 700 (25,500) 12,200 (2,500) 4,900 1,800 3,000 (7,500) Equity-accounted entities (BP share) (5,400) 3,500 900 (5,900) 1,200 900 (2,500) 2,900 2,800 (1,600) $ million Total subsidiaries and equity-accounted entities (20,600) 16,600 1,600 (31,400) 13,400 (1,600) 2,400 4,700 5,800 (9,100) a The marker prices used were Brent $42.82/bbl, Henry Hub $2.46/mmBtu. b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included. c Taxation is computed with reference to appropriate year-end statutory corporate income tax rates. d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. e In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and vice versa. This can result in the standardized measure of discounted future net cash flows being negative. Depending on the timing of those cash flows the effect of discounting may be to increase the discounted future net cash flows. f Non-controlling interests in BP Trinidad and Tobago LLC amounted to $300 million. g The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. h Non-controlling interests in Rosneft amounted to $1,608 million in Russia. i No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs. j Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes to US dollars are included within ‘Net changes in prices and production cost’. BP Annual Report and Form 20-F 2016 209 i F n a n c a i l s t a t e m e n t s Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves – continued Europe Rest of Europe UK North America Rest of North America US South America Africa Asia Australasia $ million 2015 Total Russia Rest of Asia At 31 December Subsidiaries Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd 27,500 15,700 4,700 2,900 4,200 1,900 7,800 5,300 700 800 1,000 300 98,100 56,300 18,800 3,100 19,900 7,400 7,200 4,200 1,700 – 1,300 900 20,100 8,600 7,000 1,700 2,800 900 32,800 12,000 8,100 3,300 9,400 4,300 Standardized measure of discounted future net cash flowse 2,300 700 12,500 400 1,900 5,100 – – – – – – – 65,200 35,900 18,200 3,800 7,300 3,700 32,000 15,200 4,500 4,000 8,300 4,400 290,700 153,200 63,700 19,600 54,200 23,800 3,600 3,900 30,400 Equity-accounted entities (BP share)f Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd Standardized measure of discounted future net cash flowsg h Total subsidiaries and equity-accounted entities Standardized measure of discounted – – – – – – – – – – – – – – – – – – – – – – – – – – – – 39,900 20,200 5,300 3,900 10,500 6,700 3,800 – – – – – – – 182,300 101,200 11,000 12,400 57,700 33,800 3,700 2,200 1,300 100 100 – 23,900 100 – – – – – – – 225,900 123,600 17,600 16,400 68,300 40,500 27,800 future net cash flows 2,300 700 12,500 400 5,700 5,100 23,900 3,700 3,900 58,200 The following are the principal sources of change in the standardized measure of discounted future net cash flows: Sales and transfers of oil and gas produced, net of production costs Development costs for the current year as estimated in previous year Extensions, discoveries and improved recovery, less related costs Net changes in prices and production cost Revisions of previous reserves estimates Net change in taxation Future development costs Net change in purchase and sales of reserves-in-place Addition of 10% annual discount Total change in the standardized measure during the yeari Equity-accounted entities (BP share) $ million Total subsidiaries and equity-accounted entities (7,300) 4,500 700 (24,700) 500 2,300 (100) 300 4,700 (19,100) (35,200) 19,500 1,300 (125,100) 14,000 40,900 3,100 (400) 12,700 (69,200) Subsidiaries (27,900) 15,000 600 (100,400) 13,500 38,600 3,200 (700) 8,000 (50,100) a The marker prices used were Brent $54.17/bbl, Henry Hub $2.59/mmBtu. b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included. c Taxation is computed with reference to appropriate year-end statutory corporate income tax rates. d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. e Non-controlling interests in BP Trinidad and Tobago LLC amounted to $600 million. f The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. g Non-controlling interests in Rosneft amounted to $93 million in Russia. h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs. i Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft to US dollars are included within ‘Net changes in prices and production cost’. 210 BP Annual Report and Form 20-F 2016 Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves – continued Europe Rest of Europe UK South America North America Rest of North America US Africa Asia Australasia $ million 2014 Total Russia Rest of Asia At 31 December Subsidiaries Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd Standardized measure of discounted future net cash flowse Equity-accounted entities (BP share)f Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd Standardized measure of discounted future net cash flowsg h 54,400 21,400 7,300 16,400 9,300 4,700 14,900 8,100 1,400 3,000 2,400 700 216,600 90,500 24,500 32,900 68,700 33,100 11,000 4,800 1,600 700 3,900 2,500 35,300 11,300 8,000 8,400 7,600 3,100 55,800 15,600 9,600 10,100 20,500 7,800 4,600 1,700 35,600 1,400 4,500 12,700 – – – – – – – 90,300 41,500 23,000 5,100 20,700 11,000 54,800 17,600 5,700 9,400 22,100 11,800 533,100 210,800 81,100 86,000 155,200 74,700 9,700 10,300 80,500 – – – – – – – – – – – – – – – – – – – – – – – – – – – – 47,300 22,300 5,700 6,700 12,600 8,000 4,600 – – – – – – – 349,200 200,000 17,400 24,200 107,600 65,500 10,200 7,800 2,100 100 200 – 42,100 200 – – – – – – – 406,700 230,100 25,200 31,000 120,400 73,500 46,900 Total subsidiaries and equity-accounted entities Standardized measure of i F n a n c a i l discounted future net cash flows 4,600 1,700 35,600 1,400 9,100 12,700 42,100 9,900 10,300 127,400 The following are the principal sources of change in the standardized measure of discounted future net cash flows: s t a t e m e n t s Sales and transfers of oil and gas produced, net of production costs Development costs for the current year as estimated in previous year Extensions, discoveries and improved recovery, less related costs Net changes in prices and production cost Revisions of previous reserves estimates Net change in taxation Future development costs Net change in purchase and sales of reserves-in-place Addition of 10% annual discount Total change in the standardized measure during the yeari Subsidiaries Equity-accounted entities (BP share) $ million Total subsidiaries and equity-accounted entities (30,500) 15,700 1,900 (17,000) 1,200 17,300 (4,500) (700) 8,800 (7,800) (6,900) 3,600 1,500 10,500 2,000 (4,900) (400) – 3,800 9,200 (37,400) 19,300 3,400 (6,500) 3,200 12,400 (4,900) (700) 12,600 1,400 a The marker prices used were Brent $101.27/bbl, Henry Hub $4.31/mmBtu. b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included. c Taxation is computed with reference to appropriate year-end statutory corporate income tax rates. d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. e Non-controlling interests in BP Trinidad and Tobago LLC amounted to $1,400 million. f The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. g Non-controlling interests in Rosneft amounted to $100 million in Russia. h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs. i Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft to US dollars are included within ‘Net changes in prices and production cost’. BP Annual Report and Form 20-F 2016 211 Operational and statistical information The following tables present operational and statistical information related to production, drilling, productive wells and acreage. Figures include amounts attributable to assets held for sale. Crude oil and natural gas production The following table shows crude oil, natural gas liquids and natural gas production for the years ended 31 December 2016, 2015 and 2014. Production for the yeara b Europe North America South America Africa Asia Australasia Total Subsidiariese Crude oilf 2016 2015 2014 Natural gas liquids 2016 2015 2014 Natural gasg 2016 2015 2014 Equity-accounted entities (BP share) Crude oilf 2016 2015 2014 Natural gas liquids 2016 2015 2014 Natural gasg 2016 2015 2014 Rest of Europe 24 38 41 4 5 5 US 335 323 347 56 56 63 82 111 102 1,656 1,528 1,519 7 – – – – – 12 – – – – – – – – – – – Rest of North America 13 3 – – – – 10 10 10 – – – – – – – – – UK 79 72 46 6 7 2 170 155 71 – – – – – – – – – 10 12 13 8 11 12 1,689 1,922 2,147 65 68 65 1 3 3 449 435 402 Russiac – – – – – – – – – 840 809 816 4 4 5 263 270 222 5 7 5 513 589 513 – – – 4 3 4 18 – 7 1,279 1,195 1,084 Rest of Asiad 204 199 147 – 1 – 363 380 408 102 97 98 – – – 15 21 21 thousand barrels per day 16 17 19 943 933 834 thousand barrels per day 3 3 3 82 88 91 million cubic feet per day 820 801 814 5,302 5,495 5,585 thousand barrels per day – – – 1,015 974 979 thousand barrels per day – – – 8 10 12 million cubic feet per day – – – 1,773 1,651 1,515 a Production excludes royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Amounts reported for Russia include BP’s share of Rosneft worldwide activities, including insignificant amounts outside Russia. d Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to comparative periods. e All of the oil and liquid production from Canada is bitumen. f Crude oil includes condensate. g Natural gas production excludes gas consumed in operations. 212 BP Annual Report and Form 20-F 2016 Operational and statistical information – continued Productive oil and gas wells and acreage The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil and natural gas acreage in which the group and its equity-accounted entities had interests as at 31 December 2016. A ‘gross’ well or acre is one in which a whole or fractional working interest is owned, while the number of ‘net’ wells or acres is the sum of the whole or fractional working interests in gross wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is the acreage within the boundary of a field, on which development wells have been drilled, which could produce the reserves; while undeveloped acres are those on which wells have not been drilled or completed to a point that would permit the production of commercial quantities, whether or not such acres contain proved reserves. Europe North America South America Africa Asia Australasia Totalb Rest of Europe UK Number of productive wells at 31 December 2016 Oil wellsc Gas wellsd – gross – net – gross – net 126 80 55 23 47 14 1 – Oil and natural gas acreage at 31 December 2016 Developed Undevelopede – gross – net – gross – net 133 76 1,383 978 37 11 1,360 517 Rest of North America 150 33 302 149 166 75 12,806 6,353 US 2,472 849 23,608 10,064 6,462 3,452 5,883 4,318 Russiaa 45,585 9,003 788 156 678 462 160 67 Rest of Asia 2,002 425 42 11 705 277 31,345 21,801 5,024 941 380,441 74,103 1,536 273 10,018 2,501 4,994 2,736 902 343 1,330 412 20,757 6,404 12 2 66 14 56,066 13,604 25,924 10,827 thousands of acres 173 41 11,617 6,340 15,566 5,558 475,610 123,315 a Based on information received from Rosneft as at 31 December 2016. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes approximately 8,367 gross (1,632 net) multiple completion wells (more than one formation producing into the same well bore). d Includes approximately 2,825 gross (1,437 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well. e Undeveloped acreage includes leases and concessions. Net oil and gas wells completed or abandoned The following table shows the number of net productive and dry exploratory and development oil and natural gas wells completed or abandoned in the years indicated by the group and its equity-accounted entities. Productive wells include wells in which hydrocarbons were encountered and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be incapable of producing hydrocarbons in sufficient quantities to justify completion. Europe North America South America Africa Asia Australasia Totala i F n a n c a i l s t a t e m e n t s Rest of North America Russia Rest of Asia 2016 Exploratory Productive Dry Development Productive Dry 2015 Exploratory Productive Dry Development Productive Dry 2014 Exploratory Productive Dry Development Productive Dry UK 0.3 1.0 3.4 0.8 – – 1.6 – 2.9 0.5 3.1 – Rest of Europe 0.4 0.3 1.4 – – – US 0.5 4.7 145.6 – 4.0 – 0.4 – 235.6 – – – 5.3 7.9 – – – – – – – – – – 0.6 – 99.8 0.6 1.1 0.4 143.1 2.3 3.7 1.4 a Because of rounding, some totals may not exactly agree with the sum of their component parts. 1.8 0.8 294.1 – 1.5 0.1 100.5 3.9 2.1 1.5 20.2 2.0 2.6 1.0 20.7 1.3 0.7 1.6 13.8 1.0 3.4 – 88.5 – 4.5 – 91.4 – 5.3 – 76.2 – 1.6 0.3 55.2 1.0 – – 51.2 – 0.6 1.4 46.3 0.4 – – 0.5 – – 0.2 0.9 – – 0.2 – 0.4 8.9 7.8 414.6 4.4 12.2 1.6 544.7 3.5 18.5 13.0 537.3 6.6 BP Annual Report and Form 20-F 2016 213 Operational and statistical information – continued Drilling and production activities in progress The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the group and its equity-accounted entities as of 31 December 2016. Suspended development wells and long-term suspended exploratory wells are also included in the table. Europe North America South America Africa Asia Australasia Totala At 31 December 2016 Exploratory Gross Net Development Gross Net UK 1.0 0.9 7.0 2.8 Rest of Europe 0.1 – 1.0 0.3 US 7.0 4.1 266.0 113.9 Rest of North America 1.0 0.4 14.0 7.0 Russia Rest of Asia 2.0 1.6 22.0 14.3 4.0 2.5 39.0 19.1 – – – – 2.0 1.3 41.0 13.5 – – 5.0 0.8 17.1 10.8 395.0 171.7 a Because of rounding, some totals may not exactly agree with the sum of their component parts. 214 BP Annual Report and Form 20-F 2016 Parent company financial statements of BP p.l.c. Company balance sheet At 31 December Non-current assets Investments Receivables Defined benefit pension plan surpluses Current assets Receivables Cash and cash equivalents Total assets Current liabilities Payables Non-current liabilities Payables Deferred tax liabilities Defined benefit pension plan deficits Total liabilities Net assets Capital and reservesa Profit and loss account Brought forward Profit (loss) for the year Other movements Called-up share capital Share premium account Other capital and reserves Note 2016 $ million 2015 2 3 4 3 5 5 6 4 7 166,283 2,951 528 139,241 – 2,516 169,762 141,757 487 50 537 1,062 – 1,062 170,299 142,819 4,225 212 34,432 179 219 34,830 39,055 6,741 877 227 7,845 8,057 131,244 134,762 111,521 (375) (6,648) 104,498 5,284 12,219 9,243 115,810 571 (4,860) 111,521 5,049 10,234 7,958 131,244 134,762 a See Statement of changes in equity on page 216 for further information. The financial statements on pages 215-238 were approved and signed by the group chief executive on 6 April 2017 having been duly authorized to do so by the board of directors: R W Dudley Group Chief Executive The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 215 i F n a n c a i l s t a t e m e n t s Company statement of changes in equitya At 1 January 2016 Loss for the year Other comprehensive income Total comprehensive income Dividends Share-based payments, net of taxb At 31 December 2016 At 1 January 2015 Profit for the year Other comprehensive income Total comprehensive income Dividends Share-based payments, net of tax At 31 December 2015 Capital redemption reserve Merger reserve Treasury shares Foreign currency translation reserve Profit and loss account $ million Total equity 1,413 26,509 (19,964) – 111,521 134,762 Share capital 5,049 – – – 137 98 Share premium account 10,234 – – – (137) 2,122 – – – – – – – – – – – – – – 1,521 5,284 12,219 1,413 26,509 (18,443) 5,023 10,260 1,413 26,509 (20,719) – – – 26 – – – – (26) – – – – – – – – – – – – – – – 755 – (236) (236) – – (236) 31 – (31) (31) – – (375) (1,269) (1,644) (4,611) (768) (375) (1,505) (1,880) (4,611) 2,973 104,498 131,244 115,810 138,327 571 1,894 2,465 (6,659) (95) 571 1,863 2,434 (6,659) 660 5,049 10,234 1,413 26,509 (19,964) – 111,521 134,762 a See Note 8 for further information. b Share capital and share premium amounts relate to the issue of new ordinary shares to the government of Abu Dhabi. See Notes 3 and 10 for further information. Movements in treasury shares relate to employee share-based payment plans. The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 216 BP Annual Report and Form 20-F 2016 Notes on financial statements 1. Significant accounting policies, judgements, estimates and assumptions Authorization of financial statements and statement of compliance with Financial Reporting Standard 101 ‘Reduced Disclosure Framework’ (FRS 101) The financial statements of BP p.l.c. for the year ended 31 December 2016 were approved and signed by the group chief executive on 6 April 2017 having been duly authorized to do so by the board of directors. The company meets the definition of a qualifying entity under Financial Reporting Standard 100 ‘Application of Financial Reporting Requirements’ (FRS 100) issued by the Financial Reporting Council. Accordingly, these financial statements have been prepared in accordance with FRS 101 and in accordance with the provisions of the UK Companies Act 2006. Basis of preparation The financial statements have been prepared on a going concern basis and in accordance with the Companies Act 2006 and applicable UK accounting standards. The financial statements have been prepared under the historical cost convention. Historical cost is generally based on the fair value of the consideration given in exchange for the assets. As permitted by FRS 101, the company has taken advantage of the disclosure exemptions available in relation to: (a) (b) (c) (d) (e) (f) the requirements of IFRS 7 ‘Financial Instruments: Disclosures’; the requirements of paragraphs 10(d), 10(f), 16, 38A, 38B, 38C, 38D, 40A, 40B, 40C, 40D, 111 and 134 to 136 of IAS 1 ‘Presentation of Financial Statements’; the requirements of IAS 7 ‘Statement of Cash Flows’; the requirements of paragraphs 30 and 31 of IAS 8 ‘Accounting Policies, Changes in Accounting Estimates and Errors’ in relation to standards not yet effective; the requirements of paragraphs 17 and 18A of IAS 24 ‘Related Party Disclosures’; and the requirements of IAS 24 ‘Related Party Disclosures’ to disclose related party transactions entered into between two or more members of a group, provided that any subsidiary which is a party to the transaction is wholly owned by such a member. Where required, equivalent disclosures are given in the consolidated financial statements of BP p.l.c. As permitted by Section 408 of the Companies Act 2006, the income statement of the company is not presented as part of these financial statements. As permitted by FRS 101 from 1 January 2016, the company has adopted the balance sheet format set out in IAS 1 rather than the Companies Act 2006 format that was previously used. This provides greater consistency with the consolidated financial statements. The financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where otherwise indicated. Significant accounting policies: use of judgements, estimates and assumptions Inherent in the application of many of the accounting policies used in preparing the financial statements is the need for management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and assumptions used. The accounting judgements and estimates that could have a significant impact on the results of the company are set out in boxed text below, and should be read in conjunction with the information provided in the Notes on financial statements. Investments Investments in subsidiaries are recorded at cost. The company assesses investments for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If any such indication of impairment exists, the company makes an estimate of its recoverable amount. Where the carrying amount of an investment exceeds its recoverable amount, the investment is considered impaired and is written down to its recoverable amount. Significant estimate or judgement: investments The recoverable amount, which is often the fair value less costs to sell, may be based upon discounted future cash flows. The assumptions underlying these calculations, such as the discount rate, future oil and gas prices, and other asset specific factors, are judgemental. Further information on the assumptions that are used in such calculations is included in Note 1 to the consolidated financial statements. Foreign currency translation The functional and presentation currency of the financial statements is US dollars. Transactions in foreign currencies are initially recorded in the functional currency by applying the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included in the income statement. Exchange adjustments arising when the opening net assets and the profits for the year retained by a non-US dollar functional currency branch are translated into US dollars are recognized in a separate component of equity and reported in other comprehensive income. Income statement transactions are translated into US dollars using the average exchange rate for the reporting period. Financial guarantees The company enters into financial guarantee contracts with its subsidiaries. At the inception of a financial guarantee contract, a liability is recognized initially at fair value and then subsequently at the higher of the estimated loss and amortized cost. Where a guarantee is issued for a premium, a receivable of an amount equal to the liability is initially recognized. Subsequently, the liability and receivable reduce by the amount of consideration received, which is recognized in the income statement. Where a guarantee is issued without a premium, the fair value is recognized as additional investment in the entity to which the guarantee relates. The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 217 i F n a n c a i l s t a t e m e n t s 1. Significant accounting policies, judgements, estimates and assumptions – continued Share-based payments Equity-settled transactions The cost of equity-settled transactions with employees of the company and other members of the group is measured by reference to the fair value of the equity instruments on the date on which they are granted and is recognized as an expense over the vesting period, which ends on the date on which the employees become fully entitled to the award. A corresponding credit is recognized within equity. Fair value is determined by using an appropriate, widely used, valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of the shares of the company (market conditions). Non-vesting conditions, such as the condition that employees contribute to a savings-related plan, are taken into account in the grant-date fair value, and failure to meet a non-vesting condition, where this is within the control of the employee, is treated as a cancellation and any remaining unrecognized cost is expensed. For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are measured at the fair value of the goods or services received. Cash-settled transactions The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the corresponding liability which is recognized on the balance sheet. The liability is remeasured at fair value at each balance sheet date until settlement, with changes in fair value recognized in the income statement. Pensions The cost of providing benefits under the company’s defined benefit plans is determined separately for each plan using the projected unit credit method, which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to determine the present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company becomes committed to a change. Net interest expense relating to pensions, which is recognized in the income statement, represents the net change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking into account expected changes in the obligation or plan assets during the year. Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not subsequently reclassified to profit and loss. The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the present value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, typically by way of refund. Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable. Significant estimate: pensions Accounting for defined benefit pensions involves making significant estimates about uncertain events, including retirement dates, salary levels at retirement, mortality rates, determination of discount rates for measuring plan obligations and net interest expense and assumptions for inflation rates. Assumptions about these variables are based on the environment in each country. The assumptions used may vary from year to year, which would affect future net income and net assets. Any differences between these assumptions and the actual outcome also affect future net income and net assets. Pension assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the company’s balance sheet, and pension expense for the following year. The assumptions used are provided in Note 4. In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. Mortality assumptions reflect best practice in the UK and have been chosen with regard to applicable published tables adjusted where appropriate to reflect the experience of the plan and an extrapolation of past longevity improvements into the future. A sensitivity analysis of the impact of changes in the mortality assumptions on the benefit expense and obligation is provided in Note 4. Income taxes Income tax expense represents the sum of current tax and deferred tax. Interest and penalties relating to income tax are also included in the income tax expense. Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity. Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are taxable or deductible in other periods as well as items that are never taxable or deductible. The company’s liability for current tax is calculated using tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for taxable temporary differences. Deferred tax assets are only recognized to the extent that it is probable that they will be realized in the future. The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 218 BP Annual Report and Form 20-F 2016 1. Significant accounting policies, judgements, estimates and assumptions – continued Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and liabilities are not discounted. Significant estimate or judgement: deferred tax Management judgement is required to determine the amount of deferred tax assets that can be recognized, based upon the likely timing and level of future taxable profits. Financial assets All financial assets held by the company are classified as loans and receivables. Financial assets include cash and cash equivalents, receivables and other investments. The company determines the classification of its financial assets at initial recognition. Financial assets are recognized initially at fair value, normally being the transaction price plus directly attributable transaction costs. Loans and receivables Loans and receivables are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in income when the loans and receivables are derecognized or impaired, as well as through the amortization process. Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and have a maturity of three months or less from the date of acquisition. Financial liabilities All financial liabilities held by the company are classified as financial liabilities measured at amortized cost. Financial liabilities include other payables, accruals, and most items of finance debt. The company determines the classification of its financial liabilities at initial recognition. Financial liabilities measured at amortized cost All financial liabilities are initially recognized at fair value, net of transaction costs. For interest-bearing loans and borrowings this is the fair value of the proceeds received net of issue costs associated with the borrowing. After initial recognition, financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs, and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively. This category of financial liabilities includes payables and finance debt. 2. Investments Cost At 1 January 2016 Additions Disposals At 31 December 2016 Amounts provided At 1 January 2016 At 31 December 2016 Cost At 1 January 2015 Additions Disposals At 31 December 2015 Amounts provided At 1 January 2015 At 31 December 2015 At 31 December 2016 At 31 December 2015 Subsidiaries Associates Shares Shares Total $ million 139,313 32,833 (5,791) 166,355 74 74 139,313 2,800 (2,800) 139,313 74 74 166,281 139,239 2 – – 2 – – 2 – – 2 – – 2 2 139,315 32,833 (5,791) 166,357 74 74 139,315 2,800 (2,800) 139,315 74 74 166,283 139,241 The company increased its investment in BP Holdings North America Limited by $27,100 million and its investment in BP International Limited by $5,727 million during 2016. It also disposed of its $5,727-million investment in BP Corporate Holdings Limited. The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 219 i F n a n c a i l s t a t e m e n t s 2. Investments – continued The more important subsidiaries of the company at 31 December 2016 and the percentage holding of ordinary share capital (to the nearest whole number) are set out below. For a full list of related undertakings see Note 14. Subsidiaries International BP Global Investments BP International Burmah Castrol Canada BP Holdings Canada US BP Holdings North America % Country of incorporation Principal activities 100 100 100 England & Wales England & Wales Scotland Investment holding Integrated oil operations Lubricants 100 England & Wales Investment holding 100 England & Wales Investment holding The carrying value of the investment in BP International Limited at 31 December 2016 was $76,152 million (2015 $70,425 million). 3. Receivables Amounts receivable from subsidiariesa Amounts receivable from associates Other receivables 2016 Non- current 2,951 – – 2,951 $ million 2015 Current Non-current 1,054 5 3 1,062 – – – – Current 480 4 3 487 a 2016 non-current receivables includes a promissory note issued by BP (Abu Dhabi) Limited in consideration for the issue of BP p.l.c. ordinary shares to the government of Abu Dhabi. See Note 10 for further information. 4. Pensions The primary pension arrangement is a funded final salary pension plan in the UK under which retired employees draw the majority of their benefit as an annuity. This pension plan is governed by a corporate trustee whose board is composed of four member-nominated directors, four company-nominated directors, an independent director, and an independent chairman nominated by the company. The trustee board is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as investment policies of the plan. The plan is closed to new joiners but remains open to ongoing accrual for current members. New joiners are eligible for membership of a defined contribution plan. The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall due. During 2016 the aggregate level of contributions was $539 million (2015 $754 million). The aggregate level of contributions in 2017 is expected to be approximately $652 million, and includes contributions we expect to be required to make by law or under contractual agreements, as well as an allowance for discretionary funding. For the primary plan there is a funding agreement between the company and the trustee. On an annual basis the latest funding position is reviewed and a schedule of contributions covering the next seven years is agreed. The funding agreement can be terminated unilaterally by either party with two years’ notice. Contractually committed funding therefore represents nine years of future contributions, which amounted to $5,761 million at 31 December 2016, of which $2,410 million relates to past service. The surplus relating to the primary pension plan is recognized on the balance sheet on the basis that the company is entitled to a refund of any remaining assets once all members have left the plan. The obligation and cost of providing the pension benefits is assessed annually using the projected unit credit method. The date of the most recent actuarial review was 31 December 2016. The principal plans are subject to a formal actuarial valuation every three years in the UK. The most recent formal actuarial valuation of the primary pension plan was as at 31 December 2014. The material financial assumptions used to estimate the benefit obligations of the plans are set out below. The assumptions are reviewed by management at the end of each year, and are used to evaluate accrued pension benefits at 31 December and pension expense for the following year. Financial assumptions used to determine benefit obligation Discount rate for pension plan liabilities Rate of increase in salaries Rate of increase for pensions in payment Rate of increase in deferred pensions Inflation for pension plan liabilities Financial assumptions used to determine benefit expense Discount rate for pension plan service costs Discount rate for pension plan other finance expense Inflation for pension plan service costs 2016 2.7 4.6 3.0 3.0 3.2 2016 4.0 3.9 3.1 % 2015 3.9 4.4 3.0 3.0 3.0 % 2015 3.9 3.6 3.1 The discount rate assumption is based on third-party AA corporate bond indices and we use yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumption is based on the difference between the yields on index-linked and fixed-interest long- term government bonds. The inflation assumption is used to determine the rate of increase for pensions in payment and the rate of increase in The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 220 BP Annual Report and Form 20-F 2016 4. Pensions – continued deferred pensions. For 2016, the assumed rate of increase for the UK plans also reflects the probability of exceeding a cap or breaching a floor for pension increases as set out in the plan rules; this change resulted in a reduction in the pension obligation of $865 million. The assumption for the rate of increase in salaries is based on our inflation assumption plus an allowance for expected long-term real salary growth. This includes allowance for promotion-related salary growth of 0.7%. In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best practice in the UK, and have been chosen with regard to applicable published tables adjusted to reflect the experience of the plans and an extrapolation of past longevity improvements into the future. For the primary pension plan the mortality assumptions are as follows: Mortality assumptions Life expectancy at age 60 for a male currently aged 60 Life expectancy at age 60 for a male currently aged 40 Life expectancy at age 60 for a female currently aged 60 Life expectancy at age 60 for a female currently aged 40 2016 28.0 30.0 29.5 31.9 Years 2015 28.5 31.0 29.5 31.9 The assets of the primary plan are held in a trust. The primary objective of the trust is to accumulate pools of assets sufficient to meet the obligations of the plan. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management. A significant proportion of the assets are held in equities, owing to a higher expected level of return over the long term of such assets with an acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment portfolios are highly diversified. For the primary plan there is an agreement with the trustee to reduce the proportion of plan assets held as equities and increase the proportion held as bonds over time, with a view to better matching the asset portfolio with the pension liabilities. During 2016, the plan switched 4% from equities to bonds. The primary plan uses a liability driven investment (LDI) approach for part of the portfolio, a form of investing designed to match the movement in pension plan assets with the impact of interest rate changes and inflation assumption changes on the projected benefit obligation. The company’s asset allocation policy for the primary plan is as follows: Asset category Total equity (including private equity) Bonds/cash (including LDI) Property/real estate % 58 35 7 i F n a n c a i l The amounts invested under the LDI programme as at 31 December 2016 were $423 million (2015 $329 million) of government-issued nominal bonds and $9,384 million (2015 $6,421 million) of index-linked bonds. This is partly funded by short-term sale and repurchase agreements, proceeds from which are shown separately in the table below. In addition, the primary plan has entered into interest rate swaps in the year to offset the long-term fixed interest rate exposure for $4,450 million (2015 $2,651 million) of the corporate bond portfolio. At 31 December 2016 the fair value liability of these swaps was $144 million (2015 $17 million fair value asset) and is included in other assets in the table below. s t a t e m e n t s The primary plan does not invest directly in either securities or property / real estate of the company or of any subsidiary. The fair values of the various categories of assets held by the defined benefit plans at 31 December are presented in the table below, including the effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on page 222. Fair value of pension plan assets Listed equities – developed markets – emerging markets Private equity Government issued nominal bondsa Government issued index-linked bondsa Corporate bondsa Propertyb Cash Other Debt (repurchase agreements) used to fund liability driven investments a Bonds held are denominated in sterling. b Property held is all located in the United Kingdom. 2016 $ million 2015 11,494 2,549 2,754 489 9,384 4,042 1,970 547 (68) (2,981) 30,180 13,474 2,305 2,933 393 6,425 4,357 2,453 564 110 (1,791) 31,223 The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 221 4. Pensions – continued Analysis of the amount charged to profit before interest and taxation Current service costa Past service costb Operating charge relating to defined benefit plans Payments to defined contribution plan Total operating charge Interest income on plan assetsc Interest on plan liabilities Other finance income (expense) Analysis of the amount recognized in other comprehensive income Actual asset return less interest income on pension plan assets Change in financial assumptions underlying the present value of the plan liabilities Change in demographic assumptions underlying the present value of plan liabilities Experience gains and losses arising on the plan liabilities Remeasurements recognized in other comprehensive income 2016 333 17 350 30 380 1,086 (1,004) 82 4,422 (6,926) 430 55 (2,019) $ million 2015 485 12 497 31 528 1,124 (1,144) (20) 315 2,054 – 321 2,690 a The costs of managing the fund’s investments are treated as being part of the investment return, the costs of administering our pensions plan benefits are included in current service cost. b Past service cost represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes. c The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above. Movements in benefit obligation during the year Benefit obligation at 1 January Exchange adjustments Operating charge relating to defined benefit plans Interest cost Contributions by plan participantsa Benefit payments (funded plans)b Benefit payments (unfunded plans)b Remeasurements Benefit obligation at 31 December Movements in fair value of plan assets during the year Fair value of plan assets at 1 January Exchange adjustments Interest income on plan assetsc Contributions by plan participantsa Contributions by employers (funded plans) Benefit payments (funded plans)b Remeasurementsc Fair value of plan assets at 31 Decemberd e Surplus at 31 December Represented by Asset recognized Liability recognized The surplus may be analysed between funded and unfunded plans as follows Funded Unfunded The defined benefit obligation may be analysed between funded and unfunded plans as follows Funded Unfunded 2016 $ million 2015 28,934 (5,680) 350 1,004 18 (1,192) (4) 6,441 29,871 31,223 (5,916) 1,086 18 539 (1,192) 4,422 30,180 309 528 (219) 309 519 (210) 309 32,357 (1,446) 497 1,144 32 (1,269) (6) (2,375) 28,934 31,773 (1,506) 1,124 32 754 (1,269) 315 31,223 2,289 2,516 (227) 2,289 2,506 (217) 2,289 (29,661) (210) (28,717) (217) (29,871) (28,934) a Most of the contributions made by plan participants were made under salary sacrifice. b The benefit payments amount shown above comprises $1,177 million benefits plus $19 million of plan expenses incurred in the administration of the benefit. c The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above. d Reflects $29,970 million of assets held in the BP Pension Fund (2015 $31,030 million) and $165 million held in the BP Global Pension Trust (2015 $147 million), with $38 million representing the company’s share of Merchant Navy Officers Pension Fund (2015 $37 million) and $7 million of Merchant Navy Ratings Pension Fund (2015 $9 million). e The fair value of plan assets includes borrowings related to the LDI programme as described on page 221. The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 222 BP Annual Report and Form 20-F 2016 4. Pensions – continued Sensitivity analysis The discount rate, inflation, salary growth and the mortality assumptions all have a significant effect on the amounts reported. A one-percentage point change, in isolation, in certain assumptions as at 31 December 2016 for the company’s plans would have had the effects shown in the table below. The effects shown for the expense in 2017 comprise the total of current service cost and net finance income or expense. Discount ratea Effect on pension expense in 2017 Effect on pension obligation at 31 December 2016 Inflation rateb Effect on pension expense in 2017 Effect on pension obligation at 31 December 2016 Salary growth Effect on pension expense in 2017 Effect on pension obligation at 31 December 2016 $ million One percentage point Increase Decrease (288) (5,294) 248 7,067 219 4,628 75 1,043 (185) (4,085) (66) (947) a The amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation. b The amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions. One additional year of longevity in the mortality assumptions would increase the 2017 pension expense by $38 million and the pension obligation at 31 December 2016 by $1,092 million. Estimated future benefit payments and the weighted average duration of defined benefit obligations The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2026 and the weighted average duration of the defined benefit obligations at 31 December 2016 are as follows: Estimated future benefit payments 2017 2018 2019 2020 2021 2022-2026 Weighted average duration 5. Payables Amounts payable to subsidiaries Accruals and deferred income Other payables $ million 904 947 984 1,003 1,039 5,576 Years 20.4 $ million 2015 Non- current 6,708 33 – 6,741 2016 Non- current 34,389 43 – 34,432 Current 3,904 129 192 4,225 Current 100 81 31 212 Included in non-current amounts payable to subsidiaries after one year is an interest-bearing payable of $4,236 million (2015 $4,236 million) with BP International Limited, with interest being charged based on a 3 month USD LIBOR rate plus 55 basis points and a maturity date of December 2021. Also included is an interest-bearing payable of $2,300 million (2015 $2,311 million) with BP Finance plc, with interest being charged based on a 1 year USD LIBOR rate and a maturity date of April 2020. Non-current amounts payable to subsidiaries also includes an interest-bearing payable of $27,100 million (2015 $nil) with BP International Limited with interest being charged based on a 3 month USD LIBOR rate plus 65 basis points and a maturity date of May 2023. The maturity profile of the financial liabilities included in the balance sheet at 31 December is shown in the table below. These amounts are included within payables. Due within 1 to 2 years 2 to 5 years More than 5 years 2016 206 6,936 27,290 34,432 $ million 2015 75 85 6,581 6,741 The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 223 i F n a n c a i l s t a t e m e n t s 6. Taxation Tax charge included in total comprehensive income Deferred tax Origination and reversal of timing differences in the current year This comprises: Taxable temporary differences relating to pensions Deferred tax Deferred tax liability Pensions Net deferred tax liability Analysis of movements during the year At 1 January Charge for the year on ordinary activities Charge (credit) for the year in other comprehensive income At 31 December 2016 (698) (698) 179 179 877 52 (750) 179 $ million 2015 877 877 877 877 – 81 796 877 At 31 December 2016, deferred tax assets of $82 million on other temporary differences and $8 million relating to pensions (2015 $65 million relating to other temporary differences and $8 million relating to pensions) were not recognized as it is not considered probable that suitable taxable profits will be available in the company from which the future reversal of the underlying temporary differences can be deducted. It is anticipated that the reversal of these temporary differences will benefit other group companies in the future. 7. Called-up share capital The allotted, called-up and fully paid share capital at 31 December was as follows: Issued 8% cumulative first preference shares of £1 eacha 9% cumulative second preference shares of £1 eacha Ordinary shares of 25 cents each At 1 January Issue of new shares for the scrip dividend programme Issue of new shares – otherb 31 December Shares thousand 7,233 5,473 20,108,771 548,005 392,920 21,049,696 2016 $ million 12 9 21 5,028 137 98 5,263 5,284 Shares thousand 7,233 5,473 20,005,961 102,810 – 20,108,771 2015 $ million 12 9 21 5,002 26 – 5,028 5,049 a The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of preference shares. b Relates to the issue of new ordinary shares to the government of Abu Dhabi. See Notes 3 and 10 for further information. Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each. In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value. Treasury sharesa At 1 January Purchases for settlement of employee share plans Shares re-issued for employee share-based payment plans At 31 December Of which – shares held in treasury by BP – shares held in ESOP trusts – shares held by BP’s US plan administratorb 2016 2015 Shares thousand Nominal value $ million Shares thousand Nominal value $ million 1,756,327 9,631 (151,339) 1,614,619 1,576,411 21,432 16,814 439 2 (38) 403 394 5 4 1,811,297 51,142 (106,112) 1,756,327 1,727,763 18,453 10,111 453 13 (27) 439 432 4 3 a See Note 8 for definition of treasury shares. b Held by the company in the form of ADSs to meet the requirements of employee share-based payment plans in the US. For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by BP during the year, representing 8.6% (2015 8.9%) of the called-up ordinary share capital of the company. During 2016, the movement in shares held in treasury by BP represented less than 0.8% (2015 less than 0.2%) of the ordinary share capital of the company. The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 224 BP Annual Report and Form 20-F 2016 8. Capital and reserves See statement of changes in equity for details of all reserves balances. Share capital The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury shares. Share premium account The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares. Capital redemption reserve The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled. Merger reserve The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in an acquisition made by the issue of shares. Treasury shares Treasury shares represent BP shares repurchased and available for specific and limited purposes. For accounting purposes, shares held in Employee Share Ownership Plans (ESOPs) and by BP’s US share plan administrator to meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are therefore included in the financial statements as treasury shares. The ESOPs are funded by the company and have waived their rights to dividends in respect of such shares held for future awards. Until such time as the shares held by the ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders’ equity. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the company. Foreign currency translation reserve The foreign currency translation reserve records exchange differences arising from the translation of the financial information of the foreign currency branch. Upon disposal of foreign operations, the related accumulated exchange differences are recycled to the income statement. Profit and loss account The balance held on this reserve is the accumulated retained profits of the company. The profit and loss account reserve includes $24,107 million (2015 $24,107 million), the distribution of which is limited by statutory or other restrictions. The financial statements for the year ended 31 December 2016 do not reflect the dividend announced on 7 February 2017 and paid in March 2017; this will be treated as an appropriation of profit in the year ended 31 December 2017. i F n a n c a i l 9. Financial guarantees The company has issued guarantees under which the maximum aggregate liabilities at 31 December 2016 were $71,443 million (2015 $51,775 million), the majority of which relate to finance debt of subsidiaries. The increase in 2016 primarily relates to guarantees of subsidiaries’ liabilities under the Consent Decree between the United States, the Gulf states and BP and under the settlement agreement with the Gulf states in relation to the Gulf of Mexico oil spill. The company has also issued uncapped indemnities and guarantees, including a guarantee of subsidiaries’ liabilities under the Plaintiffs’ Steering Committee agreement relating to the Gulf of Mexico oil spill. Uncapped indemnities and guarantees are also issued in relation to potential losses arising from environmental incidents involving ships leased and operated by a subsidiary. s t a t e m e n t s 10. Share-based payments Effect of share-based payment transactions on the company’s result and financial position Total expense recognized for equity-settled share-based payment transactions Total (credit) expense recognized for cash-settled share-based payment transactions Total expense recognized for share-based payment transactions Closing balance of liability for cash-settled share-based payment transactions Total intrinsic value for vested cash-settled share-based payments 2016 397 44 441 59 48 $ million 2015 759 (50) 709 32 – In addition to the share-based payment transactions detailed in the table above, the company issued ordinary shares to the government of Abu Dhabi in consideration for a 10% interest in the Abu Dhabi onshore oil concession. The interest in the concession is owned by a subsidiary of the company, BP (Abu Dhabi) Limited. As part of the agreements BP (Abu Dhabi) Limited has issued a promissory note to the company as described in Note 3. The share-based payment transaction was valued at the fair value of the interest in the assets, which was valued with reference to a market transaction for an identical interest. Additional information on the company’s share-based payment plans is provided in Note 10 to the consolidated financial statements. 11. Auditor’s remuneration Note 35 to the consolidated financial statements provides details of the remuneration of the company’s auditor on a group basis. The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 225 12. Directors’ remuneration Remuneration of directors Total for all directors Emoluments Amounts awarded under incentive schemesa Total a Excludes amounts relating to past directors. 2016 10 14 24 $ million 2015 10 14 24 Emoluments These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits earned during the relevant financial year, plus cash bonuses awarded for the year. Further information is provided in the Directors’ remuneration report on page 80. 13. Employee costs and numbers Employee costs Wages and salaries Social security costs Pension costs Average number of employees Upstream Downstream Other businesses and corporate 2016 480 66 69 615 2016 248 1,152 2,405 3,805 $ million 2015 478 67 96 641 2015 259 1,395 2,424 4,078 The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 226 BP Annual Report and Form 20-F 2016 14. Related undertakings of the group In accordance with Section 409 of the Companies Act 2006, a full list of related undertakings, the registered office address and the percentage of equity owned as at 31 December 2016 is disclosed below. Unless otherwise stated, the share capital disclosed comprises ordinary shares or common stock (or local equivalent thereof) which are indirectly held by BP p.l.c. All subsidiary undertakings are controlled by the group and their results are fully consolidated in the group’s financial statements. The percentage of equity owned by the group is 100% unless otherwise noted below. The stated ownership percentages represent the effective equity owned by the group. Subsidiaries 200 PS Overseas Holdings Inc. 4321 North 800 West LLCa 563916 Alberta Ltd. ACP (Malaysia), Inc. Actomat B.V. Advance Petroleum Holdings Pty Ltd Advance Petroleum Pty Ltd AE Cedar Creek Holdings LLCa AE Goshen II Holdings LLCa AE Goshen II Wind Farm LLCa AE Power Services LLCa AE Wind PartsCo LLCa Air BP Albania SHA Air BP Brasil Ltda. Air BP Canada LLCa Air BP Croatia d.o.o. Air BP Denmark ApS Air BP Finland OYb Air BP Limited Air BP Norway AS Air BP Sales Romania S.R.L. Air BP Sweden AB Air Refuel Pty Ltdc Allgreen Pty Ltd AM/PM International Inc. American Oil Company Amoco (Fiddich) Limited Amoco (U.K.) Exploration Company, LLC Amoco Austria Petroleum Company Amoco Bolivia Petroleum Company Amoco Bolivia Services Company Inc. Amoco Brazil, Inc. Amoco Canada International Holdings B.V. Amoco Capline Pipeline Company Amoco Chemical (Europe) S.A. Amoco Chemical Holding B.V.d Amoco Chemical U.K. Limited (in liquidation) Amoco Chemicals (FSC) B.V. Amoco CNG (Trinidad) Limited Amoco Cypress Pipeline Company Amoco Destin Pipeline Company Amoco Endicott Pipeline Company Amoco Environmental Services Company Amoco Exploration Holdings B.V. Amoco Fabrics (U.K.) Limited (in liquidation) Amoco Fabrics and Fibers Ltd.e Amoco Guatemala Petroleum Company Amoco International Finance Corporation Amoco International Petroleum Company Amoco Kazakhstan (CPC) Inc. Amoco Leasing Corporation Amoco Louisiana Fractionator Company Amoco Main Pass Gathering Company Amoco Marketing Environmental Services Company Amoco MB Fractionation Company Amoco MBF Company Amoco Netherlands Petroleum Company Amoco Nigeria Exploration Company Limitedf Amoco Nigeria Oil Company Limitedf Amoco Nigeria Petroleum Company Amoco Nigeria Petroleum Company Limited Amoco Norway Oil Company Amoco Oil Holding Company Amoco Olefins Corporation Amoco Overseas Exploration Company Amoco Pipeline Asset Company Amoco Pipeline Holding Company Amoco Properties Incorporated Amoco Realty Company Amoco Remediation Management Services Corporation Amoco Research Operating Company Amoco Rio Grande Pipeline Company Amoco Somalia Petroleum Company Amoco Sulfur Recovery Company Amoco Tax Leasing X Corporation Amoco Trinidad Gas B.V. Amoco Tri-States NGL Pipeline Company The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 240 - Fourth Avenue SW, Calgary AB T2P 4H4, Canada Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Level 17, 717 Bourke Street, Docklands VIC, Australia Level 17, 717 Bourke Street, Docklands VIC, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Aeroporti Nderkombetar i Tiranes, “Nene Tereza”, Post Box 2933 in Tirana, Albania Avenida Rouxinol, 55 , Offices 501-514 , Moema Office Tower, São Paulo, 04516 - 000, Brazil Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Petrinjska ulica 2, Zagreb, Croatia Arne Jacobsens Allé 7, 5th Floor, 2300, Copenhagen, Denmark Teknobulevardi 3-5, 01530 Vantaa, Finland Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Drammensveien 167, Oslo, 0277, Norway 59 Aurel Vlaicu Street, Otopeni, Ilfov County, Romania Box 8107, 10420, Stockholm, Sweden Bulwer Island Refinery, 572 Curtin Avenue, Eagle Farm QLD 4009, Australia Level 17, 717 Bourke Street, Docklands VIC, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands 5-5A Queen’s Park West, Port-of-Spain, Trinidad and Tobago Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Bank of America Center, 16th Floor, 1111 East Main Street, Richmond VA 23219, United States Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 1423 Cameron Street, Hawkesbury ON, Canada Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 400 East Court Avenue, Des Moines IA 50309, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria 7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria 7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria 7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Annual Report and Form 20-F 2016 227 i F n a n c a i l s t a t e m e n t s 14. Related undertakings of the group – continued Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States 801 Adlai Stevenson Drive, Springfield, IL, 62703, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Wittener Straße 45, 44789 Bochum, Germany Bâtiment B, 36 route de Longwy, L-8080 Bertrange, Luxembourg Wittener Straße 45, 44789 Bochum, Germany Autoroute A3/E25, L-3325 Brechem Ouest, Luxembourg Bâtiment B, 36 route de Longwy, L-8080 Bertrange, Luxembourg Überseeallee 1, 20457, Hamburg, Germany Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC, Australia Rua da Candelária, 65, Office 2102, Rio de Janeiro, Brazil Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria Providence House, East Hill Street, P.O. Box N-3944, Nassau, Bahamas Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco U.K. Petroleum Limited AmProp Finance Company Amprop Illinois I Limited Partnershipg Amprop, Inc. Anaconda Arizona, Inc. Aral Aktiengesellschaft Aral Luxembourg S.A. Aral Mineralölvertrieb GmbH Aral Services Luxembourg Sarl Aral Tankstellen Services Sarl Aral Vertrieb GmbH ARCO British International, Inc. ARCO British Limited, LLC ARCO Coal Australia Inc. Arco do Brasil Ltda. ARCO El-Djazair Holdings Inc. ARCO El-Djazair LLCa ARCO Environmental Remediation, L.L.C.a ARCO Exploration, Inc. ARCO Gaviota Company ARCO Ghadames Inc. ARCO International Investments Inc. ARCO International Services Inc. ARCO Material Supply Company ARCO Midcon LLCa ARCO Neftegaz Holdings, Inc. ARCO Oil Company Nigeria Unlimiteda ARCO Oman Inc. ARCO Products Company ARCO Resources Limited ARCO Terminal Services Corporation ARCO Trinidad Exploration and Production Company Limited Providence House, East Hill Street, P.O. Box N-3944, Nassau, Bahamas ARCO Unimar Holdings LLCa Aspac Lubricants (Malaysia) Sdn. Bhd. (63.03%) Atlantic 2/3 UK Holdings Limited Atlantic Richfield Company Autino Holdings Limitedh Auwahi Wind Energy Holdings LLCa Bahia de Bizkaia Electridad, S.L. (75.00%) Baltimore Ennis Land Company, Inc. Black Lake Pipe Line Company BP - Castrol (Thailand) Limited (57.56%)b BP (Abu Dhabi) Limited BP (Barbados) Holding SRL BP (Barbican) Limitedi BP (China) Holdings Limited BP (China) Industrial Lubricants Limited BP (Gibraltar) Limitedj BP (Indian Agencies) Limitedi BP (Malta) Limitedi BP (Shanghai) Trading Limited BP Absheron Limited BP Africa Limitedi BP Akaryakit Ortakligi (70.00%)g BP Alaska LNG LLCa BP Alternative Energy Holdings Limited BP Alternative Energy North America Inc. BP America Chembel Holding LLC BP America Chemicals Company BP America Foreign Investments Inc. BP America Inc. BP America Limited BP America Production Company BP AMI Leasing, Inc. BP Amoco Chemical Company BP Amoco Chemical Holding Company BP Amoco Chemical Indonesia Limited BP Amoco Chemical Malaysia Holding Company BP Amoco Chemical Singapore Holding Company BP Amoco Exploration (Faroes) Limited BP Amoco Exploration (In Amenas) Limited BP Amoco Neighborhood Development Corporation BP Angola (Block 18) B.V. BP Argentina Exploration Company BP Aromatics Holdings Limited BP Aromatics Limited BP Aromatics Limited N.V. BP Asia Limited BP Asia Pacific (Malaysia) Sdn. Bhd. BP Asia Pacific Holdings Limited BP Asia Pacific Pte Ltdi BP Australia Capital Markets Limited BP Australia Employee Share Plan’ Proprietary Limited BP Australia Group Pty Ltdf BP Australia Investments Pty Ltd BP Australia Nominees Proprietary Limited BP Australia Pty Ltd BP Australia Shipping Pty Ltdk BP Australia Swaps Management Limited BP Aviation A/S BP Benevolent Fund Trustees Limitedi Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Axiata Tower, No.9 Jalan Stesen Sentral 5, Kuala Lumpur Sentral 50470 Kuala Lumpur, Malaysia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 83-85 London Street , Reading , Berkshire, RG1 4QA, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Atraque Punta Lucero, Explanada Punta Ceballos s/n, Ziérbena (Vizcaya), Spain 1300 East Ninth Street, Cleveland, OH, 44114, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa Sathon, Bangkok 10120, Thailand Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Erin Court, Bishop’s Court Hill, St. Michael, Barbados Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Room 2101, 21F Youyou International Plaza, 76 Pujian Road, Pudong, Shanghai, PRC Bin Jiang Road, Petrochemical Industrial Park, Jiangsu Province, China Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 3rd Floor, Navi Buildings, Pantar Road, Lija, LJA 2021, Malta Room 2206, Dong Hua Financial Building, 28 Ma ji Road, Waigaoqiao Bonded Zone, Shanghai, China Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Degirmen yolu cad. No:28, Asia OfisPark K:3 I˙cerenkoy-Atasehir, Istanbul, 34752, Turkey Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 400 East Court Avenue, Des Moines IA 50309, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Amocolaan 2 2440 Geel, Belgium Unit 807, Tower B, Manulife Financial Centre, 223 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong Axiata Tower, No.9 Jalan Stesen Sentral 5, Kuala Lumpur Sentral 50470 Kuala Lumpur, Malaysia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 1 Harbour Front Avenue, #02-01 Keppel Bay Tower, Singapore 098632, Singapore Level 17, 717 Bourke Street, Docklands VIC, Australia Level 17, 717 Bourke Street, Docklands VIC, Australia Level 17, 717 Bourke Street, Docklands VIC, Australia Level 17, 717 Bourke Street, Docklands VIC, Australia Level 17, 717 Bourke Street, Docklands VIC, Australia Level 17, 717 Bourke Street, Docklands VIC, Australia Level 17, 717 Bourke Street, Docklands VIC, Australia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom c/o Danish Refuelling Services, Kastrup Lufthavn, 2770 Kastrup, Denmark Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 228 BP Annual Report and Form 20-F 2016 14. Related undertakings of the group – continued BP Berau Ltd. BP Biocombustíveis S.A. (99.99%) BP Bioenergia Campina Verde Ltda. (99.99%) BP Bioenergia Ituiutaba Ltda. (99.99%) BP Bioenergia Itumbiara S.A. (99.99%) BP Bioenergia Tropical S.A. (99.99%) BP Biofuels Advanced Technology Inc. BP Biofuels Brazil Investments Limited BP Biofuels Louisiana LLCa BP Biofuels North America LLCa BP Biofuels Trading Comércio, Importação e Exportação Ltda. (99.99%) BP Biofuels UK Limited BP Bomberai Ltd. BP Brasil Investimentos Ltda BP Brasil Ltda. BP Brazil Tracking L.L.C.a BP Bulwer Island Pty Ltdl BP Business Service Centre Asia Sdn Bhd BP Business Service Centre KFTa BP Canada Energy Development Company BP Canada Energy Group ULC BP Canada Energy Marketing Corp. BP Canada International Holdings B.V. BP Canada Investments Inc. BP Capellen Sarl BP Capital Markets America Inc. BP Capital Markets p.l.c. BP Caplux S.A.c BP Car Fleet Limitedi BP Caribbean Company BP Castrol KK (64.84%) BP Castrol Lubricants (Malaysia) Sdn. Bhd. (63.03%) BP Chembel N.V. BP Chemical US Sales Company BP Chemicals (Korea) Limited BP Chemicals East China Investments Limited BP Chemicals France Holding BP Chemicals Investments Limited BP Chemicals Limited BP Chemicals Trading Limited BP Chile Petrolera Limitada BP China Exploration and Production Company BP China Limitedi BP Company North America Inc. BP Containment Response Limited BP Containment Response System Holdings LLCa BP Continental Holdings Limited BP Corporate Holdings Limited BP Corporation North America Inc.b BP Danmark A/S BP Developments Australia Pty. Ltd. BP Dogal Gaz Ticaret Anonim Sirketi BP East Kalimantan CBM Limited BP Eastern Mediterranean Limitedi BP Egypt Company BP Egypt East Delta Marine Corporation BP Egypt East Tanka B.V. BP Egypt Production B.V. BP Egypt Ras El Barr B.V. BP Egypt West Mediterranean (Block B) B.V. BP Energía México, S. de R.L. de C.V. BP Energy Asia Pte. Limited BP Energy Colombia Limited BP Energy Company BP Energy do Brasil Ltda. BP Energy Europe Limited BP Espana, S.A. Unipersonall BP Europa SEm BP Exploracion de Venezuela S.A. BP Exploration & Production Inc.e BP Exploration (Alaska) Inc. BP Exploration (Algeria) Limited BP Exploration (Alpha) Limited BP Exploration (Angola) Limited BP Exploration (Azerbaijan) Limited BP Exploration (Canada) Limited BP Exploration (Caspian Sea) Limited BP Exploration (Delta) Limited BP Exploration (El Djazair) Limited BP Exploration (Epsilon) Limited BP Exploration (Finance) Limited BP Exploration (Greenland) Limited BP Exploration (Morocco) Limited BP Exploration (Namibia) Limited BP Exploration (Nigeria Finance) Limited BP Exploration (Nigeria) Limited BP Exploration (Shafag-Asiman) Limited BP Exploration (Shah Deniz) Limited Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Avenida das Nações Unidas, 12.399, 4º andar, cj. 41B, sala 01, São Paulo, Brazil Rua Principal, Fazenda Recanto, Caixa Postal 01, Ituiutaba, Minas Gerais, 38.300-898, Brazil Fazenda Recanto, Zona Rural, CEP 38.300-898, Ituiutaba, Minas Gerais, Brazil Estrada Municipal Itumbiara, Chacoeira Dourada, Fazenda Jandaia, Itumbiara, Goiás, 75516-126, Brazil Rodovia GO 410, km 51 à esquerda, Fazenda Canadá, s/n, Zona Rural, Edéia, Goiás, 75940-000, Brazil Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Avenida das Nações Unidas, 12.399, 4º andar, cj. 41B, sala 01, São Paulo, Brazil Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Rua Bernardo Guimarães, 135, part, Rio de Janeiro, Brazil Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC, Australia Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur, Malaysia BP Business Service Centre KFT, 32-34 Soroksári út, H-1095 Budapest, Hungary Stewart McKelvey, 900, 1959 Upper Water Street, Halifax NS B3J 3N2, Canada Stewart McKelvey, 900, 1959 Upper Water Street, Halifax NS B3J 3N2, Canada Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Aire de Capellen, L-8309 Capellen, Luxembourg Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Aire de Capellen, L-8309 Capellen, Luxembourg Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States East Tower 20F, Gate CIty Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan Axiata Tower, No.9 Jalan Stesen Sentral 5, Kuala Lumpur Sentral 50470 Kuala Lumpur, Malaysia Amocolaan 2 2440 Geel , Belgium Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Patricio Raby Benavente, Moneda N° 920 Of 205, Santiago, Chile Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 150 West Market Street, Suite 800, Indianapolis IN 46204, United States Arne Jacobsens Allé 7, 5th Floor, 2300, Copenhagen, Denmark Level 8, 250 St Georges Terrace, Perth WA 6000, Australia Degirmen yolu cad. No:28, Asia OfisPark K:3 I˙cerenkoy-Atasehir, Istanbul, 34752, Turkey Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico 1 Harbour Front Avenue, #02-01 Keppel Bay Tower, Singapore 098632, Singapore Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom Avenida de Barajas 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain Überseeallee 1, 20457, Hamburg, Germany Av. Francisco de Miranda, Edif Cavendes, Los Palos Grandes, Chacao, Caracas Miranda, 1060, Venezuela Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Providence House, East Hill Street, P.O. Box N-3910, Nassau, Bahamas Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Landmark Towers-5B, Water Corporation Road, Victoria Island, Lagos, Nigeria Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 229 i F n a n c a i l s t a t e m e n t s 14. Related undertakings of the group – continued BP Exploration (South Atlantic) Limited BP Exploration (Vietnam) Limited BP Exploration (West Africa) Limited BP Exploration (Xazar) PTE. Ltd. BP Exploration Angola (Kwanza Benguela) Limited BP Exploration Australia Pty Ltd BP Exploration Beta Limited BP Exploration China Limited BP Exploration Company (Middle East) Limited BP Exploration Company Limitedn BP Exploration do Brasil Ltda BP Exploration Indonesia Limited BP Exploration Libya Limited BP Exploration Mexico Limited BP Exploration Mexico, S.A. DE C.V.b BP Exploration North Africa Limited BP Exploration Operating Company Limitedl BP Exploration Orinoco Limited BP Exploration Personnel Company Limited BP Express Shopping Limited BP Finance Australia Pty Ltd BP Finance p.l.c. BP Foundation Incorporateda BP France BP Fuels & Lubricants AS BP Fuels Deutschland GmbH BP Gas Europe, S.A.U. BP Gas Marketing Limited BP Gas Supply (Angola) LLCa BP Gelsenkirchen GmbH BP Ghana Limited BP Global Investments Limitedi BP Global Investments Salalah & Co LLC BP Global West Africa Limited BP Greece Limited BP Guangdong Limited (90.00%) BP High Density Polyethylene France - BP HDPE BP Holdings (Thailand) Limited (81.01%)o BP Holdings B.V. BP Holdings Canada Limitedi BP Holdings International B.V. BP Holdings North America Limitedi BP Hong Kong Limited BP India Services Private Limited BP Indonesia Investment Limited BP Indonesia Oil Terminal Investment Limited BP International Limitedi BP International Services Company BP Investment Management Limited BP Investments Asia Limited BP Iran Limited BP Iraq N.V. BP Italia SpA BP Japan K.K. BP Kapuas I Limited BP Kapuas II Limited BP Kapuas III Limited BP Korea Limited BP Kuwait Limited BP Latin America LLCa BP Lesotho (Pty) Limitedi BP Lingen GmbH BP LNG Shipping Limited BP Lubes Marketing GmbH BP Lubricants KK (64.84%) BP Lubricants USA Inc. BP Luxembourg S.A. BP Malaysia Holdings Sdn. Bhd. (70.00%) BP Management International B.V. BP Management Netherlands B.V. BP Marine Limited BP Maritime Services (Isle of Man) Limited BP Maritime Services (Singapore) Pte. Limited BP Marketing Egypt LLC BP Mauritius Limited BP Middle East Enterprises Corporationb BP Middle East Limitedi BP Middle East LLC BP Mocambique Limitada BP Mocambique Limited BP Muturi Holdings B.V. BP Nederland Holdings BV BP Netherlands Exploration Holding B.V. BP Netherlands Upstream B.V. BP New Ventures Middle East Limited BP New Zealand Holdings Limited BP New Zealand Share Scheme Limited BP Norge AS BP Nutrition Inc. BP Offshore Gathering Systems Inc. Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 1 Harbour Front Avenue, #02-01 Keppel Bay Tower, Singapore 098632, Singapore Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Level 8, 250 St Georges Terrace, Perth WA 6000, Australia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. CuajimalpaC.P., 05349 México D.F., Mexico Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Level 17, 717 Bourke Street, Docklands VIC, Australia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France P.O.Box 153 Skøyen, 0212 Oslo, Norway Wittener Straße 45, 44789 Bochum, Germany Avenida de Barajas 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Pawikerstraße 30, 45899 Gelsenkirchen, Germany Number 12, Aviation Road, Una Home 3rd Floor, Airport City , Accra, Greater Accra, PMB CT 42, Ghana Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom PO Box 2309, Salalah, 211, Oman Landmark Towers - 5B, Water Corporation Road, Victoria Island, Lagos, Nigeria Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Rm 2710Guangfa Bank Plaza, No. 83 Nonglin Xia Road, Yuexiu District, Guangzhou, China Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France 39/77-78 Moo 2 Rama II Road, Tambon Bangkrachao, Amphur Muang, Samutsakorn 74000, Thailand Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Unit 807, Tower B, Manulife Financial Centre, 223 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400 093, India Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Amocolaan 2 2440 Geel , Belgium Via A. Cechov 50/2, 20151 Milan, Italy Roppongi Hills Mori Tower, 10-1 Roppongi 6-chome, Minato-ku, Tokyo106-6115, Japan Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 2nd Floor, Woojin Bldg., 76-4, Jamwon-dong, Seocho-gu, Seoul 137-909, Republic of Korea Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP House, Motsoene Road, Industrial Area, Maseru, Lesotho Raffineriestraße, 49808 Lingen, Germany c/o Codan Services Limited, PO Box HM 1022, Clarendon House, Church Street, Hamilton, Bermuda Überseeallee 1, 20457, Hamburg, Germany East Tower 20F, Gate CIty Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Aire de Capellen, L-8309 Capellen, Luxembourg Axiata Tower, No.9 Jalan Stesen Sentral 5, Kuala Lumpur Sentral 50470 Kuala Lumpur, Malaysia Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Samuel Harris House, 5-11 St Georges Street, Douglas, Isle of Man, IM1 1AJ, Isle of Man 1 Harbour Front Avenue, #02-01 Keppel Bay Tower, Singapore 098632, Singapore Plot 28, North 90 Road, Housing & Construction Bank Building, New Cairo, Cairo, 11835, Egypt 5th Floor, Ebene Esplanade, 24 Cybercity, Ebene, Mauritius Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom P.O.Box 1699, Dubai, 1699, United Arab Emirates Society and Geography Avenue, Plot No. 269 , Third floor, Maputo, Mozambique Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand Godesetdalen 8, 4065 Stavanger, Norway Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 230 BP Annual Report and Form 20-F 2016 14. Related undertakings of the group – continued BP Offshore Pipelines Inc. BP Offshore Response Company LLCa BP Oil (Thailand) Limited (90.32%)p BP Oil and Chemicals International Philippines Inc. BP Oil Australia Pty Ltd BP Oil Espana, S.A. Unipersonal BP Oil Hellenic S.A. BP Oil International Limited BP Oil Kent Refinery Limited (in liquidation) BP Oil Llandarcy Refinery Limited BP Oil Logistics UK Limited BP Oil Marketing GmbH BP Oil New Zealand Limited BP Oil Pipeline Company BP Oil Shipping Company, USA BP Oil UK Limited BP Oil Venezuela Limited BP Oil Vietnam Limited BP Oil Yemen Limited BP Olex Fanal Mineralol GmbH BP Pacific Investments Ltd BP Pakistan (Badin) Inc. BP Pakistan Exploration and Production, Inc. BP Pension Trustees Limitedi BP Pensions (Overseas) Limitedj BP Pensions Limitedi BP Petrochemicals India Investments Limited BP Petroleo y Gas, S.A. BP Petrolleri Anonim Sirketi BP Pipelines (Alaska) Inc. BP Pipelines (BTC) Limited BP Pipelines (North America) Inc. BP Pipelines (SCP) Limited BP Pipelines (TANAP) Limited BP Pipelines TAP Limited BP Polska Services Sp. z o.o. BP Portugal -Comercio de Combustiveis e Lubrificantes SA BP Poseidon Limited BP Products North America Inc. BP Properties Limitedi BP Raffinaderij Rotterdam B.V. BP Refinery (Kwinana) Proprietary Limited BP Refining & Petrochemicals GmbH BP Regional Australasia Holdings Pty Ltd BP Russian Investments Limited BP Services International Limited BP Shafag-Asiman Limited BP Shipping Limited BP Singapore Pte. Limited BP Solar Energy North America LLCa BP Solar Espana, S.A. Unipersonalc BP Solar International Inc. BP Solar Pty Ltd BP South East Asia Limitedi BP Southern Africa Proprietary Limited (75.00%) BP Southern Cone Company BP Subsea Well Response (Brazil) Limited BP Subsea Well Response Limited BP Taiwan Marketing Limited BP Tanjung IV Limited BP Technology Ventures Inc. BP Technology Ventures Limited BP Toplivnaya Kompanya LLCa BP Trade and Supply (Germany) GmbH,Hamburg BP Trading Limitedi BP Train 2/3 Holding SRL BP Transportation (Alaska) Inc. BP Trinidad and Tobago LLC (70.00%)a BP Trinidad Processing Limited BP Turkey Refining Limitedi BP Venezuela Investments B.V. BP West Aru I Limited BP West Aru II Limited BP West Coast Products LLCa BP West Papua I Limited BP West Papua III Limited BP Wind Energy North America Inc. BP Wiriagar Ltd. BP World-Wide Technical Services Limited BP Zhuhai Chemical Company Limited (85.00%) BP+Amoco International Limitedi BPA Investment Holding Company BPNE International B.V. BPRY Caribbean Ventures LLC (70.00%)a Brian Jasper Nominees Pty Ltd Britannic Energy Trading Limited Britannic Investments Iraq Limited (90.00%) Britannic Strategies Limited Britannic Trading Limited British Pipeline Agency Limited (50.00%)b q Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 39/77-78 Moo 2 Rama II Road, Tambon Bangkrachao, Amphur Muang, Samutsakorn 74000, Thailand 30/F LKG Tower, 6801 Ayala Avenue, Makati City 1226, Philippines Level 17, 717 Bourke Street, Docklands VIC, Australia Polígono Industrial “El Serrallo”, s/n12100 Grao de Castellón, Castellón de la Plana, Spain 26 Kifissias Ave. and 2 Paradissou st., 15125 Maroussi, Athens, Greece Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Wittener Straße 45, 44789 Bochum, Germany Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Überseeallee 1, 20457, Hamburg, Germany Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Albert House, South Esplanade, St. Peter Port, GY1 1AW, Guernsey Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Av. Francisco de Miranda, Edif Cavendes, Los Palos Grandes, Chacao, Caracas Miranda, 1060, Venezuela Degirmen yolu cad. No:28, Asia Ofis Park K:3 I˙cerenkoy-Atasehir, Istanbul, 34752, Turkey Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 45 Memorial Circle, Augusta ME 04330, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Ul. Jasnogórska 1, 31-358 Kraków, Malopolskie, Poland Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 351 West Camden Street, Baltimore MD 21201, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom d’Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Level 17, 717 Bourke Street, Docklands VIC, Australia Wittener Straße 45, 44789 Bochum, Germany Level 17, 717 Bourke Street, Docklands VIC, Australia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 1 Harbour Front Avenue, #02-01 Keppel Bay Tower, Singapore 098632, Singapore Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Avenida de Barajas 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC, Australia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 7FNo. 71Sec. 3Min Sheng East Road, Taipei, Taiwan Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 2 Paveletskaya sq, Building1, 115054 Moscow, Russian Federation Überseeallee 1, 20457, Hamburg, Germany Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Erin Court, Bishop’s Court Hill, St. Michael , Barbados Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 5-5A Queen’s Park West, Port-of-Spain, Trinidad and Tobago Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Da Ping Harbour, Lin Gang Industrial Zone, Zhuhai City, Guangdong Province, China Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC, Australia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 5-7 Alexandra Road, Hemel Hempstead, Hertfordshire, HP2 5BS, United Kingdom The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 231 i F n a n c a i l s t a t e m e n t s 14. Related undertakings of the group – continued Britoil Limited BTC Pipeline Holding Company Limited Burmah Castrol Australia Pty Ltdr Burmah Castrol Holdings Inc. Burmah Castrol PLCi Burmah Castrol South Africa (Pty) Limited Burmah Chile S.A. Burmah Fuels Australia Pty Ltdl BXL Plastics Limited Cadman DBP Limited Cape Vincent Wind Power, LLCa Casitas Pipeline Company Castrol (China) Limited Castrol (Ireland) Limited Castrol (Shenzhen) Company Limited Castrol (U.K.) Limited Castrol Australia Pty. Limited Castrol Austria GmbHa Castrol B.V. Castrol BP Petco Limited Liability Company (65.00%)a Castrol Brasil Ltda. Castrol Caribbean & Central America Inc. Castrol Colombia Limitada Castrol Del Peru S.A. (99.49%) Castrol Hungária Trading Co. Ltd. (Castrol Hungária Kereskedelmi Kft)a Castrol India Limited (51.00%) Castrol Industrial North America Inc. Castrol Industrie und Service GmbH Castrol KK (64.84%) Castrol Limited Castrol Lubricants (CR), s.r.o. Castrol Lubricants RO S.R.L Castrol Mexico, S.A. de C.V.s Castrol Namibia (Pty) Limited Castrol Offshore Limited Castrol Pakistan (Private) Limited Castrol Philippines, Inc. Castrol Servicos Ltda. Castrol Slovensko, s.r.o. Castrol South Africa Proprietary Limited Castrol Ukraine LLCa Castrol Zimbabwe (Private) Limited Centrel Pty Ltd CH-Twenty Holdings LLCa CH-Twenty, Inc. Clarisse Holdings Pty Ltd Coastwise Trading Company, Inc. Consolidada de Energia y Lubricantes, (CENERLUB) C.A. Conti Cross Keys Inn, Inc. Coro Trading NZ Limited Cuyama Pipeline Company Delta Housing Inc. Dermody Developments Pty Ltd Dermody Holdings Pty Ltd Dermody Investments Pty Ltd Dermody Petroleum Pty. Ltd. DHC Solvent Chemie GmbH Dome Beaufort Petroleum Limited Dome Beaufort Petroleum Limited (March 1980) Limited Partnershipg Dome Beaufort Petroleum Limited 1979 Partnership No. 1g Dome Wallis (1980) Limited Partnership (92.50%)g Dradnats, Inc. ECM Markets SA (Pty) Ltd (75.00%) Edom Hills Project 1, LLCa Elite Customer Solutions Pty Ltd Elm Holdings Inc. Energy Global Investments (USA) Inc. Enstar LLCa Europa Oil NZ Limited Exomet, Inc. Expandite Contract Services Limited Exploration (Luderitz Basin) Limited Exploration Service Company Limited F&H Pipeline Company Flat Ridge 2 Holdings LLCa Flat Ridge Wind Energy, LLCa Foseco Chile Ltda. Foseco Holding International B.V. Foseco Holding, Inc. Foseco, Inc. Fosroc Expandite Limited Fosven, CA Fowler Ridge Holdings LLCa Fowler Ridge I Land Investments LLCa Fowler Ridge II Holdings LLCa Fowler Ridge III Wind Farm LLCa FreeBees B.V. 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Level 17, 717 Bourke Street, Docklands VIC, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa José Musalen Saffie, Huerfanos N° 770 Of. 301, Santiago, Chile Level 17, 717 Bourke Street, Docklands VIC, Australia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 111 Eighth Avenue, New York, New York, 10011, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Unit 807, Tower B, Manulife Financial Centre, 223 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong First Floor, Fitzwilton House, Wilton Place, Dublin 2, Ireland No.1120 Mawan Rod, Nanshan District, China Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Level 17, 717 Bourke Street, Docklands VIC, Australia Straße 6, Objekt 17, Industriezentrum NÖ-Süd 2355 Wr. Neudorf, Austria Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands 22-36 Nguyen Hue Street, 57-69F Dong Khoi Street, District 1, Ho Chi Minh City, Vietnam Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Oficina 401, Carrera 14 N° 93B -45, Bogotá, Colombia Av. Camino Real, 111 Torre B Oficina, 603 San Isidro, Lima, Peru Castrol Hungária Kft, 30-34/E. Soroksári ùt, H-1095 Budapest, Hungary Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400 093, India Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Erkelenzer Straße 20, 41179 Mönchengladbach, Germany East Tower 20F, Gate CIty Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan Technology Centre, Whitchurch Hill, Pangbourne, Reading, RG8 7QR, United Kingdom V Parku 2294/2, 148 00 Praha 4, Czech Republic 5th Floor, 92-96 Izvor St, 5th District, Bucharest, Romania Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. Cuajimalpa C.P., 05349 México D.F., Mexico BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom D-67/1, Block # 4, Scheme # 5, Clifton, Karachi, Pakistan 32/F LKG Tower, Ayala Avenue, Makati City, 6801, Philippines Avenida Tamboré, 448, Barueri, Sao Paulo, Brazil Rozˇnavská 24, 821 04 Bratislava 2, Slovakia BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa 2a Konstiantynivskay Street, Kyiv, 04071, Ukraine Barking Road, Willowvale, Harare, Zimbabwe Level 17, 717 Bourke Street, Docklands VIC, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Av. Eugenio Mendoza, San Felipe Edificio Centro Letonia, La Castellana, Caracas, 1060, Venezuela Easton and Swamp Roads, Buckinham Township, Bucks County, Pennsylvania, United States Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC, Australia Level 17, 717 Bourke Street, Docklands VIC, Australia Level 17, 717 Bourke Street, Docklands VIC, Australia Level 17, 717 Bourke Street, Docklands VIC, Australia Timmerhellstsr. 28, 45478, Mülheim/Ruhr, Germany 240 - Fourth Avenue SW, Calgary AB T2P 4H4, Canada 240 - Fourth Avenue SW, Calgary AB T2P 4H4, Canada 240 - Fourth Avenue SW, Calgary AB T2P 4H4, Canada 240 - Fourth Avenue SW, Calgary AB T2P 4H4, Canada 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand 1300 East Ninth Street, Cleveland, OH, 44114, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 112 SW 7th Street, Suite 3C, Topeka, Kansas, 66603, United States Avenida Eliodoro Yañez N° 1572, Providencia , Santiago, Chile Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Av. Francisco de Miranda, Edif Cavendes, Los Palos Grandes, Chacao, Caracas Miranda, 1060, Venezuela Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 232 BP Annual Report and Form 20-F 2016 14. Related undertakings of the group – continued Box 8107, 10420, Stockholm, Sweden Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal Fuel & Retail Aviation Sweden AB FUELPLANE- Sociedade Abastecedora de Aeronaves, Unipessoal, Lda Gardena Holdings Inc. Gasolin GmbH Gasolinera Industrial S.L. GOAM 1 C.I S. A .S Grampian Aviation Fuelling Services Limited Grangemouth Holdings Limited Grangemouth Properties Limited Guangdong Investments Limited Highlands Ethanol, LLCa Hydrogen Energy International Limited IGI Resources, Inc. International Card Centre Limited Iraq Petroleum Company Limited J & A Petrochemical Sdn. Bhd. Jupiter Insurance Limited Kabulonga Properties Limited Ken-Chas Reserve Company Kenilworth Oil Company Limitedi Latin Energy Argentina S.A. Lebanese Aviation Technical Services S.A.L. Lubricants UK Limited Mardi Gras Endymion Oil Pipeline Company, LLCa Mardi Gras Transportation System Inc. Markoil, S.A. Unipersonal Masana Petroleum Solutions (Pty) Ltd (37.88%) Mayaro Initiative for Private Enterprise Development (70.00%)a 5-5A Queen’s Park West, Port-of-Spain, Trinidad and Tobago Mehoopany Holdings LLCa Mes Tecnologia en Servicios y Energia, S.A. DE C.V. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Wittener Straße 45, 44789 Bochum, Germany Avenida de Barajas 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain Calle 80 No.11-42, Bogota, 110111, Colombia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 12550 W. Explorer Dr., Suite 100, Boise, Idaho, 83713, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Symphony House, Pusat Dagangan Dana 1, Jalan PJU 1A/46, 47301 Petaling Jaya, Selangor, Malaysia The Albany, South Esplanade, St Peter Port, GY1 4NF, Guernsey 3rd floor Mukuba Pension House, Dedan Kimathi Road, Lusaka 10101, Zambia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Av. Cordoba 315 Piso 8, Buenos Aires, 1054, Argentina P.O. Box - 11 -5814 c/o Coral Oil Building, 583 Avenue de Gaulle, Raoucheh, Beirut, Lebanon Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Avenida de Barajas 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa Minza Pty. Ltd. Mountain City Remediation, LLCa No. 1 Riverside Quay Proprietary Limited Nordic Lubricants A/S Nordic Lubricants AB Nordic Lubricants Oy North America Funding Company Oelwerke Julius Schindler GmbH OMD87, Inc. Omega Oil Company Orion Delaware Mountain Wind Farm LPa Orion Energy Holdings, LLCa Orion Energy L.L.C.a Orion Post Land Investments, LLCa Pacroy (Thailand) Co., Ltd. (39.00%) Pan American Petroleum Company of California Pan American Petroleum Corporation Peaks America Inc. Pearl River Delta Investments Limited Phoenix Petroleum Services, Limited Liability Company Products Cogeneration Company Produits Métallurgie Doittau SA - PROMEDO ProGas Limited ProGas U.S.A., Inc. Prospect International, C.A. PT BP Petrochemicals Indonesia PT Castrol Indonesia (68.30%) PT Jasatama Petroindoc Reading Investment (Nominee) Limited Reax Industria e Comercio Ltda. Remediation Management Services Company Richfield Oil Corporation Rolling Thunder I Power Partners, LLCa Ropemaker Deansgate Limited Ropemaker Properties Limited Ruehl Gesellschaft m.b.H. & Co KG.g Ruhr Oel GmbH (ROG) Rural Fuel Limited Saltend Chemicals Park Limited Saturn Insurance Inc. Setra Lubricants Kazakhstan LLPg Setra Lubricantsa Sherbino I Holdings LLCa Sherbino II Wind Farm LLCa Sherbino Mesa I Land Investments LLCa Shine Top International Investment Limited Silver Star I Power Partners, LLCa Sociedade de Promocao Imobiliaria Quinta do Loureiro, SA Société de Gestion de Dépots d’Hydrocarbures - GDHa SOFAST Limited (62.77%)t Southeast Texas Biofuels LLCa Southern Ridge Pipeline Holding Company Southern Ridge Pipeline LP LLCa Sp/f Decision3 (GreenSteam) Companyu SRHP (99.99%)a Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. Cuajimalpa C.P., 05349 México D.F., Mexico Level 17, 717 Bourke Street, Docklands VIC, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC, Australia Arne Jacobsens Allé 7, 5th Floor, 2300, Copenhagen, Denmark Box 49104, S-100 28 Stockholm, Sweden Teknobulevardi 3-5, 01530 Vantaa, Finland Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Überseeallee 1, 20457, Hamburg, Germany 111 Eighth Avenue, New York, New York, 10011, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa Sathon, Bangkok 10120, Thailand 818 West Seventh Street, 2nd Floor, Los Angeles, CA, 90017, United States 311 S. Division St., Carson City NV 89703, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Baghdad International Airport, Al-Burhan Commercial Complex , First floor, Baghdad, Iraq Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France 240–Fourth Avenue SW, Calgary AB T2P 4H4, Canada Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Av. Eugenio Mendoza, San Felipe Edificio Centro Letonia, La Castellana, Caracas, 1060, Venezuela 20th Floor Summitmas II Jl., Jend. Sudirman Kav. 61 - 62, Jakarta, Selatan, Indonesia Perkantoran Hijau Arkadia, Tower B, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta 12520, Indonesia Perkantoran Hijau Arkadia, Tower E, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta 12520, Indonesia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Estrada São Lourenço, 751, part, Duque de Caxias, Rio Janeiro, Brazil Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Straße 6, Objekt 17, Industriezentrum NÖ-Süd, 2355 Wr. Neudorf, Austria Johannastraße 2-8, 45899 Gelsenkirchen-Horst, Germany AR Short & Co, Level 8, FMG Building, 55 The Square, Palmerston North, New Zealand Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 400 Cornerstone Drive, Suite 240, Williston VT 05495, United States 98 Panfilov Street, office 809, Almaty, 05000, Kazakhstan 2 Paveletskaya sq, Building1, 115054 Moscow, Russian Federation Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Unit 807, Tower B, Manulife Financial Centre, 223 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France 23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa Sathon, Bangkok 10120, Thailand Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Krosslíð 11, FO-100 Tórshavn , Faroe Islands Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 233 i F n a n c a i l s t a t e m e n t s 14. Related undertakings of the group – continued Standard Oil Company, Inc. Taradadis Pty. Ltd. TEA Comercio E Participacoes Ltda. Telcom General Corporatione Terre de Grace Partnership (75.00%)g The Anaconda Company The BP Share Plans Trustees Limitedi The Burmah Oil Company (Pakistan Trading) Limited The Shorebank Corporation The Standard Oil Company TJKK TOC-Rocky Mountains Inc. Toledo Refinery Holding Company LLCa Trinity Hills Wind Farm LLCa Union Texas International Corporation UT Petroleum Services, LLCa Vastar Energy, Inc. Vastar Gas Marketing, Inc. Vastar Holdings, Inc. Vastar Pipeline, LLCa Vastar Power Marketing, Inc. Verano Collateral Holdings LLCa Viceroy Investments Limited Warrenville Development Limited Partnershipa Water Way Trading and Petroleum Services LLC (90.00%) Welchem, Inc. West Kimberley Fuels Pty Ltd Westlake Houston Development, LLCa Whiting Clean Energy, Inc. Windpark Energy Nederland B.V. Wiriagar Overseas Ltd 251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States Level 17, 717 Bourke Street, Docklands VIC, Australia Avenida Itaóca, 2400, sala 108, Inhauma, Rio de Janeiro, Brazil 818 West Seventh Street, 2nd Floor, Los Angeles, CA, 90017, United States 1100, 635 - 8th Avenue SW, Calgary AB T2P 3M3, Canada 814 Thayer Avenue, Bismarck, ND, 58501-4018, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom 7054 S. Jeffery Blvd., Chicago IL 60649, United States 1300 East Ninth Street, Cleveland, OH, 44114, United States Roppongi Hills Mori Tower, 10-1 Roppongi 6-chome, Minato-ku, Tokyo106-6115, Japan Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 33 North LaSalle Street, Chicago, Illinois 60602, United States Hay Al Wihda, Q904, Alley 68, H32, Korodha, Baghdad, Iraq 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Level 17, 717 Bourke Street, Docklands VIC, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands Palm Grove House, P.O. Box 438, Road Town, Tortola, British Virgin Islands The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 234 BP Annual Report and Form 20-F 2016 14. Related undertakings of the group – continued Level 3, Unit 3, 22 Albert Road, South Melbourne VIC 3205, Australia Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago Maracaibo Drive, Point Lisas Industrial Estate, Point Lisas, Trinidad and Tobago 1 Tanker Street, Lytton QLD, Australia 7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria 2-2 Sangnam-ri, Chungryang-myun, Ulju-gun, Ulsan 689-863, Republic of Korea Degirmen yolu cad. No:28, Asia OfisPark K:3|cerenkoy-Atasehir, Istanbul, 34752, Turkey RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago Patricio Raby Benavente, Moneda N° 920 Of 205, Santiago, Chile Via Lazio 20/C, 00187 Roma, Italy Avenida Ricardo Rivera Navarrete n.501 / room 1602, Lima, Peru Av. Anita Garibaldi, n.252, 2o floor, Ala Sul, Federação, Salvador, Bahia, 40210-750, Brazil Oude Vijfhuizerweg 6, 1118LV Luchthaven, Schiphol, Netherlands Trabrennstraße 6-8 3, A-1020, Wien, Austria 2 Market Street, Sydney NSW, Australia Oksenoyveien 10, 1366 Lysaker, Norway Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 9360 Glacier Highway, Suite 202, Juneau AK 99801, United States Yakuplu Mahallesi Genc, Osman Caddesi, No.7 Beylikdüzü, Istanbul, Turkey Luisenstraße 5 a, 26382 Wilhelmshaven, Germany c/o Mannheimer Swartling Advokatbyra Norrmalmstrog, 4 Box 1711, 111 87 Stockholm, Sweden Riyadh Airport Road, Business Gate, Building C2, 2nd Floor. , Saudi Arabia Related undertakings other than subsidiaries Brucknerstraße 4, 1041 Wien, Austria ABG Autobahn-Betriebe GmbH (32.58%)a Abu Dhabi Marine Areas Limited (33.33%)b Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Abu Dhabi Petroleum Company Limited (23.75%)v Rooms 522-524, 3rd Floor, Salisbury House, London Wall, London, EC2M 5QQ, United Kingdom Advanced Biocatalytics Corporation (24.20%)w 18010 Skypark Circle, #130, Irvine CA 92614, United States AGES International GmbH & Co. KG, Langenfeld (24.70%)g Berghausener Straße 96, 40764 Langenfeld, Germany AGES Maut System GmbH & Co. KG, Langenfeld (24.70%)g Berghausener Straße 96, 40764 Langenfeld, Germany Air BP Copec S.A. (51.00%) Air BP Italia Spa (50.00%) Air BP PBF del Peru S.A.C. (50.00%) Air BP Petrobahia Ltda. (50.00%) Aircraft Fuel Supply B.V. (28.57%) Aircraft Refuelling Company GmbH (33.33%)a Airport Fuel Services Pty. Limited (20.00%) Aker BP ASA (30.00%) Alaska Tanker Company, LLC (25.00%)a Alyeska Pipeline Service Company (48.44%) Ambarli Depolama Hizmetleri Limited Sirketi (50.00%) Ammenn GmbH (75.00%) Amoco Bolivia Oil and Gas Aktiebolag (60.00%) Arabian Production And Marketing Lubricants Company (50.00%) ARCO Solar Nigeria Ltd. (40.00%) Asian Acetyls Co., Ltd (34.00%) ATAS Anadolu Tasfiyehanesi Anonim Sirketi (68.00%) Atlantic 1 Holdings LLC (34.00%)a Atlantic 2/3 Holdings LLC (42.50%)a Atlantic 4 Holdings LLC (37.78%)a Atlantic LNG 2/3 Company of Trinidad and Tobago Unlimited (42.50%) Atlantic LNG 4 Company of Trinidad and Tobago Unlimited (37.78%) Atlantic LNG Company of Trinidad and Tobago (34.00%) Atlas Methanol Company Unlimited (36.90%) Australasian Lubricants Manufacturing Company Pty Ltd (50.00%)b Australian Terminal Operations Management Pty Ltd (50.00%) Auwahi Holdings, LLC (50.00%)a Auwahi Wind Energy LLC (50.00%)a Aviation Fuel Services Limited (25.00%) Azerbaijan Gas Supply Company Limited (23.06%)b Azerbaijan International Operating Company (40.50%)x Baplor S.A. (60.00%) Barranca Sur Minera S.A. (60.00%) Bayernoil Raffineriegesellschaft mbH (35.00%) Beer GmbH & Co. Mineralol-Vertriebs-KG (50.00%)g Beer GmbH (50.00%) BGFH Betankungs-Gesellschaft Frankfurt-Hahn GbR (50.00%)g Sportallee 6, 22335 Hamburg, Germany Billund Refuelling I/S (50.00%) Blendcor (Pty) Limited (37.50%)s BP AOC Pumpstation Maatschap (50.00%)g BP Dhofar LLC (49.00%) BP Esso AOC Maatschap (22.80%)g BP Esso Pipeline Maatschap (50.00%)g BP Guangzhou Development Oil Product Co., Ltd (40.00%) BP India Limited (51.00%) BP PetroChina Petroleum Co., Ltd (49.00%) BP Petronas Acetyls Sdn. Bhd. (70.00%) BP Sinopec (ZheJiang) Petroleum Co., Ltd (40.00%) BP Sinopec Marine Fuels Pte. Ltd. (50.00%) BP YPC Acetyls Company (Nanjing) Limited (50.00%) BP-Husky Refining LLC (50.00%)a BP-Japan Oil Development Company Limited (50.00%)b BTC International Investment Co. (30.10%)y Butamax™ Advanced Biofuels LLC (50.00%)a Caesar Oil Pipeline Company, LLC (56.00%)a Cairns Airport Refuelling Service Pty Ltd (25.00%) Cantera K-3 Limited Partnership (39.00%)g Castrol Cuba S.A. (50.00%) Castrol DongFeng Lubricant Co., Ltd (50.00%) Cedar Creek II Holdings LLC (50.00%)a Cedar Creek II, LLC (50.00%)a Cekisan Depolama Hizmetleri Limited Sirketi (35.00%) Central African Petroleum Refineries (Pvt) Ltd (20.75%) Chicap Pipe Line Company (56.17%)a China American Petrochemical Company, Ltd. (CAPCO) (61.36%) China Aviation Oil (Singapore) Corporation Ltd (20.03%) Cleopatra Gas Gathering Company, LLC (54.00%)a Coastal Oil Logistics Limited (25.00%) Combined Refuelling Service VOF (25.00%)g Compania de Inversiones El Condor Limitada (99.00%) Concessionaria Stalvedro SA (50.00%) CSG Convenience Service GmbH (24.80%) Cypress Pipeline Company, L.L.C. (50.00%)a Danish Refuelling Service I/S (33.33%)g Danish Tankage Services I/S (50.00%)g The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. GA Centervej 1, DK-7190, Billund, Denmark 135 Honshu Road, Islandview, Durban, 4052, South Africa Rijndwarsweg 3, Havennr 5719, 3198LK Europoort Rotterdam, Netherlands P.O.Box 20302/211, 20302, Oman Rijndwarsweg 3, Havennr 5719, 3198LK Europoort Rotterdam, Netherlands Rijndwarsweg 3, Havennr 5719, 3198LK Europoort Rotterdam, Netherlands No.13 Longxue Road, Longxue Island, Nansha District, Guangzhou, Guangdong, 511450, China Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400 093, India Room A 17th Floor, No.22 Gangkou Road, Jiangmen, Guangdong Province, China Symphony House, Pusat Dagangan Dana 1, Jalan PJU 1A/46, 47301 Petaling Jaya, Selangor, Malaysia 12 Hua Zhe Plaza, 1 Hua Zhe Square, Hang Zhou City, Zhe Jiang Province, China 112 Robinson Road, #05-01, Robinson 112, 068902, Singapore 9# Huo Ju Road, Liu He District, Nanjing, Jiangsu Province, China Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 2 Market Street, Sydney NSW, Australia 6400 Shafer Ct., Suite 400, Rosemont IL 60018-4927, United States Calle 6 No 319, esq 5ta. Ave., Miramar, Playa, La Habana, Cuba Room 1404-1405, Donghe Centre Tower B, 3 Sanjiao Hu Road, Wuhan, Hubei Province, China Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 1560 Broadway, Suite 2090, Denver, Colorado, 80202, United States Yakuplu Ambarli Mevkii, 9 Ada2-3-6-7 Parsel, Büyükçekmece, Istanbul, Turkey Block 1Tendeseka Office Park, Samora Machel Av/Renfrew Road, Harare, Zimbabwe Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 9th Floor No. 392 Ruei Kuang Road, Neihu 11492, Taipei, Taiwan 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States National Registered Agents, Inc., 160 Greentree Dr., Dover, Delaware, 19904, United States Calshot Way Central Area, Heathrow Airport, Hounslow, Middlesex, TW6 1PY, United Kingdom P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands 190 Elgin Avenue, George Town, Grand Cayman, KY1-9005, Cayman Islands Colonia 810, Oficina 403, Montevideo, Uruguay Calle 14, No 781, Piso 2, Oficina 3, Ciudad de La Plata, Provincia de Buenos Aires, Argentina Postfach 10 08 58, 85008 Ingolstadt, Germany Saganer Straße 31, 90475 Nürnberg, Germany Saganer Straße 31, 90475 Nürnberg, Germany 8 Temasek Boulevard #31-02, Suntec City Tower 3, Singapore 038988, Singapore Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 10th Floor, The Bayleys Building, Cnr Brandon St and Lambton Quay, Wellington, 6011, New Zealand Anchoragelaan 4, 1118 LD, Schipol, Netherlands Av. Andrés Bello 2711, Piso 24, Las Condes, Santiago, Chile San Gottardo Sud, 6780, Airolo, Switzerland Wittener Straße 45, 44789 Bochum, Germany Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Kastrup Lufthavn, 2770 Kastrup, Denmark Kastrup Lufthavn, 2770 Kastrup, Denmark BP Annual Report and Form 20-F 2016 235 i F n a n c a i l s t a t e m e n t s 14. Related undertakings of the group – continued Dinarel S.A. (24.00%) Dusseldorf Fuelling Services GbR (33.00%)g Dusseldorf Tank Services GbR (33.00%)g East Tanka Petroleum Company “ETAPCO” (50.00%) Ekma Oil Company “EKMA” (50.00%) El Temsah Petroleum Company “PETROTEMSAH” (25.00%) EMDAD Aviation Fuel Storage FZCO (33.33%) Emoil Storage Company FZCO (20.00%) Endymion Oil Pipeline Company, LLC (75.00%)a Energenomics LLC (50.00%)a Energy Emerging Investments, LLC (60.00%)a Entrepot petrolier de Chambery (32.00%) Entrepôt Pétrolier de Puget sur Argens - EPPA (58.25%) Erdol-Lagergesellschaft m.b.H. (23.00%)a Eroil Mineraloel GmbH - Diehl (50.00%) Esma Petroleum Company “ESMA” (50.00%) Estonian Aviation Fuelling Services (49.00%) Etzel-Kavernenbetriebsgesellschaft mbH & Co. KG (33.00%)g Etzel-Kavernenbetriebs-Verwaltungsgesellschaft mbH (33.33%) FFS Frankfurt Fuelling Services (GmbH & Co.) OHG (33.00%)g Fibil SA (50.00%) Field Services Enterprise S.A. (60.00%) Fip Verwaltungs GmbH (50.00%) Flat Ridge 2 Wind Energy LLC (50.00%)a Flat Ridge 2 Wind Holdings LLC (50.00%)a Flughafen Hannover Pipeline Verwaltungsgesellschaft mbH (50.00%) Flughafen Hannover Pipelinegesellschaft mbH & Co. KG (50.00%)g Flytanking AS (50.00%) Foreseer Ltd (25.00%) Formosa BP Chemicals Corporation (50.00%) Fowler I Holdings LLC (50.00%)a Fowler II Holdings LLC (50.00%)a Fowler Ridge II Wind Farm LLC (50.00%)a Fowler Ridge Wind Farm LLC (50.00%)a Fuelling Aviation Service—FAS (50.00%)a Fundación para la Eficiencia Energética de la Comunidad Valenciana (33.33%)a Gardermeon Fuelling Services AS (33.33%) Gemalsur S.A. (60.00%) Georg Reitberger Mineralole GmbH & Co. KG (50.00%)g Georg Reitberger Mineralöle Verwaltungs GmbH (50.00%) Georgian Pipeline Company (40.50%)x Gezamenlijke Tankdienst Schiphol B.V. (50.00%) GISSCO S.A. (50.00%) Goshen Phase II LLC (50.00%)a Gothenburgh Fuelling Company AB (GFC) (33.33%) Gravcap, Inc. (25.00%) Groupement Pétrolier de Saint Pierre des Corps - GPSPC (20.00%)a Groupement Pétrolier de Strasbourg (33.33%)a Groupement pour l’Avitaillement de Lyon Saint-Exupéry - GALYS (39.93%)a Guangdong Dapeng LNG Company Limited (30.00%) Gulf Of Suez Petroleum Company “GUPCO” (50.00%) GVÖ Gebinde-Verwertungsgesellschaft der Mineralölwirtschaft mbH (21.00%) H & G Contracting Services Limited (33.50%) Hamburg Tank Service (HTS) GbR (33.00%)g Heinrich Fip GmbH & Co. KG (50.00%)g Heliex Power Limited (32.40%)w HFS Hamburg Fuelling Services GbR (25.00%)g Hiergeist Heizolhandel GmbH & Co. KG (50.00%)g Hiergeist Verwaltung GmbH (50.00%) Hokchi Energy S.A. de C.V. (60.00%) Hokchi Iberica S.L. (60.00%) Hydrogen Energy International LLC (50.00%)a In Salah Gas Ltd (25.50%)s In Salah Gas Services Ltd (25.50%)s India Gas Solutions Private Limited (50.00%) Jamaica Aircraft Refuelling Services Limited (51.00%)b Kingston Research Limited (50.00%) Klaus Köhn GmbH (50.00%) Köhn & Plambeck GmbH & Co. KG (50.00%)g Kosmos BP Senegal Limited (49.99%) Kurt Ammenn GmbH & Co. KG (50.00%)g LFS Langenhagen Fuelling Services GbR (50.00%)g Limited Liability Company TYNGD (20.00%)a Lotos—Air BP Polska Spółka z ograniczona˛ odpowiedzialnos´ cia˛ (50.00%) LOTTE BP Chemical Co., Ltd (51.00%) Maasvlakte Europoort Pipeline Maatschap (50.00%)g La Cumparsita 1373, piso 4°, Montevideo, Uruguay Sportallee 6, 22335 Hamburg, Germany Sportallee 6, 22335 Hamburg, Germany 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt 5 El Mokhayam El Daiem St, 6th Sector, Nasr City, Egypt P.O.Box 261781, Dubai, United Arab Emirates Plot No. B003R04, Box No. 9400, Dubai, United Arab Emirates Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 562 Avenue du Parc de l’Ile, 92000, Nanterre, France Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France Radlpaßstraße 6, 8502 Lannach, Austria Schillerstraße 10, 66482 Zweibrücken, Germany 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt Lennujaama tee 2, TallinnEE0011, Estonia Bertrand-Russell-Straße 3, 22761 Hamburg, Germany Bertrand-Russell-Straße 3, 22761 Hamburg, Germany Sportallee 6, 22335 Hamburg, Germany Autostradale Coldrerio-Est, 6877, Coldrerio, Switzerland Av. Leandro N. Alem 1180, piso 11, Buenos Aires, Argentina Rheinstraße 36, 49090 Osnabrück, Germany Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Überseeallee 1, 20457, Hamburg, Germany Überseeallee 1, 20457, Hamburg, Germany Postboks 36, Stjordal, NO-7501, Norway 121A Thoday Street, Cambridge, Cambridgeshire, CB1 3AT, United Kingdom No. 1-1Formosa Industrial Comples, Mailiao, Yunlin Hsien, Taiwan Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 3 Rue des Vignes, Aéroport Charles de Gaulle, 93290, Tremblay en France, France Calle Lituania nº 10, Castellón de la Plana, Spain Postboks 133, Gardermoen, NO-2061, Norway Colonia 810, Oficina 403, Montevideo, Uruguay Bahnhofstraße 25, 86551 Aichach, Germany Bahnhofstraße 25, 86551 Aichach, Germany 190 Elgin Avenue, George Town, Grand Cayman , KY1-9005, Cayman Islands Anchoragelaan 6, 1118 LD Schiphol, Netherlands 2,Vouliagmenis Ave & Papaflessa, 16777 Elliniko, Athens, Attika, Greece Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Box 2154, 438 14, Landvetter, Sweden Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 150 Avenue Yves Farge, 37700, Saint Pierre des Corps, France 562 Avenue du Parc de l’Ile, 92000, Nanterre, France Aéroport de Lyon Saint Exupéry, 69124, Colombier-Saugnieu, France 10-11/FTime Finance Center, No.4001 Shennan Dadao, Shenzhen, Guangdong Province, China 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt Steindamm 55, 20099 Hamburg, Germany Third Floor, One London Square, Cross Lanes, Guildford, GU1 1UN , United Kingdom Sportallee 6, 22335 Hamburg, Germany Rheinstraße 36, 49090 Osnabrück, Germany Kelvin Building, Bramah Avenue, East Kilbride, Glasgow, Scotland, G75 0RD, United Kingdom Sportallee 6, 22335 Hamburg, Germany Grubenweg 4, 83666 Waakirchen-Marienstein, Germany Grubenweg 4, 83666 Waakirchen-Marienstein, Germany Torre A, Calzada Legaria 549, Colonia 10 de Abril, Ciudad de Mexico, C. P. 11250, Mexico Campus Empresarial Arbea - Edificio No 1, Carretera Fuencarral a Alcobendas, Alcobendas, Madrid, Spain Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 22 Grenville Street, St Helier, JE4 8PX, Jersey 22 Grenville Street, St Helier, JE4 8PX, Jersey 2nd North Avenue, Bandra - Kurla Complex, Bandra (East), Mumbai 400 051, Maharashtra, India PCJ Building36 Trafalgar Road, Kingston 10, Jamaica C/O Banks Cooper Associates, 21 Marina Court, Hull, HU1 1TJ, United Kingdom An der Braker Bahn 22, 26122 Oldenburg, Germany An der Braker Bahn 22, 26122 Oldenburg, Germany Wilmington Trust SP Services (London) Limited, Kings Arms Yard, London EC2R 7AF, United Kingdom Luisenstraße 5 a, 26382 Wilhelmshaven, Germany Sportallee 6, 22335 Hamburg, Germany Pervomayskaya street, 32A, 678144, Lensk, Sakha (Yakutiya) Republic, Russian Federation ul. Elbla˛ ska nr 135, 80-718 Gdan´ sk, 80-718, Gdan´ sk, Województwo Pomorskie, Poland 2-2 Sangnam-ri, Chungryang-myun, Ulju-gun, Ulsan 689-863, Republic of Korea Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 236 BP Annual Report and Form 20-F 2016 Moezelweg 101, 3198 LS Europoort, Rotterdam, Netherlands Naz City, Building J, Suite 10 Erbil, Iraq Box 22, SE 230 32 Malmö-Sturup, Sweden Bircham Dyson Bell, 50 Broadway, London, SW1H 0BL, United Kingdom Francisco Behr 20, Barrio Pueyrredon, Comodoro Rivadavia, Provincia del Chubut, Argentina 5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States 20 Rue Contades, 67300, Schiltigheim, France 700 Bond Street, Te Awamutu, New Zealand 5 El Mokhayam El Daiem St, 6th Sector, Nasr City, Egypt Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 6th Flr City Tower, 2 - Sheikh Zayed Road, PO Box 1699, Dubai, United Arab Emirates 900 E. Benson Boulevard, Anchorage, Alaska, 99508, United States Kronestraße 22-23, 29221 Celle, Germany Spaldingstraße 64, 20097 Hamburg, Germany Spaldingstraße 64, 20097 Hamburg, Germany Butaanweg 215, NL-3196 KC Vondelingenplaat, Rotterdam, 3045, Havennummer, Netherlands 14. Related undertakings of the group – continued Maatschap Europoort Terminal (50.00%)g Mach Monument Aviation Fuelling Co. Ltd. (70.00%) Malmo Fuelling Services AB (33.33%) Manchester Airport Storage and Hydrant Company Limited (25.00%) Manpetrol S.A. (60.00%) Mars Oil Pipeline Company (28.50%)g MATELUB S.A.R.L. (Baldersheim/Frankreich) (80.00%) McFall Fuel Limited (30.07%) Mediteranean Gas Co. “MEDGAS” (25.00%) Mehoopany Wind Energy LLC (50.00%)a Mehoopany Wind Holdings LLC (50.00%)a Middle East Lubricants Company LLC (40.00%) Milne Point Pipeline, LLC (50.00%)a Mineralol-Handels-Gesellschaft mbH, Celle (50.00%) Mobene GmbH & Co. KG (50.00%)g Mobene Verwaltungs-GmbH (50.00%) N.V. Rotterdam-Rijn-Pijpleiding Maatschappij (RRP) (44.44%) Natural Gas Vehicles Company “NGVC” (40.00%) New Zealand Oil Services Limited (50.00%) NFX Combustíveis Marítimos Ltda. (50.00%) Nigermed Petroleum S.A. (50.00%) Nord-West Oelleitung GmbH (59.33%) North Ghara Petroleum Company (NOGHCO) (30.00%) North October Petroleum Company “NOPCO” (50.00%) Oberrheinische Mineralolwerke GmbH (33.00%) Ocwen Energy Pty Ltd (49.50%) Oleoductos Canarios, S.A. (20.00%) OptoAtmospherics Inc (27.20%)w Oslo Lufthaven Tankanlegg AS (33.33%) PAE E & P Bolivia Limited (60.00%) PAE Oil & Gas Bolivia Ltda. (60.00%) Pan American Energy Chile Limitada (60.00%) Pan American Energy do Brasil Ltda. (60.00%)a Pan American Energy Holdings Ltd. (60.00%) Pan American Energy Iberica S.L. (60.00%) i F n a n c a i l s t a t e m e n t s 85 El Nasr Road, Cairo, Cairo, Egypt Level 3, 139 The Terrace, Wellington, 6011, New Zealand Avenida Atlântica, no. 1.130, 2nd floor (part), Copacabana, Rio de Janeiro, RJ, 22021-000, Brazil 53rd East Street, Marbella, Swiss Bank Building, 2nd Floor, City of Panama, Republic of Panama Zum Ölhafen 207, 26384 Wilhelmshaven, Germany 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt DEA-Scholven-Straße, 76187 Karlsruhe, Germany GTH Accounting Group Pty Ltd ‘2’, 1A Kitchener Street, Toowoomba QLD 4350, Australia C/ Explanada Tomas Quevedo S/N, 35008 Puerto De La Luz, Las Palmas De G.C, Spain 3500 DuPont Highway, Dover, County of Kent DE 19901, United States Postboks 134, Gardermoen, NO-2061, Norway Trinity Place Annex, Corner of Frederick & Shirley Streets, P.O. Box N-4805, Nassau, Bahamas Cuarto anillo, Avda. Ovidio Barbery N° 4200,Equipetrol Norte, Santa Cruz de la Sierra, Bolivia Nueva de Lyon Nº 145, piso 12, oficina 1203, Edificio Costa, Santiago de Chile, Chile Rua Manoel da Nóbrega n°1280, 10° andar, Sao Paulo, Sao Paulo, 04001-902, Brazil Palm Grove House, P.O. Box 438, Road Town, Tortola, British Virgin Islands Campus Empresarial Arbea - Edificio No 1, Carretera Fuencarral a Alcobendas, Alcobendas, Madrid, Spain Palm Grove House, P.O. Box 438, Road Town, Tortola, British Virgin Islands 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Colonia 810, Oficina 403, Montevideo, Uruguay O´Higgins N° 194, Rio Grande, Argentina O´Higgins N° 194, Rio Grande, Argentina Kronestraße 22-23, 29221 Celle, Germany P O Box 6369, Jeddah21442, Saudi Arabia 6th Floor (c/o Q8 Aviation), Dukes Court, Duke Street, Woking, GU215BH, United Kingdom Route de Pré-Bois 2, 1214, Vernier, Switzerland 70/72 Road 200, Maadi, Cairo, Egypt Villa Tulip 27, An Phu, District 2, Ho Chi Minh City, Vietnam 9360 Glacier Highway, Suite 202, Juneau AK 99801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Bakrie Tower 17th Floor, Rasuna Epicentrum Complex Jl. H.R Rasuna Said, Jakarta, 12940, Indonesia 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 24 Cours Michelet, 92800, Puteaux, France Pan American Energy Investments Ltd. (60.00%) Pan American Energy LLC (60.00%)a Pan American Energy Uruguay S.A. (60.00%) Pan American Fueguina S.A. (60.00%) Pan American Sur S.A. (60.00%) Paul Harling Mineralole GmbH & Co. KG (50.00%)g Peninsular Aviation Services Company Limited (25.00%) Pentland Aviation Fuelling Services Limited (25.00%)b Petrostock SA (50.00%) Pharaonic Petroleum Company “PhPC” (25.00%) Phu My 3 BOT Power Company Limited (33.33%)g Prince William Sound Oil Spill Response Corporation (25.00%) Proteus Oil Pipeline Company, LLC (75.00%)a PT Petro Storindo Energi (30.00%) PTE Pipeline LLC (32.00%)a Raffinerie de Strasbourg (33.33%) Rahamat Petroleum Company (PETRORAHAMAT) (50.00%) 70/72 Road 200, Maadi, Cairo, Egypt Hörhof 1, 95473 Creußen, Germany Raimund Mineraloel GmbH (50.00%) 26 Kifissias Ave. and 2 Paradissou st., 15125 Maroussi, Athens, Greece RAPISA (62.51%) Nideracher 1, 8867, Niederurnen, Switzerland Raststaette Glarnerland AG, Niederurnen (20.00%) Albert Alloo & Sons, 67 Princes Street, Dunedin, New Zealand RD Petroleum Limited (49.00%) Resolution Partners LLP (68.00%)g 1675 Broadway, Denver CO 80202, United States Godorfer Hauptstraße 186, 50997 Köln, Germany Rhein-Main-Rohrleitungstransportgesellschaft mbH (35.00%) Rio Grande Pipeline Company (30.00%)g RocketRoute Limited (29.40%)w Romanian Fuelling Services S.R.L. (50.00%) Rosneft Oil Company (19.75%) Routex B.V. (25.00%) Rudeis Oil Company “RUDOCO” (50.00%) Rundel Mineraloelvertrieb GmbH (50.00%) S&JD Robertson North Air Limited (49.00%) SABA- Sociedade Abastecedora de Aeronaves, Lda (25.00%) SAFCO SA (33.33%) Salzburg Fuelling GmbH (33.00%)a Saraco SA (20.00%) SBB Dortmund GmbH (25.00%) Servicios Logísticos de Combustibles de Aviación, S.L (50.00%) Shanghai SECCO Petrochemical Company Limited (50.00%) No. 557 South Yinhe Road, Shanghai Chemical Industry Park, Caojing, Shanghai, China Sharjah Aviation Services Co. LLC (49.00%)s Sharjah Pipeline Company LLC (49.00%) Shell and BP South African Petroleum Refineries (Pty) Ltd (37.50%)b Shell Mex and B.P. Limited (40.00%)s Shenzhen Cheng Yuan Aviation Oil Company Limited (25.00%) Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Barttelot Court, Barttelot Road, Horsham, West Sussex, RG12 1DQ, United Kingdom 59 Aurel Vlaicu Street, Otopeni, Ilfov County, Romania 26/1 Sofiyskaya Embankment, 115035, Moscow, Russian Federation Strawinskylaan 1725, 1077XX Amsterdam, Netherlands 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt Am Güterbahnhof 4, 78224 Singen, Germany 1 Wellheads Avenue, Dyce, Aberdeen, AB217PB, United Kingdom Grupo Operacional de Combustiveis do Aeroporto de Lisboa, Edificio 19, 1.º Sala Saba, Lisboa, Portugal International airport “El. Venizelos”, Athens, Greece Innsbrucker Bundesstraße 95, 5020 Salzburg, Austria Route de Pré-Bois 17, 1216, Cointrin, Switzerland Westfalendamm 166, 44141 Dortmund, Germany Vía de los Poblados 1, Madrid, Spain P O Box- 97, Sharjah, United Arab Emirates Sharjah 42244, Sharjah, UAE, Sharjah, United Arab Emirates 1 Refinery Road, Prospecton, 4110, South Africa Shell Centre, London, SE17NA, United Kingdom Fu Yong Town, Bao An county, ShenZhen Airport, Guangdong Province, China The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 237 14. Related undertakings of the group – continued 5 Clementi Loop, Singapore 129816, Singapore Causeway House, 1 Dane Street, Bishop’s Stortford, Hertfordshire, CM23 3BT, United Kingdom Holstenhofweg 47, 22043 Hamburg, Germany Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States LOB 16, Suite #309, Jebel Ali Free Zone, Dubai, PO BOX 262794, United Arab Emirates Shell International Petroleum, Co Ltd, Shell Centre, 8 York Road, London, SE1 7NA, United Kingdom 1 Place Gustave Eiffel, 94150, Rungis, France P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands Baiyun Internation Airport, Guangzhou, China 27 Route du Bassin Numéro 6, 92230, Gennevilliers, France Room 316 Excellence Mansion, No.98 Fuhua 1Rd, Futian District, Shenzhen, China Shenzhen Dapeng LNG Marketing Company Limited (30.00%) Sherbino I Wind Farm LLC (50.00%)a SKA ENERGY HOLDINGS LIMITED (50.00%) SM Realisations Limited (In Liquidation) (40.00%) Société d’Avitaillement et de Stockage de Carburants Aviation “SASCA” (40.00%)a Société de Gestion de Produits Pétroliers - SOGEPP (37.00%) South Caucasus Pipeline Company Limited (28.83%)s South Caucasus Pipeline Holding Company Limited (28.83%) South Caucasus Pipeline Option Gas Company Limited (28.83%) South China Bluesky Aviation Oil Company Limited (24.50%) ST-Airport Services Pte Ltd (33.00%) Stansted Intoplane Company Limited (20.00%) STDG Strassentransport Dispositions Gesellschaft mbH (50.00%) Stockholm Fuelling Services Aktiebolag (25.00%) Box 7, 190 45 Arlanda, Sweden Stonewall Resources Ltd. (60.00%) Palm Grove House, P.O. Box 438, Road Town, Tortola, British Virgin Islands Sunrise Oil Sands Partnership (50.00%)g c/o Husky Oil Operations Limited, 707 - 8th Avenue SW, Calgary AB T2P 1H5, Canada Tankanlage AG Mellingen (33.33%) Birmenstorferstrasse 2, 5507, Mellingen, Switzerland TAR - Tankanlage Ruemlang AG (27.32%) Zwüscheteich, 8153, Rümlang, Switzerland TAU Tanklager Auhafen AG (50.00%) Auhafenstrasse 10a, 4132, Muttenz, Switzerland Team Terminal B.V. (22.80%) Rijndwarsweg 3, Havennr 5719, 3198LK Europoort Rotterdam, Netherlands Tecklenburg GmbH & Co. Energiebedarf KG (50.00%)g Wesermünder Straße 1, 27729 Hambergen, Germany Tecklenburg GmbH (50.00%) Wesermünder Straße 1, 27729 Hambergen, Germany Terminales Canarios, S.L. (50.00%) Carretera de San Andréss/n, La Jurada-María Jiménez, Santa Cruz de Tenerife, Spain TFSS Turbo Fuel Services Sachsen GbR (20.00%)f Sportallee 6, 22335 Hamburg, Germany TGFH Tanklager-Gesellschaft Frankfurt-Hahn GbR (50.00%)g Sportallee 6, 22335 Hamburg, Germany TGH Tankdienst-Gesellschaft Hamburg GbR (33.33%)g Sportallee 6, 22335 Hamburg, Germany TGHL Tanklager-Gesellschaft Hannover-Langenhagen GbR Sportallee 6, 22335 Hamburg, Germany (50.00%)g TGK Tanklagergesellschaft Koln-Bonn (20.00%)g The Baku-Tbilisi-Ceyhan Pipeline Company (30.10%)y The Consolidated Petroleum Company Limited (50.00%)s The Consolidated Petroleum Supply Company Limited (50.00%) The New Zealand Refining Company Limited (21.19%) The Sullom Voe Association Limited (33.33%)s TLM Tanklager Management GmbH (49.00%)a TLS Tanklager Stuttgart GmbH (45.00%) Torsina Oil Company “TORSINA” (37.50%) TRaBP GbR (75.00%)g Trafineo GmbH & Co. KG (75.00%)g Trafineo Verwaltungs-GmbH (75.00%) Transalpine Olleitung in Osterreich Gesellschaft m.b.H. (20.00%) TransTank GmbH (50.00%) Unimar LLC (50.00%)a United Gas Derivatives Company “UGDC” (33.33%) United Kingdom Oil Pipelines Limited (33.50%) Ursa Oil Pipeline Company LLC (22.69%)a VIC CBM Limited (50.00%) Virginia Indonesia Co. CBM Limited (50.00%) Virginia Indonesia Co., LLC (50.00%)a Virginia International Co., LLC Walton-Gatwick Pipeline Company Limited (42.33%) West London Pipeline and Storage Limited (30.50%) West Morgan Petroleum Company (PETROMORGAN) (50.00%) Wiri Oil Services Limited (27.78%) Xact Downhole Telemetry Inc (27.00%)w Yangtze River Acetyls Co., Ltd (51.00%) Am Stadthafen 60, 45881 Gelsenkirchen, Germany Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 55 Road 18, Maadi, Cairo, Egypt 5-7 Alexandra Road, Hemel Hempstead, Hertfordshire, HP2 5BS, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Eni House, 10 Ebury Bridge Road, London, SW1W 8PZ, United Kingdom Eni House, 10 Ebury Bridge Road, London, SW1W 8PZ, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 5-7 Alexandra Road, Hemel Hempstead, Hertfordshire, HP2 5BS, United Kingdom 5-7 Alexandra Road, Hemel Hempstead, Hertfordshire, HP2 5BS, United Kingdom 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt Marsden Point, Ruakaka, New Zealand Town Hall, Lerwick, Shetland, ZE10HB, United Kingdom Am Tankhafen 4, 4020 Linz, Austria Zum Ölhafen 49, 70327 Stuttgart, Germany 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt Huestraße 25, 44787, Bochum, Germany Wittener Straße 56, Bochum, Germany Wittener Straße 56, Bochum, Germany Kienburg 11, 9971 Matrei in Osttirol, Austria 303 Parnell Rd, Parnell, Auckland, New Zealand 906 55th Avenue NE, Calgary AB, Canada 97 Weijiang Road (in the Petrochemical Park), Changshou District, Chongqing, China Sportallee 6, 22335 Hamburg, Germany P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands Shell Centre, London, SE17NA, United Kingdom Shell Centre, London, SE17NA, United Kingdom u B and D shares v 23.75% ordinary shares and 23.75% A shares w Preference shares x Unlimited redeemable shares y 1.89% A shares and 40.80% B shares a Member interest b A shares c A and B shares d Ordinary shares, B shares and preference shares e Common stock and preference shares f Ordinary shares and preference shares g Partnership interest h A, B and D shares i Interest held directly by BP p.l.c. j 99% held directly by BP p.l.c. k 1% held directly by BP p.l.c. l Ordinary shares, A and B shares m0.008% held directly by BP p.l.c. n Ordinary shares and cumulative redeemable preference shares o 79.93% ordinary shares and 99.06% preference shares p 93.59% ordinary shares and 81.01% preference shares q Subsidiary in which the group does not hold a majority of the voting rights but exercises control over it r Ordinary shares and redeemable preference shares s B shares t 100% ordinary shares and 58.63% preference shares The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 238 BP Annual Report and Form 20-F 2016 Additional disclosures 240 Selected financial information 242 Liquidity and capital resources 244 Upstream analysis by region 249 Downstream plant capacity 251 Oil and gas disclosures for the group 257 Environmental expenditure 257 Regulation of the group’s business 261 Legal proceedings 265 International trade sanctions 266 Material contracts 266 Property, plant and equipment 266 Related-party transactions 266 Corporate governance practices 267 Code of ethics 267 Controls and procedures 268 Principal accountants’ fees and services 268 Directors’ report information 269 Disclosures required under Listing Rule 9.8.4R 269 Cautionary statement BP Annual Report and Form 20-F 2016 239 A d d i t i o n a l i l d s c o s u r e s Selected financial information This information, insofar as it relates to 2016, has been extracted or derived from the audited consolidated financial statements of the BP group presented on page 114. Note 1 to the financial statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related notes elsewhere herein. Income statement data Sales and other operating revenues Profit (loss) before interest and taxation Finance costs and net finance expense relating to pensions and other post- retirement benefits Taxation Non-controlling interests Profit (loss) for the yeara Inventory holding (gains) losses*, before tax Taxation charge (credit) on inventory holding gains and losses RC profit (loss)* for the year Net (favourable) unfavourable impact of non-operating items* and fair value accounting effects*, before tax Taxation charge (credit) on non-operating items and fair value accounting effects Underlying RC profit* for the year Earnings per shareb – cents Profit (loss) for the yeara per ordinary share Basic Diluted RC profit (loss) for the year per ordinary share* Underlying RC profit for the year per ordinary share* Dividends paid per share – cents – pence Additions to non-current assetsc Capital expenditure on an accruals basis*b d Organic capital expenditure*e Inorganic capital expenditure* Balance sheet data (at 31 December) Total assets Net assets Share capital BP shareholders’ equity Finance debt due after more than one year Net debt to net debt plus equity* Ordinary share dataf Basic weighted average number of shares Diluted weighted average number of shares 2016 2015 2014 2013 2012 $ million except per share amounts 183,008 222,894 353,568 379,136 375,765 (430) (7,918) 6,412 31,769 19,769 (1,865) 2,467 (57) 115 (1,597) 483 (1,653) 3,171 (82) (6,482) 1,889 (569) (999) (5,162) (1,462) (947) (223) 3,780 6,210 (1,917) 8,073 (1,548) (6,463) (307) (1,638) (6,880) (234) 23,451 11,017 290 (60) 594 (183) 23,681 11,428 6,746 (3,162) 2,585 15,067 (4,000) 8,234 (4,171) (9,244) (1,009) 6,110 (467) 5,905 12,136 13,428 17,071 0.61 0.60 (5.33) 13.79 40.00 29.418 21,204 18,440 939 19,379 (35.39) (35.39) (28.18) 32.22 40.00 26.383 20,080 18,748 710 19,458 20.55 20.42 43.90 66.00 39.00 23.850 26,492 22,892 601 23,493 123.87 123.12 125.08 70.92 36.50 23.399 36,916 24,600 12,007 36,607 263,316 96,843 5,284 95,286 51,666 26.8% 261,832 98,387 5,049 97,216 46,224 21.6% 284,305 112,642 5,023 111,441 45,977 16.7% 305,690 130,407 5,129 129,302 40,811 16.2% 57.89 57.50 60.05 89.70 33.00 20.852 29,268 23,950 1,097 25,047 300,466 119,752 5,261 118,546 38,767 18.7% Share million 18,745 18,855 18,324 18,324 18,385 18,497 18,931 19,046 19,028 19,158 a Profit attributable to BP shareholders. b A reconciliation to GAAP information is provided on page 285. c Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures*; and investments in associates*. d The definitions of capital expenditure on an accruals basis and inorganic capital expenditure have been revised to exclude asset exchanges as they are non-cash transactions. Previously reported amounts have been amended. Previously reported amounts for organic capital expenditure are unchanged. e 2016 includes amounts relating to the renewal of a 10% interest in the Abu Dhabi onshore oil concession for which new ordinary shares in BP were issued. f The number of ordinary shares shown has been used to calculate the per share amounts. * See Glossary. 240 BP Annual Report and Form 20-F 2016 Additional information Non-operating items Non-operating items are charges and credits included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors to understand better and evaluate the group’s reported financial performance. An analysis of non-operating items is shown in the table below. Upstream Impairment and gain (loss) on sale of businesses and fixed assetsa Environmental and other provisions Restructuring, integration and rationalization costs Fair value gain (loss) on embedded derivatives Otherb c Downstream Impairment and gain (loss) on sale of businesses and fixed assetsa Environmental and other provisions Restructuring, integration and rationalization costs Fair value gain (loss) on embedded derivatives Other Rosneft Impairment and gain (loss) on sale of businesses and fixed assetsa Environmental and other provisions Restructuring, integration and rationalization costs Fair value gain (loss) on embedded derivatives Other Other businesses and corporate Impairment and gain (loss) on sale of businesses and fixed assetsa Environmental and other provisions Restructuring, integration and rationalization costs Fair value gain (loss) on embedded derivatives Gulf of Mexico oil spill responsed Otherc Total before interest and taxation Finance costsd Taxation credit (charge) Total after taxation 2016 2015 2,391 (8) (373) 32 (289) 1,753 405 (73) (300) – (56) (24) 62 – – – (39) 23 (1,204) (24) (410) 120 (717) (2,235) 131 (108) (607) – (6) (590) – – – – – – – (134) (90) – (6,640) (55) (170) (151) (71) – (11,709) (155) (6,919) (12,256) (5,167) (494) 2,833 (15,081) (247) 4,056 (2,828) (11,272) $ million 2014 (6,576) (60) (100) 430 8 (6,298) (1,190) (133) (165) – (82) (1,570) 225 – – – – 225 (304) (180) (176) – (781) (10) (1,451) (9,094) (38) 4,512 (4,620) a See Financial statements – Note 4 for further information on impairments. b 2016 includes the write-off of $147 million in relation to the value ascribed to licences in the deepwater Gulf of Mexico, and $334 million in relation to the value ascribed to the BM-C-34 licence in Brazil, both as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. 2016 also includes a $319-million reversal relating to Block KG D6 in India. 2014 includes a $395-million write-off relating to Block KG D6 in India. c 2015 principally relates to BP’s share of impairment losses recognized by equity-accounted entities. d See Financial statements – Note 2 for further details regarding costs relating to the Gulf of Mexico oil spill. A d d i t i o n a l d i s c l o s u r e s BP Annual Report and Form 20-F 2016 241 Liquidity and capital resources Financial framework We maintain our financial framework to support the pursuit of value growth for shareholders, while ensuring a secure financial base. BP’s objective over time is to grow sustainable free cash flow* through a combination of material growth in operating cash flow excluding amounts related to the Gulf of Mexico oil spill* and a strong focus on capital discipline, providing a sound platform to grow shareholder distributions. The initial priority is to address the dilution that arises from the undiscounted scrip dividend alternative we currently have in place. We would then aim to balance disciplined investment for even stronger growth with our objective of growing distributions to shareholders over the long term. Any surplus cash over and above that required for capital investment and dividend payments will be biased towards further shareholder distributions through buybacks or other mechanisms. While maintaining safe and reliable operations, preserving core growth activities and with an ongoing commitment to sustaining the dividend, our principal objective in the near term is to re-establish a balance in our financial framework. This rebalanced framework is underpinned by the resetting of both the capital and cash cost base of the group in response to the lower price environment, as well as the growth in operating cash flow we anticipate in our businesses. The group’s controllable cash costs reduction target was reached a year ahead of schedule in 2016 and, including the impact of deals announced at the end of 2016, we expect organic capital expenditure in 2017 to be between $15-17 billion. We aim to manage gearing* within a 20-30% band while weak market conditions remain and maintain a significant liquidity buffer. As the portfolio additions are assimilated into our plans during 2017 and we maintain our focus on both capital and costs, we expect to continue to optimize our overall spend driving down the organic cash rebalance point through the year. Operating cash flow excluding amounts related to the Gulf of Mexico oil spill is expected to cover organic capital expenditure and the dividend at around $60 per barrel by the end of 2017. As we further assimilate recently announced deals into our plans and maintain our focus on both capital and costs, we will continue to optimize our overall spend driving the balance point closer to $55 per barrel by the end of 2017. Based on our current planning assumptions we would expect our cash balance point to reduce to around $35-40 per barrel over the next five years. Deepwater Horizon cash payments are expected to be in the range of $4.5-5.5 billion in 2017 with the larger part of the outflow in the first half of the year. With amounts to resolve the remaining business economic loss claims expected to be substantially paid this year we expect the total Deepwater Horizon cash payments to fall to around $2 billion in 2018, and then to step down to a little over $1 billion per annum from 2019. In 2017 we expect divestment proceeds to be in the range of $4.5-5.5 billion, weighted towards the second half of the year, and from 2018 to average the historical norm of around $2-3 billion per annum. 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 2017 and beyond. Dividends and other distributions to shareholders The dividend is determined in US dollars, the economic currency of BP, and the dividend level is regularly reviewed by the board. The quarterly dividend was increased to 10 cents per share for the third quarter of 2014 and has been maintained at this level in each subsequent quarter. The total dividend distributed to BP shareholders in 2016 was $7.5 billion (2015 $7.3 billion). Shareholders have the option to receive a scrip dividend in place of receiving cash. In 2016 the total dividend paid in cash was $4.6 billion (2015 $6.7 billion). Details of share repurchases to satisfy the requirements of certain employee share-based payment plans are set out on page 278. There were no other buyback programmes conducted during 2016. Financing the group’s activities The group’s principal commodities, oil and gas, are priced internationally in US dollars. Group policy has generally been to minimize economic exposure to currency movements by financing operations with US dollar debt. Where debt is issued in other currencies, including euros, it is generally swapped back to US dollars using derivative contracts, or else hedged by maintaining offsetting cash positions in the same currency. The cash balances of the group are mainly held in US dollars or swapped to US dollars and holdings are well-diversified to reduce concentration risk. The group is not, therefore, exposed to significant currency risk regarding its borrowings. Also see Risk factors on page 49 for further information on risks associated with prices and markets and Financial statements – Note 28. The group’s gross debt at 31 December 2016 amounted to $58.3 billion (2015 $53.2 billion). Of the total gross debt, $6.6 billion is classified as short term at the end of 2016 (2015 $6.9 billion). See Financial statements – Note 25 for more information on the short-term balance. Net debt* was $35.5 billion at the end of 2016, an increase of $8.3 billion from the 2015 year-end position of $27.2 billion. The ratio of gross debt to gross debt plus equity at 31 December 2016 was 37.6% (2015 35.1%). The ratio of net debt to net debt plus equity* was 26.8% at the end of 2016 (2015 21.6%). See Financial statements – Note 26 for gross debt, which is the nearest equivalent measure on an IFRS basis, and for further information on net debt. Cash and cash equivalents of $23.5 billion at 31 December 2016 (2015 $26.4 billion) are included in net debt. We manage our cash position to ensure the group has adequate cover to respond to potential short- term market illiquidity, and expect to maintain a robust cash position. The group also has undrawn committed bank facilities of $7.4 billion (see Financial statements – Note 28 for more information). We believe that the group has sufficient working capital for foreseeable requirements, taking into account the amounts of undrawn borrowing facilities and levels of cash and cash equivalents, and the ongoing ability to generate cash. Standard & Poor’s Ratings’ long-term credit rating for BP is A negative (stable outlook) and the Moody’s Investors Service rating is A2 (positive outlook). The group’s sources of funding, its access to capital markets and maintaining a strong cash position are described in Financial statements – Note 24 and Note 28. Further information on the management of liquidity risk and credit risk, and the maturity profile and fixed/floating rate characteristics of the group’s debt are also provided in Financial statements – Note 25 and Note 28. During 2016 significant progress was made in resolving outstanding claims arising from the 2010 Deepwater Horizon accident and oil spill. As a result, a judgement has been made that a reliable estimate can now be made for all remaining material liabilities arising from the incident. Any further outstanding Deepwater Horizon related claims are not expected to have a material impact on the group’s financial performance. See Financial statements – Note 2 for further information. Off-balance sheet arrangements At 31 December 2016, the group’s share of third-party finance debt of equity-accounted entities was $14.6 billion (2015 $11.8 billion). These amounts are not reflected in the group’s debt on the balance sheet. The group has issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the balance sheet, at 31 December 2016 were $309 million (2015 $35 million) in respect of liabilities of joint ventures* and associates* and $370 million (2015 $163 million) in respect of liabilities of other third parties. Of these amounts, $298 million (2015 $22 million) of the joint ventures and associates guarantees relate to borrowings and for other third- party guarantees, $338 million (2015 $119 million) relate to guarantees of borrowings. Details of operating lease commitments, which are not recognized on the balance sheet, are shown in the table below and provided in Financial statements – Note 27. The information above contains forward-looking statements, which by their nature involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. You are urged to read the Cautionary statement on page 269 and Risk factors on page 49, which describe the risks and uncertainties that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements. 242 BP Annual Report and Form 20-F 2016 Contractual obligations The following table summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2016 and the proportion of that expenditure for which contracts have been placed. Capital expenditure Committed of which is contracted Total 2017 32,377 11,207 12,823 5,868 2018 9,060 3,462 2019 4,568 1,070 2020 2,588 427 2021 1,328 106 2022 and thereafter 2,010 274 $ million Payments due by period Capital expenditure is considered to be committed when the project has received the appropriate level of internal management approval. For joint operations*, the net BP share is included in the amounts above. In addition, at 31 December 2016, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to $2,318 million. Contracts were in place for $2,083 million of this total. The following table summarizes the group’s principal contractual obligations at 31 December 2016, distinguishing between those for which a liability is recognized on the balance sheet and those for which no liability is recognized. Further information on borrowings is given in Financial statements – Note 25 and more information on operating leases is given in Financial statements – Note 27. $ million Payments due by period Expected payments by period under contractual obligations Total 2017 2018 2019 2020 2021 Balance sheet obligations Borrowingsa Finance lease future minimum lease paymentsb Decommissioning liabilitiesc Environmental liabilitiesc Gulf of Mexico oil spill liabilitiesd Pensions and other post-retirement benefitse Off-balance sheet obligations Operating lease future minimum lease paymentsf Unconditional purchase obligationsg 63,508 1,321 18,119 1,626 21,644 24,288 7,755 96 287 316 3,056 1,619 6,962 94 303 311 1,853 1,792 7,586 90 258 177 1,272 1,772 7,015 87 321 154 1,225 1,761 7,353 85 319 134 1,200 1,759 130,506 13,129 11,315 11,155 10,563 10,850 14,255 140,490 154,745 3,315 64,743 68,058 2,194 16,155 18,349 1,915 10,624 12,539 1,520 7,512 9,032 1,022 5,536 6,558 2022 and thereafter 26,837 869 16,631 534 13,038 15,585 73,494 4,289 35,920 40,209 Total 285,251 81,187 29,664 23,694 19,595 17,408 113,703 a Expected payments include interest totalling $5,842 million ($1,162 million in 2017, $1,032 million in 2018, $895 million in 2019, $757 million in 2020, $618 million in 2021 and $1,378 million thereafter). b Expected payments include interest totalling $687 million ($54 million in 2017, $52 million in 2018, $47 million in 2019, $44 million in 2020, $40 million in 2021 and $450 million thereafter). c The amounts are undiscounted. d The amounts presented are undiscounted. Gulf of Mexico oil spill liabilities are included in the group balance sheet, on a discounted basis, within other payables. See Financial statements – Note 2 for further information. e Represents the expected future contributions to funded pension plans and payments by the group for unfunded pension plans and the expected future payments for other post-retirement benefits. f The future minimum lease payments are before deducting related rental income from operating sub-leases. In the case of an operating lease entered into solely by BP as the operator of a joint operation, the amounts shown in the table represent the net future minimum lease payments, after deducting amounts reimbursed, or to be reimbursed, by joint operation partners. Where BP is not the operator of a joint operation, BP’s share of the future minimum lease payments are included in the amounts shown, whether BP has co-signed the lease or not. Where operating lease costs are incurred in relation to the hire of equipment used in connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project. g Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms (such as fixed or minimum purchase volumes, timing of purchase and pricing provisions). Agreements that do not specify all significant terms, or that are not enforceable, are excluded. The amounts shown include arrangements to secure long-term access to supplies of crude oil, natural gas, feedstocks and pipeline systems. In addition, the amounts shown for 2017 include purchase commitments existing at 31 December 2016 entered into principally to meet the group’s short-term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts is discussed in Financial statements – Note 28. The following table summarizes the nature of the group’s unconditional purchase obligations. A d d i t i o n a l d i s c l o s u r e s Unconditional purchase obligations Total 2017 Crude oil and oil products Natural gas Chemicals and other refinery feedstocks Power Utilities Transportation Use of facilities and services 63,034 26,041 5,801 4,624 486 21,814 18,690 41,953 14,619 2,576 2,747 151 1,218 1,479 2018 7,312 4,544 1,413 856 137 1,028 865 2019 4,103 2,326 1,467 407 68 919 1,334 Total 140,490 64,743 16,155 10,624 $ million Payments due by period 2021 2,020 1,097 38 90 18 1,286 987 5,536 2022 and thereafter 4,682 1,897 78 365 51 16,063 12,784 35,920 2020 2,964 1,558 229 159 61 1,300 1,241 7,512 BP Annual Report and Form 20-F 2016 243 Upstream analysis by region Our upstream operations are set out below by geographical area, with associated significant events for 2016. BP’s percentage working interest in oil and gas assets is shown in brackets. Working interest is the cost-bearing ownership share of an oil or gas lease. Consequently, the percentages disclosed for certain agreements do not necessarily reflect the percentage interests in reserves and production. In addition to exploration, development and production activities, our upstream business also includes midstream and LNG supply activities. Midstream activities involve the ownership and management of crude oil and natural gas pipelines, processing facilities and export terminals, LNG processing facilities and transportation, and our natural gas liquids (NGLs) processing business. Our LNG supply activities are located in Abu Dhabi, Angola, Australia, Indonesia and Trinidad. We market around 20% of our LNG production using BP LNG shipping and contractual rights to access import terminal capacity in the liquid markets of the US (via Cove Point), the UK (via the Isle of Grain), Spain (in Bilbao) and Italy (in Rovigo), with the remainder marketed directly to customers. LNG is supplied to customers in markets including Japan, South Korea, China, the Dominican Republic, Argentina, Brazil and Mexico. Europe BP is active in the North Sea and the Norwegian Sea. Our activities focus on maximizing recovery from existing producing fields and new field developments. BP’s production is generated from three key areas: the Shetland area, comprising the Magnus, Clair, Foinaven and Schiehallion fields; the central area, comprising the Bruce, Andrew and ETAP fields; and Norway, through our equity accounted 30% interest in Aker BP established in 2016 (see below). • We announced that we doubled our interest in the Culzean development in the UK Central North Sea in May, following the acquisition of an additional 16% interest from JX Nippon. The acquisition increases our interest in the development from 16% to 32%. The Maersk-operated Culzean field development was sanctioned at the end of August 2015, and we expect production to start in 2019 and continue into the 2030s. • BP and Det norske oljeselskap announced the creation of an independent oil and gas company in June, with the transaction completing at the end of September. It combines the assets and expertise from the Norwegian exploration and production operations of both companies to form the largest Norwegian independent oil and gas producer. Under the terms of the transaction, the BP Norge and Det norske businesses have combined and been renamed Aker BP ASA. Aker BP is independently operated and listed on the Oslo Stock Exchange. It is owned by the former Det norske shareholder Aker (40%), BP (30%) and independent shareholders (including other former Det norske shareholders) (30%). Aker BP is an equity- accounted associate over which BP has significant influence. Aker BP benefits from the combined strength of Det norske’s efficient, streamlined operating model and BP’s long experience in Norwegian offshore operations, asset knowledge, technical skills and international experience. BP received a cash payment of $250 million including working capital and interest adjustments as part of the transaction. • On 2 October, 95 tonnes of oil in water was released to the sea from the Clair platform, as a result of a technical issue with the system designed to separate the mixed production fluids of water, oil and gas. The release was stopped within an hour of the issue being identified and Clair production was taken offline. Production restarted on 25 October, resulting in a full-year production impact of 0.5mboe/d BP net. • Operations at the Rhum gas field in the North Sea continue under a licence issued by the US Office of Foreign Asset Control, which licenses US persons and US owned and controlled companies to support Rhum activities. This expires on 30 September 2017. Work is ongoing to reduce BP’s reliance on US persons ahead of a new licence application expected in the second quarter of 2017. The field is owned by BP (50%) and the Iranian Oil Company (IOC) under a joint operating agreement. EU sanctions and certain US secondary sanctions in respect of Iran have been lifted or suspended as part of the Joint Comprehensive Plan of Action. See International trade sanctions on page 265. 244 BP Annual Report and Form 20-F 2016 • We made strong progress on the Quad 204 project in the Schiehallion and Loyal fields, West of Shetland in 2016. Glen Lyon, the replacement floating production, storage and offloading vessel (FPSO) arrived on station in June 2016 and all 21 risers are now attached. Final commissioning activities are underway with first oil expected in 2017. • On 24 January 2017 BP announced that it has agreed to sell 25% of its 100% stake in Magnus, a 25% interest in a number of associated pipelines and a 3% interest in the Sullom Voe Terminal (SVT) on Shetland to EnQuest. The sale price of $85 million is expected to be met by EnQuest from the sharing of future cash flows from the assets and the agreement will not include any upfront payment to BP. Under the terms of the agreement, EnQuest has an option, exercisable between 1 July 2018 and 15 January 2019, to purchase BP’s remaining 75% interest in Magnus, a further 9% interest in SVT and the remainder of BP’s interests in the associated pipelines for a consideration of $300 million. The deal remains subject to regulatory and other third-party approvals. In the UK North Sea, BP operates the Forties Pipeline System (FPS) (BP 100%), an integrated oil and NGLs transportation and processing system that handles production from around 80 fields in the central North Sea. The system has a capacity of more than 675mboe/d, with average throughput in 2016 of 439mboe/d. On 3 April 2017 BP announced that it had agreed to sell the FPS business to INEOS for a consideration of up to $250 million, subject to partner, regulatory and other third-party approvals. BP also operates the Sullom Voe oil and gas terminal in Shetland. North America Our upstream activities in North America take place in five areas: deepwater Gulf of Mexico, the Lower 48 states, Alaska, Canada and Mexico. BP has around 300 lease blocks in the deepwater Gulf of Mexico, making us one of the largest portfolio owners, and operates four production hubs. • In the first quarter of 2016 we completed evaluation of the Kepler 3 discovery well, drilled in late 2015, and this was tied into the Na Kika platform and began production in the fourth quarter of 2016. BP is the operator (50%), with Shell holding the other 50%. • Also in the first quarter, a successful exploration well on the Chevron-operated Guadalupe prospect (BP 50%) was completed. Further appraisal drilling commenced in the fourth quarter. In addition, an appraisal well in the Chevron-operated Tiber prospect (BP 31%) was completed in the second quarter and a Suspension of Production request was filed in September 2016. This notice is used in situations where the licence is approaching expiry without immediate plans for further drilling activity but where there are plans for further development of the prospect. • We completed drilling operations on two wells that commenced in the fourth quarter of 2015; the Chevron-operated Gibson prospect and the appraisal well on the Hopkins discovery. In the third quarter of 2016 BP disposed of 33.3% of its working interest in the Hopkins discovery to Anadarko, along with operatorship. BP’s remaining working interest in the Hopkins discovery is 66.7%. In the fourth quarter costs of $276 million were written off in relation to Hopkins upon reclassification of the project to the development phase. The Hopkins discovery is being renamed Constellation. • In May we announced the start-up of the water injection major project at the Thunder Horse platform (BP 75%). The project is expected to extend the production life of the field and boost recovery of oil and natural gas from one of the field’s three main reservoirs. The project follows on from improvement work over the last three years, including refurbishment of the platform’s existing topsides and subsea equipment. • We announced the start-up of the South Expansion major project at our Thunder Horse platform in January 2017. Two producing wells came online at start-up and two more will be delivered in the near future. The project scope includes a new subsea production system two miles to the south of the existing Thunder Horse platform. The system is a collection point for four wells connected to the platform by two lines installed on the seabed. • In the fourth quarter of 2016 BP sanctioned the Mad Dog Phase 2 project, which will include a new floating production platform with the capacity to produce up to 140,000 gross barrels of crude oil per day from up to 14 production wells. Oil production is expected to begin in late 2021. In 2013 BP (60.5% and operator) and co-owners, BHP Billiton and Union Oil Company of California, an affiliate of Chevron U.S.A. Inc., decided to re-evaluate the Mad Dog Phase 2 project after an initial design proved too complex and costly. Since then, BP has worked with co-owners and contractors to simplify and standardize the platform’s design, reducing the overall project cost by about 60%. Today, the leaner $9-billion project, which also includes capacity for water injection, is projected to be profitable at much lower oil prices. The second Mad Dog platform will be moored approximately six miles to the southwest of the existing platform. All partners in the project have announced that they have taken a final investment decision (FID) on Mad Dog Phase 2. • During the year $233 million was written off in connection with unsuccessful exploration activity on the Silvergate and Sweetwater prospects. • See also Significant judgement: oil and natural gas accounting on page 128 for further information on exploration leases. The US Lower 48 onshore business has significant activities across Arkansas, Colorado, New Mexico, Oklahoma, Texas and Wyoming producing natural gas, oil, NGLs and condensate. It is organized into five geographic business units, with a 1.4 billion boe proved reserve base as at 31 December 2016, predominantly in unconventional reservoirs (tight gas*, shale gas and coalbed methane). This resource spans 3.1 million net developed acres and has approximately 9,700 operated gross wells, with daily net production around 300mboe/d. Since the beginning of 2015, our US Lower 48 onshore business has been operating as a separate business while remaining part of our Upstream segment. It has its own governance, processes and systems and is designed to increase competitive performance through swift decision making and innovation, while maintaining BP’s commitment to safe, reliable and compliant operations. For further information on the use of hydraulic fracturing in our shale gas assets see page 45. BP’s onshore US crude oil and product pipelines and related transportation assets are included in the Downstream segment. In Alaska BP Exploration (Alaska) Inc. (BPXA) operated nine North Slope oilfields in the Greater Prudhoe Bay area at the end of 2016. Our focus continues to be safe and reliable operations, renewing BP’s Alaska North Slope infrastructure and minimizing oil production decline. Infrastructure renewal activities in 2016 included compressor replacements, fire and gas system upgrades, safety system upgrades, pipeline renewal and facility siting projects. BP’s daily net production in Alaska in 2016 was 107.9mboe/d. Production decline is being managed through annual drilling programmes and rig and non-rig wellwork programmes. BP also owns significant interests in eight producing fields operated by others, as well as a non-operating interest in the Liberty prospect. • In April the Point Thomson major project commenced production. BP holds a 32% working interest in the field and ExxonMobil is the operator. • The Alaska LNG project concept includes a planned three train North Slope gas treatment plant, approximately 800 miles of pipeline to tidewater and a three-train liquefaction facility, with an estimated capacity of 3bcf/d (up to 18.5 million tonnes per annum) supplied from the Prudhoe Bay and Point Thomson fields. In early 2016, all co-venturers agreed that the current project cost of supply is not competitive in the market. Furthermore, a study prepared by WoodMackenzie in August 2016 confirmed this and identified commercial levers that could enable the project to compete. In December 2016 the producer parties agreed to terminate the existing governance agreement and transition the project to be led by the Alaska Gasline Development Corporation, a state entity. In 2017 the State of Alaska will progress the US Federal Energy Regulatory Commission (FERC) permitting work, identify commercial structure alternatives that deliver a competitive cost of supply, and define a financing plan for future stages of the project. On 22 January 2017 BP Alaska LNG LLC (BPAL) and AGDC executed a Cooperation Agreement detailing BPAL’s commitment to helping the state further its 2017 priorities, detailed above. Future project milestones will be updated following the 2017 project re-definition and transition. BP Pipelines (Alaska) Inc. (BPPA) owns a 49% interest in the Trans- Alaska Pipeline System (TAPS). TAPS transports crude oil from Prudhoe Bay on the Alaska North Slope to the port of Valdez in south- east Alaska. In April 2012 the two non-controlling owners of TAPS, Koch (3.08%) and Unocal (1.37%) gave notice to BPPA, ExxonMobil (21.1%) and ConocoPhillips (29.1%) of their intention to withdraw as owners of TAPS. The transfer of Koch’s interest to the remaining owners was completed in 2012. The remaining owners and Unocal have not yet reached agreement regarding the terms for the transfer of Unocal’s interest in TAPS. • In November 2015, the FERC issued an order to BPPA addressing the TAPS tariff rate filings for years 2009 and 2010 reducing the approved tariff rate. As a result of the order, BPPA refunded impacted shipping costs to BPXA and third-party shippers in 2016. Due to these lower shipping costs, BPXA subsequently paid material incremental production tax and royalty payments to the State of Alaska in 2016 and January 2017 for the years 2009 and 2010 as well as 2011 to 2015. In Canada, BP is focused on oil sands development as well as pursuing offshore exploration opportunities. For our oil sands development we use in-situ steam-assisted gravity drainage (SAGD) technology, which uses the injection of steam into the reservoir to warm the bitumen so that it can flow to the surface through producing wells. We hold interests in three oil sands leases through the Sunrise Oil Sands and Terre de Grace partnerships and the Pike Oil Sands joint operation*. In addition, we have significant offshore exploration licences in the Canadian Beaufort Sea, Nova Scotia as well as Newfoundland and Labrador. • Following the start of oil production in March 2015 at the Sunrise Phase 1 in-situ oil sands project in Alberta (BP 50%), production is expected to ramp-up to 52,000 barrels per day (gross) in 2018. • In 2016 BP (50%) and partner Hess (50%) submitted an environmental impact statement for a drilling programme offshore Nova Scotia which is planned to commence in 2018. • In January 2016 BP was awarded three exploration licences in partnership with Statoil and ExxonMobil in the Flemish Pass Basin offshore of Newfoundland and Labrador, Canada (BP 33%) with Statoil operating all three licences. Additionally, BP acquired interests in two exploration licences from Statoil in the same basin (BP 10%). Finally, in January 2017 BP was also the successful bidder in a further four exploration blocks, of which three are in the West Orphan Basin offshore of Newfoundland and Labrador (BP 50% and operator with partners Hess and Noble Energy), and one in the East Orphan Basin (BP 60% and operator with partner Noble Energy). In Mexico, BP (33.3%) as a member of a consortium with Statoil and Total was awarded two exploration blocks in the Deepwater bid round 1.4 held on 5 December 2016, Block 1 (2,381km2 in 2,437m water depth) and Block 3 (3,287km2 in 1,763m water depth) in the Saline Basin. BP also conducts activity in Mexico through Pan American Energy LLC (PAE), an equity-accounted joint venture* with Bridas Corporation, in which BP has a 60% interest. • On 30 October 2016, PAE, via its wholly owned subsidiary, Hokchi S.A., became the first privately owned company to spud a well in Mexico post Mexico’s reform of its energy industry. This is the first of four commitment wells that will be drilled under the terms of the licence agreement. In addition, on 12 December 2016, Hokchi S.A. agreed to increase its working interest in the block from 60% to 80% in a transaction with its partner, E&P Hydrocarboros y Servicios, S.A. South America BP has upstream activities in Brazil and Trinidad & Tobago, and through PAE, in Argentina and Bolivia. In February 2016 ANCAP, the Uruguayan oil and gas regulator, approved the relinquishment of all of our blocks in Uruguay. A d d i t i o n a l d i s c l o s u r e s BP Annual Report and Form 20-F 2016 245 • In July BP Trinidad and Tobago LLC and ALNG announced the sanction of the Trinidad onshore compression project. The project is 100% funded and owned by BP Trinidad and Tobago and will be operated by ALNG. It is designed to increase production from low-pressure wells in existing acreage in the Columbus Basin using an additional inlet compressor at the Point Fortin Atlantic LNG plant. The majority of the construction work will be undertaken by ALNG with BP and other shareholder representation. The project is 95% complete and start-up is planned for the second quarter of 2017. Africa BP’s upstream activities in Africa are located in Algeria, Angola, Egypt, Libya, Mauritania and Senegal. In Algeria BP, Sonatrach and Statoil are partners in the In Salah (BP 33.15%) and In Amenas (BP 45.89%) projects that supply gas to the domestic and European markets. • The Bourarhat agreement expired in September 2014 and talks with Sonatrach to negotiate new terms were not successful. Discussions with them to close out the project were initiated in the first half of 2015 and are ongoing. • The In Salah Southern Fields major project start-up was announced in February 2016. The project is the latest stage in the development of the In Salah Gas joint venture, which commenced production in 2004. • In July train 3 at In Amenas restarted following the completion of repairs after the terrorist attack in January 2013. • In November the start of testing and ramp-up activities at the In Amenas compression project was announced. This project is designed to enhance production in order to fill the capacity of all three processing trains at the facility. In Angola BP is present in seven major deepwater licences offshore and is operator in three of these, blocks 18 and 31 that are producing oil and block 24 that is in the exploration phase. BP’s block 19 exploration licence expired on 31 December 2016 and the block has now been relinquished. BP also has an equity interest in the Angola LNG plant (BP 13.6%). • The Angola LNG plant, which had been shut down for planned repairs since April 2014 restarted in 2016 and is producing and supplying LNG and liquid cargoes to the global market. • During the year, BP was involved in two discoveries in Angola, Golfinho and Zalophus, the latter being a condensate discovery. Further assessment of their potential commerciality is underway. In Egypt BP and its partners currently produce 10% of Egypt’s liquids* production and almost 30% of its gas production. • On 26 February an exploration discovery was announced on the Nooros East prospect in Egypt by the operator Eni who has now tied it back for production. Eni holds a 75% interest in the Abu Madi West concession, while BP holds a 25% interest. The well was developed and commenced production in April 2016. Additionally, a successful discovery in Nooros West was made in the third quarter of 2016. Two wells are currently on production from the West segment. This combined with further development well drilling in the Nooros main segment, which was discovered in July 2015, led to the total Nooros production increasing to 850mmscf/d of gas, and 7,000 barrels of condensate (154,000 barrels of oil equivalent gross per day), less than 18 months after first gas. • In June we announced the Baltim SW-1 gas discovery in the Baltim South Development Lease in the East Nile Delta. The discovery, which is located 12 kilometres from shoreline, is situated along the same trend as the Nooros field discovered in July 2015. Following appraisal of the discovery, BP and its partner Eni are working on the development options for this discovery. In Brazil BP has interests in 21 exploration concessions across five basins. • Our partner Anadarko took over from BP as operator of block BM-C-32 (Itaipu) located in the Campos Basin. This transfer is expected to facilitate the realization of development efficiencies for this and the adjacent block, BM-C-30 (Wahoo), where Anadarko is also the operator. BP continues to consider options for a potential joint development of Itaipu/Wahoo or tie-back. A decision to move into front-end engineering for a potential long- term test is planned in 2017. • In the third quarter of 2016 BP completed its analysis of the prospectivity of block BM-C-34 and concluded that there were no commercially viable prospects resulting in a write-off of $601 million ($334 million as a non-operating item*). Asset relinquishment is pending regulatory approval. • After disappointing exploration results, BP and Petrobras relinquished their interests in block BM-CE-2 in the Ceara basin. All assets associated with the block have been written off between 2014 and 2016. • In the fourth quarter of 2016 BP completed its seismic acquisition programme in block BAR-M-346 in the Barreirinhas basin. The seismic processing and prospect inventory development will be progressed in 2017. An extension request was submitted to the Brazilian National Petroleum Agency (ANP) and approved for the block extending the licence until the end of 2019. • BP continued to progress the preparatory activities for drilling exploration wells in the Foz de Amazonas basin, with a BP-operated well situated in block FZA-M-59, scheduled to spud in early 2018. Additionally, BP expects drilling activity to commence on its other non-operated interests in Foz de Amazonas in 2017 (BP 30%). An extension request was submitted to ANP and approved for the five non-operated blocks extending the licence until the third quarter of 2020. • In the South Campos basin, Petrobras notified BP in August 2016 of their decision to exit from block BM-C-35. BP has taken over operatorship and has a 100% working interest post Petrobras’ exit. A revised appraisal plan was submitted to ANP and approved, the decision to move into the second stage of the appraisal plan and commit to an additional pre-salt well or end the appraisal plan is expected in the third quarter of 2017. In Argentina and Bolivia BP conducts activity through PAE. • On 13 December 2016 the Bolivian Branch of PAE, E&P Bolivia Limited, entered into, jointly with the other members of the Caipipendi Consortium and Yacimientos Petroliferos Fiscales Bolivianos, an addendum to the Caipipendi Operation Contract for an extension of up to 15 years from the expiration of the original term (2 May 2031) subject to certain investment and operational conditions being met over the next five years. The addendum is subject to the authority of the Bolivian National Congress and approval is expected to be received in the first half of 2017. • PAE signed an agreement on 7 December 2016 to acquire a 55% working interest and operatorship in the Coiron Amargo Sur Este Block located in the Vaca Muerte area of Neuquen, Argentina from Madalena Energy, Inc. In Trinidad & Tobago BP holds exploration and production licences and PSAs covering 1.8 million acres offshore of the east and north-east coast. Facilities include 13 offshore platforms and two onshore processing facilities. Production comprises gas and associated liquids. BP also has a shareholding in the Atlantic LNG (ALNG) liquefaction plant, BP’s shareholding averages 39% across four LNG trains* with a combined capacity of 15 million tonnes per annum. BP sells gas to each of the LNG trains, supplying 100% of the gas for train 1, 50% for train 2, 75% for train 3 and around 67% of the gas for train 4. All LNG from train 1 and most of the LNG from trains 2 and 3 is sold to third parties in the US and Europe under long-term contracts. BP’s remaining equity LNG entitlement from trains 2, 3 and 4 is marketed via BP’s LNG marketing and trading function to markets in the US, UK, Spain and South America. 246 BP Annual Report and Form 20-F 2016 • Also in June we announced, together with the Egyptian Natural Gas Holding Company (EGAS), that we had sanctioned development of the Atoll Phase 1 project. The project is an early production scheme involving the conversion of the existing exploration well to a producing well, the drilling of two additional wells and the installation of the necessary tie-ins and facilities required to produce from the field, and is expected to bring gas to the Egyptian domestic gas market starting in the first half of 2018. BP has a 100% interest in the concession. BP recently completed multiple transportation and processing agreements to accelerate the development of the Atoll field. Onshore processing will be handled by the existing West Harbour gas processing facilities. BP announced the Atoll discovery in March 2015. • In September we announced we had signed concession amendments for the Temsah (BP 50%), Ras El Barr (BP 50%) and Nile Delta offshore (BP 25%) concessions in Egypt. These amendments allow for the economic development of the Nooros field in the Nile Delta offshore concession. • Following the devaluation of the Egyptian pound on 3 November 2016, the IMF approved a $12 billion extended fund facility, S&P upgraded its outlook for Egypt to ‘Stable’ and Egypt’s foreign currency reserves increased from $19 billion in October 2016 to $23 billion in December 2016. • In November BP announced that it had agreed to buy a 10% interest in the Shorouk concession offshore Egypt, which contains the Zohr gas field from Eni, for $375 million plus reimbursement of Eni’s past expenditure from 1 January 2016 up to completion of the deal. The deal completed on 23 February. The transaction also includes the option to buy an additional 5% interest on the same terms by 31 December 2017. First gas is expected in 2017. In Libya we partner with the Libyan Investment Authority (LIA) in an exploration and production-sharing agreement (EPSA) to explore acreage in the onshore Ghadames and offshore Sirt basins (BP 85%). BP and the LIA served the National Oil Corporation (NOC) with notices of force majeure in August 2014 as a result of underlying circumstances which rendered the delivery of the EPSA obligations impossible. BP and the NOC signed an Interim Arrangement Agreement in January 2016 under which the EPSA did not terminate automatically in August 2016 (two years from the notice of force majeure). BP wrote off all balances associated with the Libya EPSA in 2015. In December BP announced that it had signed agreements with Kosmos Energy to acquire a 62% working interest, including operatorship, of Kosmos’ exploration blocks in Mauritania and a 32.49% effective working interest in Kosmos’ Senegal exploration blocks. Together these blocks cover approximately 33,000km2. BP intends to invest nearly $1 billion, mostly in the form of a multi-year exploration and development carry to acquire a 62% interest and operatorship of offshore Blocks C-6, C-8, C-12 and C-13 in Mauritania and an effective 32.49% interest in the Saint-Louis Profond and Cayar Profond blocks in Senegal. Under the terms of the agreements, BP and Kosmos have also agreed that Kosmos will remain the technical operator for the exploration phase of the project and drill three new exploration wells beginning in 2017. In addition to the existing blocks, the companies have agreed to co-operate in areas of mutual interest in offshore Mauritania, Senegal and the Gambia with Kosmos acting as the exploration operator and BP as the development operator. The Mauritania agreement completed in December and the Senegal agreement in February 2017. In June 2016 BP’s non-operated Tarhazoute offshore (BP 45%) and Foum Assaka offshore (BP 26.3%) licences in Morocco were not extended and lapsed. This was in agreement with partners and followed a detailed review of the prospects. Exit is in progress on BP’s third licence in Morocco – the Essaouira offshore licence (BP 45%). Asia BP has activities in Western Indonesia, China, Azerbaijan, Oman, Abu Dhabi, India, Iraq, Russia and Kuwait. In November BP completed the sale of all of its interests in the Sanga- Sanga PSA (BP 38%) in Western Indonesia operated by Virginia Indonesia Company LLC (VICO) to subsidiaries of PT. Saka Energi Indonesia by a share sale. In China BP has a 30% equity stake in the Guangdong LNG regasification terminal and trunkline project with a total storage capacity of 640,000m3, making it the first and only international oil company invested in China’s LNG import infrastructure. The project is supplied under a long-term contract with Australia’s North West Shelf venture (BP 16.67%). • In March BP and China National Petroleum Corporation (CNPC) signed a production-sharing contract for shale gas exploration, development and production in the Neijiang-Dazu block in the Sichuan Basin, China. The contract is BP’s first shale gas PSC in China and covers an area of approximately 1,500km2. CNPC will be operator for this project. • In September we announced that we had signed a second PSC for shale gas exploration, development and production with CNPC. The PSC covers an area of approximately 1,000km2 at Rong Chang Bei in the Sichuan Basin. In Azerbaijan, BP operates two PSAs, Azeri-Chirag-Gunashli (ACG) (BP 35.8%) and Shah Deniz (BP 28.83%) and also holds a number of other exploration leases. • In 2012 certain EU and US regulations concerning restrictive measures against Iran were issued, which impact the Shah Deniz joint venture in which Naftiran Intertrade Co Ltd (NICO), a subsidiary of the National Iranian Oil Company, holds a 10% interest. The EU sanctions and certain US secondary sanctions in respect of Iran have been lifted or suspended as part of the Joint Comprehensive Plan of Action. For further information see International trade sanctions on page 265. • In May BP and the State Oil Company of the Republic of Azerbaijan (SOCAR) signed a memorandum of understanding, followed by a heads of agreement in November, to jointly explore potential prospects in Block D230 in the North Absheron basin in the Azerbaijan sector of the Caspian Sea. • Implementation of the Shah Deniz Stage 2 project continues successfully. In May, the Shah Deniz consortium announced the award of a $1.5 billion contract for the transport and installation of the deeperwater subsea production systems for Shah Deniz Stage 2. In September the jacket for one of the Shah Deniz Stage 2 platforms commenced its journey for offshore installation. The Shah Deniz Stage 2 project is now more than 83% complete in terms of engineering, procurement and construction, and remains on target for first gas in 2018. • In December the Azerbaijan International Operating Company and the ACG Joint Operating Company operated by BP, signed a non-binding letter of intent with SOCAR covering the future development of the AGC field in the Azerbaijan sector of the Caspian Sea. The agreement will cover the development of the field until the end of 2049. The letter of intent agrees the key commercial terms for the contract extension and enables the parties to proceed with negotiations and finalize fully-termed agreements. BP holds a 30.1% interest in and operates the Baku-Tbilisi-Ceyhan (BTC) oil pipeline. The 1,768km pipeline transports oil from the BP-operated ACG oilfield and gas condensate from the Shah Deniz gas field in the Caspian Sea, along with other third-party oil, to the eastern Mediterranean port of Ceyhan. The pipeline has a capacity of 1mmboe/d with an average throughput in 2016 of 694mboe/d. BP is technical operator of, and currently holds a 28.83% interest in, the 693km South Caucasus Pipeline (SCP). The pipeline takes gas from Azerbaijan through Georgia to the Turkish border and has a capacity of 143mboe/d with average throughput in 2016 of 121mboe/d. BP (as operator of Azerbaijan International Operating Company) also operates the Western Export Route Pipeline that transports ACG oil to Supsa on the Black Sea coast of Georgia, with an average throughput of 83mboe/d in 2016. BP also holds a 12% interest in the Trans Anatolian Natural Gas Pipeline that will transport Shah Deniz gas across Turkey, and a 20% interest in the Trans Adriatic Pipeline that will take gas through Greece and Albania into Italy. BP Annual Report and Form 20-F 2016 247 A d d i t i o n a l d i s c l o s u r e s In Oman, BP is continuing with development activity on the BP-operated Khazzan field in block 61 (BP 60%). • As at 31 December 2016 the Khazzan major project was 92.5% complete and on track to deliver first gas in the second half of 2017. The vast majority of the infrastructure is already in place including roads, power lines and a 60km water pipeline from Hanya. The two-train central gas processing facility has also progressed well and is 97% complete. Mechanical completion and handover to commissioning has commenced. The water treatment plant, waste management area and electricity substation have also been completed along with accommodation units for the workforce of up to 13,000. The Khazzan drilling programme is also on track with 45 of the 50 wells needed by first gas already drilled. Thirty well sites are mechanically completed and connection to the central gas processing facility via the duplex gathering system is on track for the second quarter of 2017. • In November BP and Oman Oil Company Exploration & Production signed an agreement, announced in February, with the government of the Sultanate of Oman amending the Oman Block 61 exploration and production-sharing agreement (EPSA) to extend the licence area, paving the way for further development of the Khazzan field. The extension adds more than 1,000km2 to the south and west of the original 2,700km2 of Block 61. The extension will allow a second phase of development, accessing additional gas in the area already identified by drilling activity within the original block. Development of this additional resource is subject to final approval of the government of Oman and of BP – both expected in 2017. In Abu Dhabi, we have an equity interest of 14.67% in an offshore concession. We also have a 10% equity shareholding in the Abu Dhabi Gas Liquefaction Company that supplied approximately 5.9 million tonnes of LNG (306bcfe regasified). • In December BP signed an agreement with the Supreme Petroleum Council of the Emirate of Abu Dhabi, in its capacity as representative of the government, and the Abu Dhabi National Oil Company (ADNOC) that grants BP a 10% interest in the Abu Dhabi ADCO onshore oil concession. In addition to the interest in the ADCO concession, BP becomes a 10% shareholder in OPCO, the Abu Dhabi Company for Onshore Petroleum Operations Limited, which operates the concession. The agreement includes BP becoming asset leader for the Bab asset group within the concession. The other partners in this concession are ADNOC (60%), Total (10%), INPEX (5%), and GS Energy (3%). Renewal of the ADCO concession interest (covering materially the same acreage as BP’s prior interest that expired in 2014) to 31 December 2054 provides BP with long-term access to significant and competitive production and reserves. In March 2016 we announced that BP and Kuwait Petroleum Corporation have signed a framework agreement to explore possible joint opportunities for investment and co-operation in future oil, gas, trading and petrochemicals ventures. In addition to enhancing oil and gas recovery from Kuwait’s existing resource base, the agreement also includes the intention to study opportunities for joint investment in future oil and gas exploration both inside Kuwait and globally. Other elements of the agreement cover possible future oil and gas trading deals including LNG trading and related ventures. In March 2016 BP also signed an Enhanced Technical Service Agreement for south and east Kuwait conventional oilfields, which includes the Burgan field, with Kuwait Oil Company. In India, we have a 30% participating interest in three oil and gas PSAs operated by Reliance Industries Limited (RIL), and have a stake with RIL in a 50:50 joint venture (India Gas Solution Private Limited) for the sourcing and marketing of gas in India. • On 21 March 2016, the government of India issued a natural gas pricing policy which allows pricing and marketing freedom for new discoveries in deep water, ultra deep water, and high pressure high temperature reservoirs. In light of this, BP and its partners are progressing the investment plans to develop the discovered resources. • In the fourth quarter of 2016 we recorded a $234-million impairment reversal and a $319-million reversal of exploration write-off relating to Block KG D6 in India. This reversal is mainly driven by an increased confidence in the progress of projects by BP and its partners. • Block CYD5 was relinquished in 2016 due to lack of material accumulations and poor future exploration prospectivity, resulting in an exploration write-off of $216 million. In Iraq, BP holds a 47.6% working interest and is the lead contractor in the Rumaila technical service contract in southern Iraq. Rumaila is one of the world’s largest oil fields, comprising five producing reservoirs. Despite continued instability and sectarian violence in the north and west of the country, BP operations continued as planned in the south. In Russia, in addition to its 19.75% equity interest in Rosneft, BP holds a 20% interest in Taas-Yuryakh Neftegazodobycha (Taas), a joint venture with Rosneft that is developing the Srednebotuobinskoye oil and gas condensate field in East Siberia (see Rosneft on page 35 for further details). • In October 2016 Rosneft and BP completed a transaction to create a new joint venture, Yermak Neftegaz LLC, to conduct onshore exploration in the West Siberian and Yenisei-Khatanga basins. Yermak Neftegaz is 51% owned by Rosneft and 49% by BP, and currently holds seven exploration and production licences. The venture will also carry out further appraisal work on the Baikalovskoye field, an existing Rosneft discovery in the Yenisei- Khatanga area of mutual interest. Australasia BP has activities in Australia and Eastern Indonesia. In Australia BP is one of seven participants in the North West Shelf (NWS) venture, which has been producing LNG, pipeline gas, condensate, LPG and oil since the 1980s. Six partners (including BP) hold an equal 16.67% interest in the gas infrastructure and an equal 15.78% interest in the gas and condensate reserves, with a seventh partner owning the remaining 5.32%. BP also has a 16.67% interest in some of the NWS oil reserves and related infrastructure. The NWS venture is currently the principal supplier to the domestic market in Western Australia and one of the largest LNG export projects in the region, with five LNG trains in operation. BP’s net share of the capacity of NWS LNG trains 1-5 is 2.7 million tonnes of LNG per year. BP is also one of five participants in the Browse LNG venture (operated by Woodside) and holds a 17.33% interest. • In March 2016, following substantial completion of front-end engineering and design (FEED) work, the Browse joint venture participants decided not to progress with the floating LNG development at that time due to the economic and market environment. The Browse joint venture participants are evaluating and narrowing a range of alternative development options, and will select one in 2018. • The NWS Persephone project (BP 16.67%) is on schedule to deliver first gas in the second half of 2017 and is the second of the NWS series of subsea tie-back projects that have been undertaken to extend the production plateau and supply additional gas to the NWS’s five existing LNG trains and domestic gas plant. The project is operated by Woodside. • In October BP announced it had taken the decision not to progress an exploration drilling programme in the Great Australian Bight (GAB), offshore South Australia. The decision follows the review and refresh of BP’s upstream strategy earlier this year. BP has determined that the GAB project would not be able to compete for capital investment with other upstream opportunities in its global portfolio in the foreseeable future and the related assets have been written off. BP’s 5.375% interest in the Jansz-lo field and its 12.5% interests in the Geryon, Orthrus, Maenad, Urania and Eurytion fields (which are part of the Greater Gorgon project) were sold in June 2016. 248 BP Annual Report and Form 20-F 2016 In Papua Barat, Eastern Indonesia, BP operates the Tangguh LNG plant. In 2016 BP increased its interest in Tangguh from 37.16% to 40.22%. The asset comprises 14 producing wells, two offshore platforms, two pipelines and an LNG plant with two production trains. It has a total capacity of 7.6 million tonnes of LNG per annum. Tangguh supplies LNG to customers in Indonesia, China, South Korea, Mexico and Japan through a combination of long, medium and short- term contracts. • In July BP announced that the FID for the development of the Tangguh expansion project had been approved. The FID allows the project to continue with the planned investment to build a third LNG processing train (train 3), adding 3.8 million tonnes per annum of production capacity to the existing facility, bringing total plant capacity to 11.4 million tonnes per annum. The project also includes two offshore platforms, 13 new production wells, an expanded LNG loading facility, and supporting infrastructure. This will enable BP to play an important role in supporting Indonesia’s growing energy demand, with 75% of its annual LNG production sold to the Indonesian state electricity company PT. PLN (Persero). First production from train 3 is expected in 2020. • In November BP received approval from the government of Indonesia to relinquish its 100% interests in the West Aru I and II PSAs. Approval to relinquish its 32% interests in the Chevron- operated West Papua I and Ill PSAs is still pending. Downstream plant capacity The following table summarizes BP group’s interests in refineries and average daily crude distillation capacities as at 31 December 2016. Fuels value chain US US North West US East of Rockies Europe Rhine Iberia Rest of world Australia New Zealand Southern Africa Total BP share of capacity at 31 December 2016 Country Refinery US Cherry Point Whiting Toledo Germanyc Netherlands Spain Bayernoild Gelsenkirchen Lingen Rotterdam Castellón Australia New Zealand Whangareid South Africa Kwinana Durband Crude distillation capacitiesa Group interestb (%) BP share thousand barrels per day 100 100 50 10 100 100 100 100 100 21.2 50 236 430 80 746 22 265 95 377 110 869 149 26 90 265 1,880 a Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period. b BP share of equity, which is not necessarily the same as BP share of processing entitlements. c On 31 December 2016 we completed the dissolution of our German refining joint operation* with Rosneft. The capacities reported here reflect BP’s share of capacities after the dissolution. d Indicates refineries not operated by BP. A d d i t i o n a l d i s c l o s u r e s BP Annual Report and Form 20-F 2016 249 Petrochemicals production capacitya The following table summarizes BP group’s share of petrochemicals production capacities as at 31 December 2016. Geographical area US Europe UK Belgium Germany Rest of world Trinidad & Tobago China Indonesia South Korea Malaysia Taiwan Total BP share of capacity at 31 December 2016 BP share of capacity thousand tonnes per annumb Site Group interestc (%) PTA PX Acetic acid Olefins and derivatives Cooper River Texas City Hulle Geel Gelsenkirchenf Mülheimf Point Lisas Caojing Chongqing Nanjing Zhuhaig Merak Ulsan Kertih Mai Liao Taichung 100 100 100 100 100 100 36.9 50 51 50 85 100 34-51 70 50 61.4 1,400 – 1,400 – 1,300 – – 1,300 – – – – 2,500 500 – – – 500 3,500 6,200 – 900 900 – 700 – – 700 – – – – – – – – – – – 1,600 – 600d 600 500 – – – 500 – – 200 300 – – 300h 400 200 – 1,400 2,500 – – – – – 3,300 – 3,300 – 3,500 – – – – – – – – 3,500 6,800 Product Others – 100 100 200 – – 300 500 700 – 100 – – – 100h – – – 900 1,500 18,600 a Petrochemicals production capacity is the proven maximum sustainable daily rate (MSDR) multiplied by the number of days in the respective period, where MSDR is the highest average daily rate ever achieved over a sustained period. b Capacities are shown to the nearest hundred thousand tonnes per annum. c Includes BP share of non-operated equity-accounted entities, as indicated. d Group interest is quoted at 100%, reflecting the capacity entitlement, which is marketed by BP. e The site has capacity under 100,000 tonnes per annum for a speciality product (e.g. naphthalene dicarboxylate and ethylidene diacetate). f Due to the integrated nature of these plants with our Gelsenkirchen refinery, the income and expenditure of these plants is managed and reported through the fuels business. On 31 December 2016 we completed the dissolution of our German refining joint operation with Rosneft. The capacities reported here reflect BP’s share of capacities after the dissolution. g BP Zhuhai Chemical Company Ltd is a subsidiary* of BP, the capacity of which is shown above at 100%. h Group interest varies by product. 250 BP Annual Report and Form 20-F 2016 Oil and gas disclosures for the group Resource progression BP manages its hydrocarbon resources in three major categories: prospect inventory, contingent resources and reserves. When a discovery is made, volumes usually transfer from the prospect inventory to the contingent resources category. The contingent resources move through various sub-categories as their technical and commercial maturity increases through appraisal activity. At the point of final investment decision, most proved reserves will be categorized as proved undeveloped (PUD). Volumes will subsequently be recategorized from PUD to proved developed (PD) as a consequence of development activity. When part of a well’s proved reserves depends on a later phase of activity, only that portion of proved reserves associated with existing, available facilities and infrastructure moves to PD. The first PD bookings will typically occur at the point of first oil or gas production. Major development projects typically take one to five years from the time of initial booking of PUD to the start of production. Changes to proved reserves bookings may be made due to analysis of new or existing data concerning production, reservoir performance, commercial factors and additional reservoir development activity. Volumes can also be added or removed from our portfolio through acquisition or divestment of properties and projects. When we dispose of an interest in a property or project, the volumes associated with our adopted plan of development for which we have a final investment decision will be removed from our proved reserves upon completion of the transaction. When we acquire an interest in a property or project, the volumes associated with the existing development and any committed projects will be added to our proved reserves if BP has made a final investment decision and they satisfy the SEC’s criteria for attribution of proved status. Following the acquisition, additional volumes may be progressed to proved reserves from non-proved reserves or contingent resources. Non-proved reserves and contingent resources in a field will only be recategorized as proved reserves when all the criteria for attribution of proved status have been met and the volumes are included in the business plan and scheduled for development, typically within five years. BP will only book proved reserves where development is scheduled to commence after more than five years, if these proved reserves satisfy the SEC’s criteria for attribution of proved status and BP management has reasonable certainty that these proved reserves will be produced. At the end of 2016 BP had material volumes of proved undeveloped reserves held for more than five years in Trinidad, the North Sea, Egypt, Canada and the Gulf of Mexico. These are part of ongoing infrastructure-led development activities for which BP has a historical track record of completing comparable projects in these countries. We have no proved undeveloped reserves held for more than five years in our onshore US developments. In each case the volumes are being progressed as part of an adopted development plan where there are physical limits to the development timing such as infrastructure limitations, contractual limits including gas delivery commitments, late life compression and the complex nature of working in remote locations. Over the past five years, BP has annually progressed a weighted average 18% (18% for 2015 five-year average) of our group proved undeveloped reserves (including the impact of disposals and price acceleration effects in PSAs) to proved developed reserves. This equates to a turnover time of about five and a half years. We expect the turnover time to remain near this level and anticipate the volume of proved undeveloped reserves held for more than five years to remain about the same. Proved reserves as estimated at the end of 2016 meet BP’s criteria for project sanctioning and SEC tests for proved reserves. We have not halted or changed our commitment to proceed with any material project to which proved undeveloped reserves have been attributed in light of lower oil and gas prices. BP has responded to the downturn in prices by enhancing the efficiency and productivity of our operations. In 2016 we progressed 1,134mmboe of proved undeveloped reserves (586mmboe for our subsidiaries* alone) to proved developed reserves through ongoing investment in our subsidiaries’ and equity- accounted entities’ upstream development activities. Total development expenditure, excluding midstream activities, was $14,143 million in 2016 ($11,145 million for subsidiaries and $2,998 million for equity-accounted entities). The major areas with progressed volumes in 2016 were Argentina, Iraq, Trinidad, Russia and the US. Revisions of previous estimates for proved undeveloped reserves are due to changes relating to field performance, well results or changes in commercial conditions including price impacts; there were no individually material revisions during the year. The following tables describe the changes to our proved undeveloped reserves position through the year for our subsidiaries and equity-accounted entities and for our subsidiaries alone. Subsidiaries and equity-accounted entities volumes in mmboea Proved undeveloped reserves at 1 January 2016 Revisions of previous estimates Improved recovery Discoveries and extensions Purchases Sales Total in year proved undeveloped reserves changes Proved developed reserves reclassified as undeveloped Progressed to proved developed reserves by development activities (e.g. drilling/completion) Proved undeveloped reserves at 31 December 2016 7,687 376 177 457 271 (59) 1,222 22 (1,134) 7,797 Subsidiaries only volumes in mmboea Proved undeveloped reserves at 1 January 2016 Revisions of previous estimates Improved recovery Discoveries and extensions Purchases Sales Total in year proved undeveloped reserves changes Proved developed reserves reclassified as undeveloped Progressed to proved developed reserves by development activities (e.g. drilling/completion) Proved undeveloped reserves at 31 December 2016 4,211 185 170 75 54 (57) 427 17 (586) 4,068 a Because of rounding, some totals may not agree exactly with the sum of their component parts. BP bases its proved reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements. BP only applies technologies that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. BP applies high-resolution seismic data for the identification of reservoir extent and fluid contacts only where there is an overwhelming track record of success in its local application. In certain cases BP uses numerical simulation as part of a holistic assessment of recovery factor for its fields, where these simulations have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In certain deepwater fields BP has booked proved reserves before production flow tests are conducted, in part because of the significant safety, cost and environmental implications of conducting these tests. The industry has made substantial technological improvements in understanding, measuring and delineating reservoir properties without the need for flow tests. To determine reasonable certainty of commercial recovery, BP employs a general method of reserves assessment that relies on the integration of three types of data: • well data used to assess the local characteristics and conditions of reservoirs and fluids * See Glossary. BP Annual Report and Form 20-F 2016 251 A d d i t i o n a l d i s c l o s u r e s • field scale seismic data to allow the interpolation and extrapolation of these characteristics outside the immediate area of the local well control • data from relevant analogous fields. Well data includes appraisal wells or sidetrack holes, full logging suites, core data and fluid samples. BP considers the integration of this data in certain cases to be superior to a flow test in providing understanding of overall reservoir performance. The collection of data from logs, cores, wireline formation testers, pressures and fluid samples calibrated to each other and to the seismic data can allow reservoir properties to be determined over a greater volume than the localized volume of investigation associated with a short-term flow test. There is a strong track record of proved reserves recorded using these methods, validated by actual production levels. Governance BP’s centrally controlled process for proved reserves estimation approval forms part of a holistic and integrated system of internal control. It consists of the following elements: • Accountabilities of certain officers of the group to ensure that there is review and approval of proved reserves bookings independent of the operating business and that there are effective controls in the approval process and verification that the proved reserves estimates and the related financial impacts are reported in a timely manner. • Capital allocation processes, whereby delegated authority is exercised to commit to capital projects that are consistent with the delivery of the group’s business plan. A formal review process exists to ensure that both technical and commercial criteria are met prior to the commitment of capital to projects. • Group audit, whose role is to consider whether the group’s system of internal control is adequately designed and operating effectively to respond appropriately to the risks that are significant to BP. • Approval hierarchy, whereby proved reserves changes above certain threshold volumes require immediate review and all proved reserves require annual central authorization and have scheduled periodic reviews. The frequency of periodic review ensures that 100% of the BP proved reserves base undergoes central review every three years. BP’s vice president of segment reserves is the petroleum engineer primarily responsible for overseeing the preparation of the reserves estimate. He has more than 30 years of diversified industry experience, with more than 10 years spent managing the governance and compliance of BP’s reserves estimation. He is a past member of the Society of Petroleum Engineers Oil and Gas Reserves Committee and of the American Association of Petroleum Geologists Committee on Resource Evaluation and is the current chair of the bureau of the United Nations Economic Commission for Europe Expert Group on Resource Classification. No specific portion of compensation bonuses for senior management is directly related to proved reserves targets. Additions to proved reserves is one of several indicators by which the performance of the Upstream segment is assessed by the remuneration committee for the purposes of determining compensation bonuses for the executive directors. Other indicators include a number of financial and operational measures. BP’s variable pay programme for the other senior managers in the Upstream segment is based on individual performance contracts. Individual performance contracts are based on agreed items from the business performance plan, one of which, if chosen, could relate to proved reserves. Compliance International Financial Reporting Standards (IFRS) do not provide specific guidance on reserves disclosures. BP estimates proved reserves in accordance with SEC Rule 4-10 (a) of Regulation S-X and relevant Compliance and Disclosure Interpretations (C&DI) and Staff Accounting Bulletins as issued by the SEC staff. By their nature, there is always some risk involved in the ultimate development and production of proved reserves including, but not limited to: final regulatory approval; the installation of new or additional 252 BP Annual Report and Form 20-F 2016 infrastructure, as well as changes in oil and gas prices; changes in operating and development costs; and the continued availability of additional development capital. All the group’s proved reserves held in subsidiaries and equity-accounted entities are estimated or assured by the group’s petroleum engineers. DeGolyer & MacNaughton (D&M), an independent petroleum engineering consulting firm, has estimated the net proved crude oil, condensate, natural gas liquids (NGLs) and natural gas reserves, as of 31 December 2016, of certain properties owned by Rosneft as part of our equity-accounted proved reserves. The properties evaluated by D&M account for 100% of Rosneft’s net proved reserves as of 31 December 2016. The net proved reserves estimates prepared by D&M were prepared in accordance with the reserves definitions of Rule 4-10(a)(1)-(32) of Regulation S-X. All reserves estimates involve some degree of uncertainty. BP has filed D&M’s independent report on its reserves estimates as an exhibit to this Annual Report on Form 20-F filed with the SEC. Our proved reserves are associated with both concessions (tax and royalty arrangements) and agreements where the group is exposed to the upstream risks and rewards of ownership, but where our entitlement to the hydrocarbons* is calculated using a more complex formula, such as with PSAs. In a concession, the consortium of which we are a part is entitled to the proved reserves that can be produced over the licence period, which may be the life of the field. In a PSA, we are entitled to recover volumes that equate to costs incurred to develop and produce the proved reserves and an agreed share of the remaining volumes or the economic equivalent. As part of our entitlement is driven by the monetary amount of costs to be recovered, price fluctuations will have an impact on both production volumes and reserves. We disclose our share of proved reserves held in equity-accounted entities (joint ventures* and associates*), although we do not control these entities or the assets held by such entities. BP’s estimated net proved reserves and proved reserves replacement 86% of our total proved reserves of subsidiaries at 31 December 2016 were held through joint operations* (84% in 2015), and 31% of the proved reserves were held through such joint operations where we were not the operator (34% in 2015). Estimated net proved reserves of crude oil at 31 December 2016a b c UK Rest of Europe US Rest of North Americad South America Africa Rest of Asia Australasia Subsidiaries Equity-accounted entities Total Developed Undeveloped 155 – 826 42 9 317 1,107 32 2,487 3,573 6,060 274 – 497 209 11 42 245 14 1,291 2,529 3,819 million barrels Total 429 – 1,322 251 20 358 1,352 46 3,778 6,101 9,879 Estimated net proved reserves of natural gas liquids at 31 December 2016a b million barrels UK Rest of Europe US Rest of North America South America Africa Rest of Asia Australasia Subsidiaries Equity-accounted entities Total Developed Undeveloped 13 – 226 – 5 13 – 9 266 65 331 3 – 73 – 28 1 – 2 107 17 123 Total 16 – 299 – 33 14 – 11 373 81 454 excluding acquisitions and disposals was 109% (61% in 2015 and 63% in 2014) for subsidiaries and equity-accounted entities, 101% for subsidiaries alone and 121% for equity-accounted entities alone. There were material reductions (162mmboe) of reserves due to accelerations of the date of cessation of production in the US due to lower oil and gas prices, but these were largely offset by increases (157mmboe) in PSAs, principally in Azerbaijan, Indonesia and Iraq resulting from increased cost recovery volumes due to lower oil and gas prices. The 2016 RRR was impacted to a significant degree by the renewal of the ADCO concession in Abu Dhabi. Excluding the impact of the renewal, the total RRR would have been 70%. In 2016 net additions to the group’s proved reserves (excluding production and sales and purchases of reserves-in-place) amounted to 1336mmboe (742mmboe for subsidiaries and 594mmboe for equity-accounted entities), through revisions to previous estimates, improved recovery from, and extensions to, existing fields and discoveries of new fields. These additions include volumes associated with the renewal of the 9.5% interest in the ADCO onshore concession. The subsidiary additions through improved recovery from, and extensions to, existing fields and discoveries of new fields were in existing developments where they represented a mixture of proved developed and proved undeveloped reserves. Volumes added in 2016 principally resulted from the application of conventional technologies and increases in PSA entitlement as a result of lower prices. The principal proved reserves additions in our subsidiaries were in Indonesia, Iraq, UAE and the US. We had material reductions in our proved reserves in the US principally due to lower oil and gas prices. The principal reserves additions in our equity-accounted entities were in Argentina and Russia. 16% of our proved reserves are associated with PSAs. The countries in which we operated under PSAs in 2016 were Algeria, Angola, Azerbaijan, Egypt, India, Indonesia and Oman. In addition, the technical service contract (TSC) governing our investment in the Rumaila field in Iraq functions as a PSA. Our Abu Dhabi offshore concessions are due to expire in 2018, we have no proved reserves associated with these concessions beyond their expiry date. The group holds no other licences due to expire within the next three years that would have a significant impact on BP’s reserves or production. For further information on our reserves see page 194. A d d i t i o n a l d i s c l o s u r e s Estimated net proved reserves of liquids* Subsidiaries Equity-accounted entities Total Developed Undeveloped 2,753 3,637 6,390 1,398 2,545 3,943 million barrels Total 4,151e f 6,183g 10,333 Estimated net proved reserves of natural gas at 31 December 2016a b UK Rest of Europe US Rest of North America South America Africa Rest of Asia Australasia Subsidiaries Equity-accounted entities Total billion cubic feet Developed Undeveloped 499 – 5,447 – 1,784 767 1,890 3,012 13,398 7,617 21,015 350 – 2,567 – 4,970 2,191 3,769 1,643 15,490 6,863 22,353 Total 848 – 8,014 – 6,755 2,958 5,659 4,654 28,888h 14,480i 43,368 Estimated net proved reserves on an oil equivalent basis Subsidiaries Equity-accounted entities Total million barrels of oil equivalent Developed Undeveloped 5,063 4,951 10,014 4,068 3,729 7,797 Total 9,131 8,679 17,810 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently, and include non-controlling interests in consolidated operations. We disclose our share of reserves held in joint ventures and associates that are accounted for by the equity method although we do not control these entities or the assets held by such entities. b The 2016 marker prices used were Brent* $42.82/bbl (2015 $54.17/bbl and 2014 $101.27/bbl) and Henry Hub* $2.46 /mmBtu (2015 $2.59/mmBtu and 2014 $4.31/mmBtu). c Includes condensate. d All of the reserves in Canada are bitumen. e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 9 million barrels on which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. f Includes 16 million barrels of liquids in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. g Includes 347 million barrels of liquids in respect of the non-controlling interest in Rosneft held assets in Russia including 28 million barrels held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha. h Includes 2,026 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. i Includes 300 billion cubic feet of natural gas in respect of the non-controlling interest in Rosneft held assets in Russia including 3 billion cubic feet held through BP’s equity- accounted interest in Taas-Yuryakh Neftegazodobycha. Because of rounding, some totals may not agree exactly with the sum of their component parts. Proved reserves replacement Total hydrocarbon proved reserves at 31 December 2016, on an oil equivalent basis including equity-accounted entities, increased by 4% (decrease of 1% for subsidiaries and increase of 9% for equity- accounted entities) compared with 31 December 2015. Natural gas represented about 42% (55% for subsidiaries and 29% for equity- accounted entities) of these reserves. The change includes a net increase from acquisitions and disposals of 520mmboe (decrease of 128mmboe within our subsidiaries and increase of 648mmboe within our equity-accounted entities). Acquisition activity in our subsidiaries occurred in Abu Dhabi (increase of interest in the ADCO onshore concession from 9.5% to 10%), Indonesia, the US and the UK, and divestment activity in our subsidiaries in Norway, Indonesia, Australia, Trinidad and the US. In our equity-accounted entities the most significant items were purchases in Russia, Norway and Venezuela. The proved reserves replacement ratio* (RRR) is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery, and extensions and discoveries. For 2016, the proved reserves replacement ratio BP Annual Report and Form 20-F 2016 253 BP’s net production by country – crude oila and natural gas liquids 2016 2015 Crude oil 2014 2016 2015 Natural gas liquids 2014 thousand barrels per day BP net share of productionb Subsidiaries UKc d Norwayc Total Rest of Europe Total Europe Alaskac Lower 48 onshorec Gulf of Mexico deepwater Total US Canadae Total Rest of North America Total North America Trinidad & Tobagoc Total South America Angola Egyptc Algeria Total Africa Azerbaijanc Western Indonesiac Iraqf India Total Rest of Asia Total Asia Australiac Eastern Indonesiac Total Australasia Total subsidiaries Equity-accounted entities (BP share) Rosneft (Russia, Canada, Venezuela, Vietnam) Abu Dhabig Argentina Bolivia Egypt Norwayc Russiac Other 79 24 24 102 107 12 216 335 13 13 347 10 10 219 39 5 263 105 2 96 1 204 204 15 2 16 943 836 101 62 4 – 7 4 1 72 38 38 110 107 14 203 323 3 3 327 12 12 221 42 6 270 111 2 85 1 199 199 15 2 17 933 809 96 65 4 – – – 1 46 41 41 87 127 14 206 347 – – 347 13 13 181 37 5 222 98 2 46 2 147 147 17 2 19 834 816 97 62 3 – – – 1 Total equity-accounted entities Total subsidiaries and equity-accounted entitiesh 1,015 1,958 974 1,908 979 1,813 6 4 4 10 – 36 20 56 – – 56 8 8 – – 5 5 – – – – – – 3 – 3 7 5 5 11 – 37 19 56 – – 56 11 11 – – 7 7 – – – – 1 1 3 – 3 2 5 5 7 – 45 18 63 – – 63 12 12 – – 5 5 – – – – – – 3 – 3 82 88 91 4 – 1 – 3 – – 1 8 90 4 – 3 – 3 – – – 10 99 5 – 3 – 4 – – – 12 104 a Includes condensate. b Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. c In 2016, BP increased its interests in Tangguh in Indonesia and the Culzean asset in the UK North Sea, and in certain US onshore assets. It disposed of its interests in the Valhall, Skarv and Ula assets in the Norwegian North Sea and in return received an interest in Aker BP ASA, which operates in Norway. It also disposed of its interests in the Jansz-Io asset in Australia, and the Sanga Sanga conventional concession in Indonesia. It also decreased its interests in certain Trinidad and US onshore assets. In 2015, BP acquired an interest in Taas-Yuryakh Neftegazodobycha. It also increased its interest in the North Alexandria and West Mediterranean Deep Water Concessions of the West Nile Delta project in Egypt. It increased its interest in certain UK North Sea, Trinidad, and US onshore assets. It also decreased its interest in certain other assets in the same regions. In 2014, BP divested its interests in the Endicott and Northstar fields, and 50% of its interests in the Milne Point field, in Alaska and its interest in the US onshore Hugoton upstream operation. BP also reduced its interest in certain wells in the US onshore Eagle Ford Shale in south Texas. It increased its interest in the Shah Deniz asset in Azerbaijan, in certain UK North Sea assets, and in certain US onshore assets. d Volumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields, which are operated by Shell. e All of the production from Canada in Subsidiaries is bitumen. f Production volume recognition methodology for our Technical Service Contract arrangement in Iraq has been simplified to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to comparative periods. There is no impact on the financial results. g BP holds interests, through associates, in offshore concessions in Abu Dhabi which expire in 2018. h Includes 3 net mboe/d of NGLs from processing plants in which BP has an interest (2015 4mboe/d and 2014 7mboe/d). Because of rounding, some totals may not agree exactly with the sum of their component parts. 254 BP Annual Report and Form 20-F 2016 BP’s net production by country – natural gas Subsidiaries UKb Norwayb Total Rest of Europe Total Europe Lower 48 onshoreb Gulf of Mexico deepwater Alaska Total US Canada Total Rest of North America Total North America Trinidad & Tobagob Total South America Egyptb Algeria Total Africa Azerbaijanb Western Indonesiab India Total Rest of Asia Total Asia Australiab Eastern Indonesiab Total Australasia Total subsidiariesc Equity-accounted entities (BP share) Rosneft (Russia, Canada, Venezuela, Vietnam) Argentina Bolivia Norwayb Angola Western Indonesiab Total equity-accounted entitiesc Total subsidiaries and equity-accounted entities million cubic feet per day BP net share of productiona 2016 2015 2014 170 82 82 252 155 111 111 266 71 102 102 173 1,476 1,353 1,350 173 6 168 7 159 11 1,656 1,528 1,519 10 10 1,666 1,689 1,689 305 208 513 245 35 84 363 363 451 369 820 10 10 1,538 1,922 1,922 402 187 589 219 48 113 380 380 447 354 801 10 10 1,529 2,147 2,147 406 107 513 230 47 131 408 408 450 364 814 5,302 5,495 5,585 1,279 354 1,195 341 1,084 323 95 12 18 15 93 – – 21 80 – 7 21 1,773 7,075 1,651 7,146 1,515 7,100 a Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b In 2016, BP increased its interests in Tangguh in Indonesia and the Culzean asset in the UK North Sea, and in certain US onshore assets. It disposed of its interests in the Valhall, Skarv and Ula assets in the Norwegian North Sea and in return received an interest in Aker BP ASA, which operates in Norway. It also disposed of its interests in the Jansz-Io asset in Australia, and the Sanga Sanga concession in Indonesia. It also decreased its interests in certain Trinidad and US onshore assets. In 2015, BP acquired an interest in Taas-Yuryakh Neftegazodobycha. It also increased its interest in the North Alexandria and West Mediterranean Deep Water Concessions of the West Nile Delta project in Egypt. It increased its interest in certain UK North Sea, Trinidad, and US onshore assets. It also decreased its interest in certain other assets in the same regions. In 2014, BP divested its interest in the US onshore Hugoton upstream operation. BP also reduced its interest in certain wells in the US onshore Eagle Ford Shale in south Texas. It increased its interest in the Shah Deniz asset in Azerbaijan, in certain UK North Sea assets, and in certain US onshore assets. c Natural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group’s reserves. Because of rounding, some totals may not agree exactly with the sum of their component parts. BP Annual Report and Form 20-F 2016 255 A d d i t i o n a l d i s c l o s u r e s The following tables provide additional data and disclosures in relation to our oil and gas operations. Average sales price per unit of production (realizations*)a $ per unit of production Subsidiaries 2016 Crude oilc Natural gas liquids Gas 2015 Crude oilc d Natural gas liquids Gas 2014 Crude oilc d Natural gas liquids Gas Equity-accounted entitiese 2016 Crude oilc Natural gas liquids Gas 2015 Crude oilc Natural gas liquids Gas 2014 Crude oilc Natural gas liquids Gas Europe North America South America Africa Asia Australasia Rest of Europe UK Rest of North Americab US Russia Rest of Asia 42.80 25.70 4.50 52.42 30.66 7.83 96.02 58.11 8.13 – – – – – – – – – 40.16 20.16 4.19 50.68 28.20 6.49 97.77 52.97 8.22 50.71 – 5.16 – – – – – – 39.65 14.71 1.90 49.84 14.80 2.10 93.66 32.28 3.80 – – – – – – – – – 26.11 – – 26.71 – – – – – – – – – – – – – – 45.64 21.40 1.72 53.19 27.66 2.67 96.85 41.62 4.65 48.88 34.51 4.21 54.24 13.17 4.35 73.87 15.75 4.73 40.83 21.30 3.89 49.09 31.94 4.40 93.99 53.67 5.92 – – – – – – – – – 39.29 – 3.39 49.33 – 5.35 97.07 – 6.28 41.52 32.70 5.71 50.64 36.69 7.35 94.04 65.70 11.20 – – – – – – – – – 36.36 n/af 1.39 12.92 – 6.11 44.78 n/af 1.48 16.87 – 7.56 84.19 n/af 2.18 14.70 – 12.83 – – – – – – – – – Total group average 39.99 17.31 2.84 49.72 20.75 3.80 94.74 36.15 5.70 34.04 34.51 2.20 41.49 13.17 2.35 72.53 15.75 3.01 Average production cost per unit of productiong $ per unit of production Europe North America South America Africa Asia Australasia Rest of Europe UK US Rest of North America Russia Rest of Asia 14.80 22.95 44.67 – – – 13.72 13.80 18.85 10.41 – – 10.20 11.84 14.22 21.79 43.56 – 4.21 5.44 5.43 9.34 11.02 13.37 – – – 7.08 11.22 16.24 – – – – – – 10.66 12.10 11.28 – – – 2.46 2.60 3.82 3.67 4.59 4.34 2.62 2.88 3.92 – – – Total group average 8.46 10.46 12.75 3.57 3.93 4.75 Subsidiaries 2016 2015d 2014d Equity-accounted entities 2016 2015 2014 a Units of production are barrels for liquids and thousands of cubic feet for gas. Realizations include transfers between businesses, except in the case of Russia. b All of the production from Canada in Subsidiaries is bitumen. c Includes condensate. d Production volume recognition methodology for our Technical Service Contract arrangement in Iraq has been simplified to exclude the impact of oil price movements on lifting imbalances. A minor adjustment has been made to comparative periods. There is no impact on the financial results. e In certain countries it is common for equity-accounted entities’ agreements to include pricing clauses that require selling a significant portion of the entitled production to local governments or markets at discounted prices. f Crude oil includes natural gas liquids. g Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes. 256 BP Annual Report and Form 20-F 2016 Environmental expenditure Environmental expenditure relating to the Gulf of Mexico oil spill Operating expenditure Capital expenditure Clean-ups Additions to environmental remediation provision Increase (decrease) in decommissioning 2016 2015 – 487 564 27 5,452 521 733 34 262 305 $ million 2014 190 624 590 33 371 provision (804) 972 2,216 Environmental expenditure relating to the Gulf of Mexico oil spill For full details of all environmental activities in relation to the Gulf of Mexico oil spill, see Financial statements – Note 2. Other environmental expenditure Operating and capital expenditure on the prevention, control, treatment or elimination of air and water emissions and solid waste is often not incurred as a separately identifiable transaction. Instead, it forms part of a larger transaction that includes, for example, normal operations and maintenance expenditure. The figures for environmental operating and capital expenditure in the table are therefore estimates, based on the definitions and guidelines of the American Petroleum Institute. Environmental operating expenditure of $487 million in 2016 (2015 $521 million) showed an overall decrease of 7% which was due to price deflations and reduced environmental expenditure following the divestment of our petrochemicals site in Decatur, partially offset by a higher level of activity at Whiting refinery. Environmental capital expenditure in 2016 was lower overall than in 2015, largely due to lower spend as a result of the completion of the installation of a dissolved nitrogen floatation unit at Whiting refinery’s wastewater treatment plant in the previous year. 2015 also included higher spend relating to the upgrade to our latest generation PTA technology at some of our petrochemicals sites. These reductions were partially offset by an increased spend on a new LPG refrigeration plant for the North Sea forties pipeline system. Clean-up costs decreased to $27 million in 2016 compared with $34 million in 2015, primarily due to decreased contractual rates, currency devaluation in certain regions and overall cost reductions. In addition to operating and capital expenditure, we also establish provisions for future environmental remediation work. Expenditure against such provisions normally occurs in subsequent periods and is not included in environmental operating expenditure reported for such periods. Provisions for environmental remediation are made when a clean up is probable and the amount of the obligation can be reliably estimated. Generally, this coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The extent and cost of future environmental restoration, remediation and abatement programmes are inherently difficult to estimate. They often depend on the extent of contamination, and the associated impact and timing of the corrective actions required, technological feasibility and BP’s share of liability. Though the costs of future programmes could be significant and may be material to the results of operations in the period in which they are recognized, it is not expected that such costs will be material to the group’s overall results of operations or financial position. Additions to our environmental remediation provision was similar to prior years and also reflects scope reassessments of the remediation plans of a number of our sites in the US and Canada. The charge for environmental remediation provisions in 2016 included $7 million in respect of provisions for new sites (2015 $6 million and 2014 $13 million). In addition, we make provisions on installation of our oil and gas producing assets and related pipelines to meet the cost of eventual decommissioning. On installation of an oil or natural gas production facility, a provision is established that represents the discounted value of the expected future cost of decommissioning the asset. In 2016 the net decrease in the decommissioning provision occurred as a result of detailed reviews of expected future costs, partially offset by increases to the asset base. The increases in 2015 and 2014 were driven by detailed reviews of expected future costs and increases to the asset base. We undertake periodic reviews of existing provisions. These reviews take account of revised cost assumptions, changes in decommissioning requirements and any technological developments. Provisions for environmental remediation and decommissioning are usually established on a discounted basis, as required by IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’. Further details of decommissioning and environmental provisions appear in Financial statements – Note 22. Regulation of the group’s business BP’s activities, including its oil and gas exploration and production, pipelines and transportation, refining and marketing, petrochemicals production, trading, biofuels, wind and shipping activities, are conducted in more than 70 countries and are subject to a broad range of EU, US, international, regional and local legislation and regulations, including legislation that implements international conventions and protocols. These cover virtually all aspects of BP’s activities and include matters such as licence acquisition, production rates, royalties, environmental, health and safety protection, fuel specifications and transportation, trading, pricing, anti-trust, export, taxes and foreign exchange. Upstream contractual and regulatory framework The terms and conditions of the leases, licences and contracts under which our oil and gas interests are held vary from country to country. These leases, licences and contracts are generally granted by or entered into with a government entity or state-owned or controlled company and are sometimes entered into with private property owners. Arrangements with governmental or state entities usually take the form of licences or production-sharing agreements* (PSAs), although arrangements with the US government can be by lease. Arrangements with private property owners are usually in the form of leases. Licences (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a licence, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the licence holder is entitled to all production, minus any royalties that are payable in kind. A licence holder is generally required to pay production taxes or royalties, which may be in cash or in kind. Less typically, BP may explore for and exploit hydrocarbons* under a service agreement with the host entity in exchange for reimbursement of costs and/or a fee paid in cash rather than production. PSAs entered into with a government entity or state-owned or controlled company generally require BP (alone or with other contracting companies) to provide all the financing and bear the risk of exploration and production activities in exchange for a share of the production remaining after royalties, if any. In certain countries, separate licences are required for exploration and production activities, and in some cases production licences are limited to only a portion of the area covered by the original exploration licence. Both exploration and production licences are generally for a specified period of time. In the US, leases from the US government typically remain in effect for a specified term, but may be extended beyond that term as long as there is production in * See Glossary. BP Annual Report and Form 20-F 2016 257 A d d i t i o n a l d i s c l o s u r e s paying quantities. The term of BP’s licences and the extent to which these licences may be renewed vary from country to country. BP frequently conducts its exploration and production activities in joint arrangements* or co-ownership arrangements with other international oil companies, state-owned or controlled companies and/or private companies. These joint arrangements may be incorporated or unincorporated arrangements, while the co-ownerships are typically unincorporated. Whether incorporated or unincorporated, relevant agreements set out each party’s level of participation or ownership interest in the joint arrangement or co-ownership. Conventionally, all costs, benefits, rights, obligations, liabilities and risks incurred in carrying out joint arrangement or co-ownership operations under a lease or licence are shared among the joint arrangement or co-owning parties according to these agreed ownership interests. Ownership of joint arrangement or co-owned property and hydrocarbons to which the joint arrangement or co-ownership is entitled is also shared in these proportions. To the extent that any liabilities arise, whether to governments or third parties, or as between the joint arrangement parties or co-owners themselves, each joint arrangement party or co-owner will generally be liable to meet these in proportion to its ownership interest. In many upstream operations, a party (known as the operator) will be appointed (pursuant to a joint operating agreement) to carry out day-to-day operations on behalf of the joint arrangement or co-ownership. The operator is typically one of the joint arrangement parties or a co-owner and will carry out its duties either through its own staff, or by contracting out various elements to third-party contractors or service providers. BP acts as operator on behalf of joint arrangements and co-ownerships in a number of countries where it has exploration and production activities. Frequently, work (including drilling and related activities) will be contracted out to third-party service providers who have the relevant expertise and equipment not available within the joint arrangement or the co-owning operator’s organization. The relevant contract will specify the work to be done and the remuneration to be paid and will typically set out how major risks will be allocated between the joint arrangement or co-ownership and the service provider. Generally, the joint arrangement or co-owner and the contractor would respectively allocate responsibility for and provide reciprocal indemnities to each other for harm caused to and by their respective staff and property. Depending on the service to be provided, an oil and gas industry service contract may also contain provisions allocating risks and liabilities associated with pollution and environmental damage, damage to a well or hydrocarbon reservoirs and for claims from third parties or other losses. The allocation of those risks vary among contracts and are determined through negotiation between the parties. In general, BP incurs income tax on income generated from production activities (whether under a licence or PSA). In addition, depending on the area, BP’s production activities may be subject to a range of other taxes, levies and assessments, including special petroleum taxes and revenue taxes. The taxes imposed on oil and gas production profits and activities may be substantially higher than those imposed on other activities, for example in Abu Dhabi, Angola, Egypt, Norway, the UK, the US, Russia and Trinidad & Tobago. Greenhouse gas regulation Agreement commits all parties to submit Nationally Determined Contributions (NDCs) (i.e. pledges or plans of climate action) and pursue domestic measures aimed at achieving the objectives of their NDCs. Developed country NDCs should include absolute emission reduction targets, and developing countries are encouraged to move over time towards them. The Paris Agreement places binding commitments on countries to report on their emissions and progress made on their NDCs and to undergo international review of collective progress. It also requires countries to submit revised NDCs every five years, which are expected to be more ambitious with each revision. Global assessments of progress will occur every five years, starting in 2023. In the decision adopting the Paris Agreement, an earlier commitment by developed countries to mobilize $100 billion a year by 2020 was extended through 2025, with a further goal with a floor of $100 billion to be set before 2025. The United Nations climate change conference in Marrakech (COP22), held in November 2016, agreed a deadline of 2018 for countries to agree on the guidelines and rules that are needed to support implementation of the Paris Agreement. More stringent national and regional measures can be expected in the future. These measures could increase BP’s production costs for certain products, increase demand for competing energy alternatives or products with lower-carbon intensity, and affect the sales and specifications of many of BP’s products. Current and announced measures and developments potentially affecting BP’s businesses include the following: United States In the US, the Obama administration adopted its Climate Action Plan in 2013 and had been using existing statutory authority to implement that plan, including the Clean Air Act (CAA) and the Mineral Leasing Act (MLA). On 28 March 2017 the Trump administration issued an Executive Order (EO) rescinding major elements of the Climate Action Plan, and instructing the Environmental Protection Agency (EPA) to review and then commence the process of suspending, revising or rescinding certain regulations, including the Clean Power Plan and the EPA new source methane rule. The EO also instructs the Department of Interior to review and possibly suspend, revise or rescind the Bureau of Land Management (BLM) methane rule. • GHG emissions are currently regulated in a number of ways under the CAA, though some of these regulations may be suspended, revised or rescinded as noted above. – Stricter GHG regulations, stricter limits on sulphur in fuels, recent emissions regulations in the refinery sector and a revised lower ambient air quality standard for ozone, finalized by the EPA in October 2015, will affect our US operations in the future. – EPA regulations aimed at methane emissions are in place for new and modified sources and the BLM has issued methane regulations for existing sites located on federal lands. It is possible that EPA will be required by statute to propose regulations on existing sources of methane from onshore oil and natural gas sector activities, unless the EPA new source methane rule is rescinded. – – States may also have separate, stricter air emission laws in addition to the CAA and in some cases are considering joining carbon trading markets (e.g. California). In December 2015, nearly 200 nations at the United Nations climate change conference in Paris (COP21) agreed the Paris Agreement, for implementation post-2020. The agreement came into force on 4 November 2016. For the first time this agreement applies to all countries, both developing and developed, although in some instances allowances or flexibilities are provided for developing nations. The Paris Agreement aims to hold global average temperature rise to well below 2°C above pre-industrial levels and to pursue efforts to limit temperature rise to 1.5°C above pre-industrial levels. There is no quantitative long-term emissions goal. However, countries aim to reach global peaking of greenhouse gas (GHG) emissions as soon as possible and to undertake rapid reductions thereafter, so as to achieve a balance between human caused emissions by sources and removals by sinks of GHGs in the second half of this century. The Paris • The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 impose a renewable fuel mandate (the federal Renewable Fuel Standard) as well as state initiatives that impose low GHG emissions thresholds for transportation fuels (currently adopted in California, through the California Low Carbon Fuel Standard and Oregon). • EPA regulations impose light, medium and heavy duty vehicle emissions standards for GHGs and permitting requirements for certain large GHG stationary emission sources. The EPA and the National Highway Traffic Safety Administration are considering a proposed rulemaking to extend and tighten GHG emission and fuel efficiency standards until 2027. This will have an impact on BP’s product mix and overall demand. The Trump administration has announced that it will reconsider these standards. 258 BP Annual Report and Form 20-F 2016 • Under the GHG mandatory reporting rule (GHGMRR), annual reports on GHG emissions must be filed. In addition to direct emissions from affected facilities, producers and importers/ exporters of petroleum products, certain natural gas liquids and GHG products are required to report product volumes and notional GHG emissions as if these products were fully combusted. • In October 2015 the EPA published its final Clean Power Plan (CPP) which was an important element of the Obama administration’s Climate Action Plan. Legal challenges have been filed and the US Supreme Court has stayed the rule until the litigation is resolved, which is not expected until later in 2017 or 2018. The US Appellate Court heard arguments on the case in September 2016 and it is anticipated that its decision will be the subject of a request for review by the US Supreme Court. These rules are important due to potential impacts on electricity prices, reliability of electricity supply, precedents for similar rules targeting other sectors and potential impacts on combined heat and power installations. As noted above, the Trump administration has instructed the EPA to review certain regulations including the CPP and may decline to defend certain legal challenges to the CPP in court. • In January 2015 the Obama administration announced plans to reduce methane emissions from the oil and gas sector by 40-45% from 2012 levels by 2025. In June 2016 the EPA finalized rules aimed at limiting methane emissions from new and modified sources in the oil and natural gas sector in the US. The EPA has announced its intent to adopt a regulation that would apply to existing sources in the sector. In January 2017 the BLM’s methane rule, aimed at limiting methane emissions on federal lands from new, modified and existing sources in the oil and gas sector, came into effect. These EPA and BLM rules will require further actions by our US upstream businesses to manage methane emissions. As above, the Trump administration’s March 2017 EO instructs the Department of Interior to review and possibly suspend, revise or rescind the BLM and EPA methane rules. • A number of additional state and regional initiatives in the US will affect our operations. The California cap and trade programme started in January 2012 and expanded to cover emissions from transportation fuels in 2015. The state of Washington recently adopted a carbon cap rule that is planned to begin in 2017. European Union • The EU has agreed to an overall GHG reduction target of 20% by 2020. To meet this, a ‘Climate and Energy Package’ of regulatory measures was adopted that includes: a collective national reduction target for emissions not covered by the EU Emissions Trading System (EU ETS) Directive; binding national renewable energy targets to double usage of renewable energy sources in the EU, including at least a 10% share of renewable energy in the transport sector under the Renewable Energy Directive (a revision to which was proposed by the European Commission in November 2016); a legal framework to promote carbon capture and storage (CCS); and a revised EU ETS Phase 3. EU ETS revisions included a GHG reduction of 21% from 2005 levels; a significant increase in allowance auctioning; an expansion in the scope of the EU ETS to encompass more industrial sectors (including the petrochemicals sector) and gases; no free allocation for electricity generation (including that which is self- generated off-shore) or production, but sector benchmarked free allocation for all other installations, with sharply declining allocation for sectors deemed not exposed to carbon leakage. EU ETS revisions also included the adoption of a Market Stability Reserve to adjust the supply of auctioned allowances. This will take effect in 2019 and could potentially lead to higher carbon costs. EU Energy efficiency policy is currently implemented via national energy efficiency action plans and the Energy Efficiency Directive adopted in 2012. • The EU Fuel Quality Directive affects our production and marketing of transport fuels. Revisions adopted in 2009 mandate reductions in the life cycle GHG emissions per unit of energy and tighter environmental fuel quality standards for petrol and diesel. • In October 2014 the EU also agreed to the 2030 Climate and Energy Policy framework with a goal of at least a 40% reduction in GHGs from 1990 and measures to achieve a 27% share of renewable energy and a 27% increase in energy efficiency. The GHG reduction target is to be achieved by a 43% reduction of emissions from sectors covered by the EU ETS, and a 30% GHG reduction by Member States for all other GHG emissions. While the European Commission has made legislative proposals, including proposed amended targets, specific EU legislation and agreements required to achieve these goals are still under discussion in the European Council and European Parliament. • European regulations also establish passenger car performance standards for CO2 tailpipe emissions (European Regulation (EC) No 443/2009). From 2020 onwards, the European passenger fleet emissions target is 95 grams of CO2 per kilometre. This target will be achieved by manufacturing fuel efficient vehicles and vehicles using alternative, low carbon fuels such as hydrogen and electricity. In addition, vehicle emission test cycles and vehicle type approval procedures are being updated to improve accuracy of emission and efficiency measurements. Consequently, product mix and overall levels of demand will be impacted. • European vehicle CO2 emission regulations also impact the fuel efficiency of vans. By 2020, the EU fleet of newly registered vans must meet a target of 147 grams of CO2 per kilometre, which is 19% below the 2012 fleet average. • In addition, the Energy Efficiency Directive (EED), Industrial Emissions Directive (IED) 2010, Medium Combustion Plants Directive (MCPD) 2015 and EU regulation on ozone depleting substances 2009 (ODS Regulation) referenced below under ‘Other environmental regulation’ will also directly or indirectly require reductions in GHG emissions. Other • Canada’s highest emitting province, Alberta, has regulations targeting large final emitters (sites with over 100,000 tonnes of carbon dioxide equivalent per annum) with intensity targets of 2% improvement per year up to 20%. Compliance is possible via direct reductions, the purchase of offsets or the payment of C$20/tonne to a technology fund which will escalate to C$30/tonne in 2017. In addition, a new policy direction was announced by the Alberta government including an economy-wide price of carbon that covers emissions not in the scope of the existing regulations for large final emitters (C$20/tonne in 2017; C$30/tonne in 2018 then escalating in real terms), targeted changes to electricity generation sources, a limit on overall oil sands emissions, and sector specific performance standards (currently being developed) to determine the volume of emissions subject to charges, or use of other compliance mechanisms, including offsets. The Canadian federal government has announced a number of climate change policy goals including a national carbon price starting at C$10/tonne and escalating to C$50/tonne by 2022 (or equivalent system for provinces with cap-and-trade systems), with implementation of the price, use of any funds generated and outcome reporting being managed by each province. • In the November 2014 US-China joint announcement on climate change addressing post-2020 actions, which was reaffirmed by the countries’ respective presidents in September 2015 and March 2016, the US committed to reducing its GHG emissions by 26-28% below its 2005 level by 2025. Achieving these reductions will require expanded efforts to reduce emissions, which are likely to include regulatory measures. China announced it intends to achieve a peak in CO2 emissions around 2030, with the intention to try to peak earlier and to increase the non-fossil fuel share of all energy to around 20% by 2030. Currently, China has targets to reduce carbon intensity of GDP 40-45% below 2005 levels by 2020 and increase the share of non-fossil fuels in total energy consumption from 7.5% in 2005 to 15% by 2020. In the March 2016 US-China joint presidential statement both countries agreed to ratify the Paris Agreement including submission of their domestic reduction commitments detailed above. • China is operating emission trading pilot programmes in five cities and two provinces. Two of BP’s joint venture* companies in China are participating in these schemes. A nationwide carbon emissions trading market is expected to be launched in 2017 which will supersede the above seven pilot programmes. It is also proposed to carry out pilot programmes on compensation for and trading of energy quotas in four provinces in 2017 which may be expanded to nationwide in or after 2020. • China has also adopted more stringent vehicle tailpipe emission standards and vehicle efficiency standards to address air pollution and GHG emissions. These standards will have an impact on transportation fuel product mix and overall demand. For information on the steps that BP is taking in relation to climate change issues and for details of BP’s GHG reporting, see Sustainability – Climate change on page 43. BP Annual Report and Form 20-F 2016 259 A d d i t i o n a l d i s c l o s u r e s Other environmental regulation Current and proposed fuel and product specifications, emission controls (including control of vehicle emissions), climate change programmes and regulation of unconventional oil and gas extraction under a number of environmental laws may have a significant effect on the production, sale and profitability of many of BP’s products. There are also environmental laws that require BP to remediate and restore areas affected by the release of hazardous substances or hydrocarbons associated with our operations or properties. These laws may apply to sites that BP currently owns or operates, sites that it previously owned or operated, or sites used for the disposal of its and other parties’ waste. See Financial Statements – Note 22 for information on provisions for environmental restoration and remediation. A number of pending or anticipated governmental proceedings against certain BP group companies under environmental laws could result in monetary or other sanctions. Group companies are also subject to environmental claims for personal injury and property damage alleging the release of, or exposure to, hazardous substances. The costs associated with future environmental remediation obligations, governmental proceedings and claims could be significant and may be material to the results of operations in the period in which they are recognized. We cannot accurately predict the effects of future developments, such as stricter environmental laws or enforcement policies, or future events at our facilities, on the group, and there can be no assurance that material liabilities and costs will not be incurred in the future. For a discussion of the group’s environmental expenditure, see page 257. A significant proportion of our fixed assets are located in the US and the EU. US and EU environmental, health and safety regulations significantly affect BP’s operations. Significant legislation and regulation in the US and the EU affecting our businesses and profitability includes the following: United States • Since taking office in January, the Trump administration has issued a number of EOs intended to reform the federal permitting and rulemaking processes to reduce regulatory burdens placed on manufacturing generally and the energy industry specifically. These EOs immediately rescind certain policies and procedures and order the commencement of a broad process to identify other actions that may be taken to further reduce these regulatory requirements. It is not clear how much or how quickly these regulatory requirements will be reduced given statutory and rulemaking constraints and the likely opposition to some of these initiatives. • The National Environmental Policy Act (NEPA) requires that the federal government gives proper consideration to the environment prior to undertaking any major federal action that significantly affects the environment, which includes the issuance of federal permits. The environmental reviews required by NEPA can delay projects. In August 2016, the White House Council on Environmental Quality issued guidance to federal agencies requiring that climate impact be considered under NEPA. These requirements could further delay projects that require federal action such as exploration and production plans. States law analogues to NEPA could also limit or delay our projects. • The CAA regulates air emissions, permitting, fuel specifications and other aspects of our production, distribution and marketing activities. • The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 affect our US fuel markets by, among other things, imposing the limitations discussed above under ‘Greenhouse gas regulation’. California also imposes Low Emission Vehicle (LEV) and Zero Emission Vehicle (ZEV) standards on vehicle manufacturers. These regulations will have an impact on fuel demand and product mix in California and those states adopting LEV and ZEV standards. • The Clean Water Act regulates wastewater and other effluent discharges from BP’s facilities, and BP is required to obtain discharge permits, install control equipment and implement operational controls and preventative measures. • The Resource Conservation and Recovery Act regulates the generation, storage, transportation and disposal of wastes associated with our operations and can require corrective action at locations where such wastes have been disposed of or released. • The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) can, in certain circumstances, impose the 260 BP Annual Report and Form 20-F 2016 entire cost of investigation and remediation on a party who owned or operated a site contaminated with a hazardous substance, or arranged for disposal of a hazardous substance at a site. BP has incurred, or is likely to incur, liability under CERCLA or similar state laws, including costs attributed to insolvent or unidentified parties. BP is also subject to claims for remediation costs under other federal and state laws, and to claims for natural resource damages under CERCLA, the Oil Pollution Act of 1990 (OPA 90) (discussed below) and other federal and state laws. CERCLA also requires notification of releases of hazardous substances to national, state and local government agencies, as applicable. In addition, the Emergency Planning and Community Right-to-Know Act requires notification of releases of designated quantities of certain listed hazardous substances to state and local government agencies, as applicable. • The Toxic Substances Control Act (TSCA) regulates BP’s manufacture, import, export, sale and use of chemical substances and products. In June 2016, the US enacted legislation to modernize and reform TSCA (the Frank R. Lautenberg Chemical Safety for the 21st Century Act). The EPA has begun to develop proposed rules, processes and guidance to implement the reforms. Key components of the reform legislation include: (1) a reset of the TSCA chemical inventory, (2) new chemical management prioritization efforts expanding risk assessment and risk management practices, (3) new confidentiality provisions, and (4) new authority for the EPA to impose a fee structure. • The Occupational Safety and Health Act imposes workplace safety and health requirements on BP operations along with significant process safety management obligations, requiring continuous evaluation and improvement of operational practices to enhance safety and reduce workplace emissions at gas processing, refining and other regulated facilities. In 2016 the Obama administration announced that the US Occupational Safety and Health Administration (OSHA) would implement a ‘National Emphasis Program’ set of inspections aimed at refineries and petrochemical facilities. The Trump administration has not made any announcement regarding its intentions for this program. • The US Department of Transportation (DOT) regulates the transport of BP’s petroleum products such as crude oil, gasoline, petrochemicals and other hydrocarbon liquids. • The Maritime Transportation Security Act and the DOT Hazardous Materials (HAZMAT) regulations impose security compliance regulations on certain BP facilities. • OPA 90 is implemented through regulations issued by the EPA, the US Coast Guard, the DOT, OSHA, the Bureau of Safety and Environmental Enforcement and various states. Alaska and the West Coast states currently have the most demanding state requirements. • The Outer Continental Shelf Land Act, the MLA and other statutes give the Department of Interior (DOI) and the BLM authority to regulate operations and air emissions on offshore and onshore operations on federal lands subject to DOI authority. New stricter regulations on operational practices, equipment and testing have been imposed on our operations in the Gulf of Mexico and elsewhere following the Deepwater Horizon oil spill. In addition, in 2016 the DOI proposed to regulate methane emissions from onshore oil and natural gas sector operations. • The Endangered Species Act and Marine Mammal Protection Act protect certain species from adverse human impacts. The species and their habitat may be protected thereby restricting operations or development at certain times and in certain places. With an increasing number of species being protected, we have increasing restrictions on our activities. European Union • The EED was adopted in 2012. It requires EU member states to implement an indicative 2020 energy saving target and apply a framework of measures as part of a national energy efficiency programme, including mandatory industrial energy efficiency surveys. This directive has been implemented in the UK by the Energy Savings Opportunity Scheme Regulations 2014, which affects our offshore and onshore assets. The ISO50001 standard is being implemented by organizations in some EU states to meet some elements of the Energy Efficiency Directive. A revision to the EED was proposed by the European Commission in November 2016, which includes a new energy efficiency target for 2030. • The IED provides the framework for granting permits for major industrial sites. It lays down rules on integrated prevention and control of air, water and soil pollution arising from industrial activities. As part of the IED framework, additional emission limit values are informed by the sector specific and cross-sector Best Available Technology (BAT) Conclusions, such as the BAT Conclusions for the refining sector, for combustion as well as petrochemicals production. These may result in requirements for BP to further reduce its emissions, particularly its air and water emissions. • The MCPD came into force on 18 December 2015 and must be implemented by member states by 19 December 2017. It applies to air emissions of sulphur dioxide (SO2), nitrogen oxides (NOx) and particulates from the combustion of fuels in plants with a rated thermal input between one and 50MW. It also includes requirements to monitor emissions of carbon monoxide (CO) from such plant. Its requirements will be phased in – the emission limit values set in the Directive will apply from 20 December 2018 for new plants and by 2025 or 2030 for existing plants, depending on their size. • The National Emission Ceiling Directive 2001 has been revised to introduce stricter emissions limits from 2030, with new indicative national targets applying from 2025. Formal adoption of the revised Directive is pending. • The ODS Regulation requires BP to reduce the use of ozone depleting substances (ODSs) and phase out use of certain ODSs. BP continues to replace ODSs in refrigerants and/or equipment in the EU and elsewhere, in accordance with the Montreal Protocol and related legislation. In addition, the EU regulation on fluorinated GHGs with high global warming potential (the F-gas Regulations) came into force on 1 January 2015. The F-gas Regulations require a phase-out of certain hydrofluorocarbons, based on global warming potential. • The EU Registration, Evaluation Authorization and Restriction of Chemicals (REACH) Regulation requires registration of chemical substances manufactured in or imported into the EU, together with the submission of relevant hazard and risk data. REACH affects our manufacturing or trading/import operations in the EU. Since coming into force in 2007, REACH implementation has followed a phase-in schedule defined by the EU. The final phase-in implementation deadline requires registration of substances manufactured or imported in the tonnage-band of 1-100 tonnes per annum per legal entity by 31 May 2018. BP is in the process of preparing and submitting registration dossiers to meet this final REACH implementation milestone. For higher tonnage-band substances, BP maintains compliance by checking whether imports are covered by the registrations of non-EU suppliers’ representatives, preparing and submitting registration dossiers to cover new manufactured and imported substances, and updating previously submitted registrations as required. Some substances registered previously, including substances supplied to us by third parties for our use, are now subject to evaluation and review for potential authorization or restriction procedures, and possible banning, by the European Chemicals Agency and EU member state authorities. • The EU Offshore Safety Directive was adopted in 2013. Its purpose is to introduce a harmonized regime aimed at reducing the potential environmental, health and safety impacts of the offshore oil and gas industry throughout EU waters. The Directive has been implemented in the UK primarily through the Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations 2015. • The Water Framework Directive (WFD) published in 2000 aims to protect the quantity and quality of ground and surface waters of the EU member states. The ongoing implementation of the WFD and the related Environmental Quality Standards Directive 2008 as well as the planned revision of the WFD in 2019 is likely to require additional compliance efforts and increased costs for managing freshwater withdrawals and discharges from BP’s EU operations. Regulations governing the discharge of treated water have also been developed in countries outside of the US and EU. This includes regulations in Trinidad and Angola. In Trinidad, BP has been working with the regulators to apply water discharge rules arising from the Certificate of Environmental Clearance (CEC) Regulations 2001 and associated Water Pollution Rules 2007. In Angola, BP has been upgrading produced water treatment systems to meet revised oil in water limits for produced water discharge under Executive Decree ED 97-14 (superseded ED 12/05 on 1 January 2016). Environmental maritime regulations BP’s shipping operations are subject to extensive national and international regulations governing liability, operations, training, spill prevention and insurance. These include: • Liability and spill prevention and planning requirements governing, among others, tankers, barges and offshore facilities are imposed by OPA in US waters. It also mandates a levy on imported and domestically produced oil to fund oil spill responses. Some states, including Alaska, Washington, Oregon and California, impose additional liability for oil spills. Outside US territorial waters, BP Shipping tankers are subject to international liability, spill response and preparedness regulations under the UN’s International Maritime Organization (IMO), including the International Convention on Civil Liability for Oil Pollution Damage, the International Convention for the Prevention of Pollution from Ships (MARPOL), the International Convention on Oil Pollution, Preparedness, Response and Co-operation and the International Convention on Civil Liability for Bunker Oil Pollution Damage. In April 2010, the Hazardous and Noxious Substance (HNS) Protocol 2010 was adopted to address issues that have inhibited ratification of the International Convention on Liability and Compensation for Damage in Connection with the Carriage of Hazardous and Noxious Substances by Sea 1996. As at 31 December 2016, as the required minimum number of contracting states had not been achieved, the HNS Convention had not entered into force. • A global sulphur cap of 0.5% will apply to marine fuel from January 2020 under MARPOL. In order to comply, ships will either need to consume low sulphur marine fuels or implement approved abatement technology to enable them to meet the low sulphur emissions requirements whilst continuing to use higher sulphur fuel. This new global cap will not alter the lower limits that apply in the sulphur oxides Emissions Control Areas established by the IMO. • Ships will be required to have ballast water treatment systems in place within the time frame prescribed by the International Convention for the Control and Management of Ships’ Ballast Water and Sediments 2004, which is due to enter into force in September 2017. To meet its financial responsibility requirements, BP Shipping maintains marine pollution liability insurance in respect of its operated ships to a maximum limit of $1 billion for each occurrence through mutual insurance associations (P&I Clubs), although there can be no assurance that a spill will necessarily be adequately covered by insurance or that liabilities will not exceed insurance recoveries. Legal proceedings Proceedings relating to the Deepwater Horizon oil spill Introduction BP Exploration & Production Inc. (BPXP) was lease operator of Mississippi Canyon, Block 252 in the Gulf of Mexico (Macondo), where the semi-submersible rig Deepwater Horizon was deployed at the time of the 20 April 2010 explosions and fire and resulting oil spill (the Incident). Lawsuits and claims arising from the Incident have generally been brought in US federal and state courts. Many of the lawsuits in federal court relating to the Incident were consolidated by the Federal Judicial Panel on Multidistrict Litigation into two multi-district litigation proceedings, one in federal district court in Houston for the securities, derivative and Employee Retirement Income Security Act (ERISA) cases (MDL 2185) and another in federal district court in New Orleans for the remaining cases (MDL 2179). A Plaintiffs’ Steering Committee (PSC) was established to act on behalf of individual and business plaintiffs in MDL 2179. These proceedings, and other material lawsuits and claims arising from the Incident, are discussed below. BP Annual Report and Form 20-F 2016 261 A d d i t i o n a l d i s c l o s u r e s Federal and state claims MDL 2179 – Department of Justice (DoJ) Action, State and local authority claims consolidated into MDL 2179 and Trial of Liability, Limitation, Exoneration and Fault Allocation The US filed a civil complaint in MDL 2179 against BPXP and others on 15 December 2010 (the DoJ Action). The complaint sought an order finding liability under the Oil Pollution Act of 1990 (OPA 90) for natural resources damages and civil penalties under the Clean Water Act (CWA). Between 2010 and 2013, the states of Alabama, Florida, Louisiana, Mississippi and Texas (the five Gulf Coast states) filed lawsuits seeking declaratory and injunctive relief, and punitive damages, as a result of the Incident. Each of these actions was consolidated with MDL 2179. A Trial of Liability, Limitation, Exoneration and Fault Allocation (the Trial) in MDL 2179 commenced on 25 February 2013. The district court issued its ruling on the first phase of the Trial in September 2014. BPXP, BP America Production Company (BPAPC) and various other parties were each found liable under general maritime law for the blowout, explosion and oil spill from the Macondo well. With respect to the United States’ claim against BPXP under the CWA, the district court found that the discharge of oil was the result of BPXP’s gross negligence and wilful misconduct and that BPXP was therefore subject to enhanced civil penalties. The district court issued its ruling on the second phase of the Trial in January 2015. It found that 3.19 million barrels of oil were discharged into the Gulf of Mexico and were therefore subject to a CWA penalty. In addition, the district court found that BP was not grossly negligent in its source control efforts. For further details of the Trial, see ‘Legal proceedings’ in BP Annual Report and Form 20-F 2014. BP appealed both rulings but following the settlement between the US and BPXP (discussed below), on 19 October 2016 BP and the PSC filed a joint stipulation to dismiss the appeals. Both appeals have now been dismissed but BP could appeal the rulings in the future if a claimant was successful in an action against BP that includes a final judgment that incorporates the district court’s rulings on these trial phases. The penalty phase of the Trial involved consideration of the amount of CWA civil penalties owed to the United States, and concluded in February 2015. No decision was entered by the district court with respect to BPXP following this phase of the trial in light of the subsequent settlement between the US and BPXP. Consent Decree and Settlement Agreement On 2 July 2015, BP announced that BPXP had executed agreements in principle with the United States federal government and the five Gulf Coast states to settle all federal and state claims arising from the Incident. In addition, BPXP also settled the claims made by more than 400 local government entities. On 5 October 2015, the United States lodged with the district court in MDL 2179 a proposed Consent Decree between the United States, the five Gulf Coast states and BP to fully and finally resolve any and all natural resource damages claims of the United States, the five Gulf Coast states and their respective natural resource trustees and all CWA penalty claims, and certain other claims of the United States and the five Gulf Coast states. Concurrently, BP entered into a definitive Settlement Agreement with the five Gulf Coast states (Settlement Agreement) with respect to state claims for economic, property and other losses. On 4 April 2016 (the Effective Date), the court entered the Consent Decree and also entered a final judgment in the DoJ Action on the terms set forth in the Consent Decree, at which time the Consent Decree and Settlement Agreement became effective. For further details of the Consent Decree and Settlement Agreement, including details of the principal payments, see ‘Legal proceedings’ in BP Annual Report and Form 20-F 2015. OPA Test Case Proceedings A number of lawsuits were brought, primarily by business claimants, under OPA 90 in relation to the 2010 federal deepwater drilling moratoria. Six test cases, consolidated with MDL 2179, were scheduled to address certain OPA 90 liability questions focusing on, 262 BP Annual Report and Form 20-F 2016 among other issues, whether the plaintiffs’ alleged losses tied to the moratoria and whether federal permit delays are compensable. On 10 March 2016, the court ruled that BPXP is not, as a ‘Responsible Party’ under OPA 90, liable for economic losses that resulted from the 2010 deepwater drilling moratoria. The court’s order dismissed the plaintiffs’ claims with prejudice. On 19 March 2016, the plaintiffs appealed the court’s ruling to the Fifth Circuit. Subsequently, BPXP settled the claims of each of the test case plaintiffs and their cases and the pending appeals to the Fifth Circuit have been dismissed. Agreement for early natural resource restoration On 21 April 2011, BP announced an agreement with natural resource trustees for the US and five Gulf Coast states, providing for up to $1 billion to be spent on early restoration projects to address natural resource injuries resulting from the Incident. BP completed the final payment for the $1 billion early restoration funds in April 2016. Under the Consent Decree, Trustees will continue to implement these early restoration projects as part of the final settlement of all US and state claims for natural resource damages. PSC settlements PSC settlements – Economic and Property Damages Settlement Agreement The Economic and Property Damages Settlement resolved certain economic and property damage claims, and included a $2.3 billion BP commitment to help resolve economic loss claims related to the Gulf seafood industry (the Seafood Compensation Program) and a $57-million fund to support advertising to promote Gulf Coast tourism. It also resolved property damage in certain areas along the Gulf Coast, as well as claims for additional payments under certain Master Vessel Charter Agreements entered into in the course of the Vessels of Opportunity Program implemented as part of the response to the Incident. The economic and property damages claims process is under court supervision through the settlement claims process established by the Economic and Property Damages Settlement. This provides that class members release and dismiss their claims against BP not expressly reserved by that agreement. The final deadline for filing all claims other than those that fall into the Seafood Compensation Program was 8 June 2015. Following numerous court decisions on 31 March 2015, the court denied the PSC’s motion seeking to alter or amend a revised policy, addressing the matching of revenue and expenses for business economic loss claims, which requires the matching of revenue with the expenses incurred by claimants to generate that revenue, even where the revenue and expenses were recorded at different times. On 23 April 2015, the PSC appealed this decision to the Fifth Circuit. On 18 December 2015, the PSC and BP entered into a joint stipulation to stay this appeal pending resolution of certain issues in the district court in New Orleans. On 8 January 2016, the Fifth Circuit granted the joint stipulation and stayed the appeal and in further orders extended the stay until 7 September 2016. That stay has now expired and the oral argument took place on 8 March 2017. For more information about BP’s current estimate of the total cost of the Economic and Property Damages Settlement, see Financial statements – Note 2. PSC settlements – Medical Benefits Class Action Settlement The Medical Benefits Class Action Settlement (Medical Settlement) involves payments to qualifying class members based on a matrix for certain Specified Physical Conditions (SPCs), as well as a 21-year Periodic Medical Consultation Program (PMCP) for qualifying class members, and also includes provisions regarding class members pursuing claims for later-manifested physical conditions (LMPCs). The deadline for submitting SPC and PMCP claims was 12 February 2015. The Medical Claims Administrator has reported the total number of claims submitted is approximately 37,250. As of 3 March 2017, approximately 22,300 SPC claims, totalling approximately $64.2 million, have been approved for compensation. In addition, approximately 26,200 claimants have been determined eligible for the PMCP and there are six pending lawsuits brought by class members claiming LMPCs. For further details of the Medical Settlement, see ‘Legal proceedings’ in BP Annual Report and Form 20-F 2015. MDL 2185 and other securities-related litigation Since the Incident, shareholders have sued BP and various of its current and former officers and directors asserting shareholder derivative claims and class and individual securities fraud claims. Many of these lawsuits have been consolidated or co-ordinated in federal district court in Houston (MDL 2185). Securities class action On 20 May 2014, the court denied plaintiffs’ motion to certify a proposed class of ADS purchasers before the Deepwater Horizon explosion (from 8 November 2007 to 20 April 2010) and granted plaintiffs’ motions to certify a class of post-explosion ADS purchasers from 26 April 2010 to 28 May 2010. The parties appealed the district court’s class certification decisions and on 8 September 2015, the Fifth Circuit affirmed both of the district court’s decisions. On 2 May 2016, the Supreme Court denied the pre-explosion ADS purchasers’ final petition. Following various legal proceedings, on 2 June 2016, BP announced that it had agreed with plaintiffs’ representatives to settle the class claims of the post-explosion ADS purchasers for the amount of $175 million, payable during 2017, subject to approval by the court. The parties filed the settlement agreement and other papers in support of approval with the court on 15 September 2016 and a class notice was issued on 14 November 2016. On 13 February 2017 the court granted final approval of the class settlement. Individual securities litigation From April 2012 to April 2016, 38 cases were filed in state and federal courts by pension funds, investment funds and advisers against BP entities and several current and former officers and directors seeking damages for alleged losses those funds suffered because of their purchases and/or holdings of BP ordinary shares and, in certain cases, ADSs. The funds assert claims under English law and, for plaintiffs purchasing ADSs, federal securities law, and seek damages for alleged losses that those funds suffered because of their purchases and holdings of BP ordinary shares and/or ADSs. All of the cases, with the exception of one case that has been stayed, have been transferred to MDL 2185. On 4 January 2016, the district court dismissed two of those cases and some of the claims of a third case. Plaintiffs in the two dismissed cases filed amended complaints on 19 January 2016. On 8 July 2016, the district court granted leave for these plaintiffs to file amended complaints. On 28 September 2016, defendants filed a motion to dismiss certain claims against certain defendants in 20 of the individual securities cases and briefing is expected to be completed on that motion in April 2017. Canadian class action On 15 November 2012, a plaintiff re-filed a statement of claim against BP in Ontario, Canada, seeking to assert claims under Canadian law against BP on behalf of a class of Canadian residents who allegedly suffered losses because of their purchase of BP ordinary shares and ADSs. On 14 August 2014, the Ontario Court of Appeal held that the claims made on behalf of Canadian residents who purchased BP ordinary shares and ADSs on exchanges outside of Canada should be litigated in those countries, and granted leave for the plaintiff to amend the complaint to assert claims only on behalf of Canadian residents who purchased ADSs on the Toronto Stock Exchange. Following an unsuccessful claim by the plaintiff in Texas federal court, on 26 February 2016, the plaintiff filed a motion in the Court of Appeal for Ontario to lift the stay on the Canadian action, which was granted on 29 July 2016. On 19 January 2017 the Supreme Court of Canada denied BP’s motion for leave to appeal from the Court of Appeal’s decision. ERISA On 15 January 2015, in an ERISA case related to BP share funds in several employee benefit savings plans, the federal district court in Houston allowed the plaintiffs to amend their complaint to allege some of their proposed claims against certain defendants. On 26 September 2016, the Fifth Circuit reversed the decision of the district court, holding that the amended complaint is insufficient to state a claim against defendants, that the district court erred in granting the plaintiffs’ motion to amend, and remanding the case to the district court for further proceedings. On 22 November 2016, plaintiffs filed a motion to file an amended complaint, and on 8 March 2017, that motion was denied. Other Deepwater Horizon oil spill related claims Other civil complaints – economic loss On 29 March 2016, the district court in MDL 2179 issued an order dismissing in its entirety the master complaint raising claims for economic loss by private plaintiffs (the March 2016 Order). The court ordered that all private plaintiffs who had filed a timely claim for economic loss against BP in MDL 2179 and had not released those claims must file and serve on BP a sworn statement disclosing information regarding their claims by 2 May 2016. In addition, the court required plaintiffs who had not filed an individual complaint (defined as a complaint not joined in by other plaintiffs) against BP to file a new individual complaint by 2 May 2016. Plaintiffs who failed to comply with the sworn statement requirement or the new individual complaint requirement by 2 May 2016 (which deadline was extended by 14 days for some of the plaintiffs) were to have their claims deemed dismissed with prejudice without further notice. The court issued a supplemental order confirming that all new complaints filed would be stayed until further direction by the court. On 7 June 2016, the court issued an order requiring private plaintiffs who had not complied with the March 2016 Order to show cause in writing by 28 June 2016 why their claims should not be dismissed with prejudice. The court also dismissed all joinders by plaintiffs in the master complaint for private plaintiff economic loss and property damages claims. On 14 July 2016 the federal district court issued an order listing those 962 plaintiffs who complied with the March 2016 Order and those plaintiffs whose compliance with the March 2016 Order remained to be determined by the court. The court dismissed with prejudice any remaining claims by private plaintiffs for economic loss and property damage. Accordingly the vast majority of economic loss and property damage claims from individuals and businesses that either opted out of the 2012 settlement with the Plaintiffs’ Steering Committee and/or were excluded from that settlement have either been resolved or dismissed. On 16 December 2016, the district court issued a ruling on the show cause submissions filed by plaintiffs whose compliance with the March 2016 Order remained to be determined by the court. The court’s ruling held another 61 plaintiffs to be noncompliant with the March 2016 Order and dismissed their claims. It found an additional 57 plaintiffs to have complied with the March 2016 Order and to be subject to further proceedings in MDL 2179. On 22 February 2017 the district court in MDL 2179 ordered that any remaining plaintiffs who wish to pursue a general maritime law claim must file and serve on BP a sworn statement as to their proprietary interest in property physically damaged by oil, and whether they worked as commercial fishermen, by 5 April 2017. Other civil complaints – personal injury On 22 February 2017 the district court in MDL 2179 issued an order dismissing in its entirety the master complaint raising claims for post- explosion clean-up, medical monitoring and personal injury claims occurring after the explosion and fire of 20 April 2010. The court ordered that all plaintiffs who had filed a timely claim for such personal injury cases against BP in MDL 2179 and had not released those claims must file and serve on BP a sworn statement disclosing information regarding their claims by 12 April 2017. In addition, the court required plaintiffs who had not filed an individual complaint (defined as a complaint not joined in by other plaintiffs) against BP to file a new individual complaint by 12 April 2017. Plaintiffs who failed to comply with the sworn statement requirement or the new individual complaint requirement by 12 April 2017 were to have their claims deemed dismissed with prejudice without further notice. Non-US government lawsuits On 5 April 2011, the Mexican State of Yucatan submitted a claim to the Gulf Coast Claims Facility (GCCF) alleging potential damage to its natural resources and environment, and seeking to recover the cost of assessing the alleged damage. This was followed by a suit against BP which was transferred to MDL 2179 where it remains pending. BP Annual Report and Form 20-F 2016 263 A d d i t i o n a l d i s c l o s u r e s On 19 April 2013, the Mexican federal government filed a civil action against BP and others in MDL 2179. The complaint seeks a determination that each defendant bears liability under OPA 90 for damages that include the costs of responding to the spill, natural resource damages allegedly recoverable by Mexico as an OPA 90 trustee and the net loss of taxes, royalties, fees or net profits. On 18 October 2012, before a Mexican Federal District Court located in Mexico City, a class action complaint was filed against BPXP, BPAPC and other BP subsidiaries. BPXP has since been dismissed. The plaintiffs, who allegedly are fishermen, are seeking, among other things, compensatory damages for the class members who allegedly suffered economic losses, as well as an order requiring BP to remediate environmental damage resulting from the Incident, to provide funding for the preservation of the environment and to conduct environmental impact studies in the Gulf of Mexico for the next 10 years. BP has not been formally served with the action. However, after learning that the Mexican Federal District Court issued a resolution in the class action that impacted BP’s rights, BP filed a constitutional challenge (amparo) in Mexico asserting that BP has never been formally served with process in the class action. This amparo was denied and is now on appeal. On 3 December 2015 and 29 March 2016, Acciones Colectivas de Sinaloa (ACS) filed two class actions (which have since been consolidated) in a Mexican Federal District Court on behalf of several Mexican states. In these class actions, plaintiffs seek an order requiring the BP defendants to repair the damage to the Gulf of Mexico, to pay penalties, and to compensate plaintiffs for damage to property, to health and for economic loss. BP has not been formally served with the action. False Claims Act actions On 17 December 2012, the court ordered one complaint to be unsealed that had been filed in the US District Court for the Eastern District of Louisiana by an individual under the Qui Tam (whistle blower) provisions of the False Claims Act (FCA). The complaint alleged that BP and another defendant had made false reports and certifications of the amount of oil released into the Gulf of Mexico following the Incident. On 17 December 2012, the DoJ filed with the court a notice that the DoJ elected to decline to intervene in the action. On 31 January 2013, the complaint was transferred to MDL 2179 and the court subsequently stayed the action. Following the Effective Date, under the terms of the Consent Decree, the United States and Gulf states covenanted not to pursue claims against BP under the FCA. On 3 February 2017 the plaintiff in the False Claims Act case voluntarily dismissed the action. US Department of Interior matters On 12 October 2011, the US Department of the Interior Bureau of Safety and Environmental Enforcement issued to BP, Transocean, and Halliburton notification of Incidents of Noncompliance (INCs). The notification issued to BP is for a number of alleged regulatory violations concerning Macondo well operations. On 7 December 2011, the Bureau of Safety and Environmental Enforcement issued to BP a second INC for five alleged violations related to drilling and abandonment operations at the Macondo well. BP filed an administrative appeal with respect to the first and second INCs and filed a joint stay of proceedings with the Department of Interior with respect to both INCs. Pursuant to the Consent Decree with the United States (see above), BP withdrew its appeals on 18 April 2016, and the INCs have been fully and finally resolved. Pending investigations and reports relating to the Deepwater Horizon oil spill CSB investigation On 13 April 2016, the US Chemical Safety and Hazard Investigation Board (CSB) released the final two volumes of its four-volume report on its investigation into the Incident. The final two volumes primarily concern the role of the regulator in the oversight of the offshore industry and organizational and cultural factors. They include proposed recommendations to the US Department of Interior’s Bureau of Safety and Environmental Enforcement, the American Petroleum Institute, the Ocean Energy Safety Institute and the Sustainability Accounting Standards Board. 264 BP Annual Report and Form 20-F 2016 Other legal proceedings FERC and CFTC matters Following an investigation by the US Federal Energy Regulatory Commission (FERC) and the US Commodity Futures Trading Commission (CFTC) of several BP entities, the Administrative Law Judge of the FERC ruled on 13 August 2015 that BP manipulated the market by selling next-day, fixed price natural gas at Houston Ship Channel in 2008 in order to suppress the Gas Daily index and benefit its financial position. On 11 July 2016 the FERC issued an Order affirming the initial decision and directing BP to pay a civil penalty of $20.16 million and to disgorge $207,169 in unjust profits. On 10 August 2016, BP filed a request for rehearing with the FERC. BP strongly disagrees with the FERC’s decision and will ultimately appeal to the US Court of Appeals if necessary. Investigations by the FERC and CFTC into BP’s trading activities continue to be conducted from time to time. CSB matters In March 2007, the CSB issued a report on the March 2005 explosion and fire at the BP Texas City refinery. The report contained recommendations to the BP Texas City refinery and to the board of directors of BP. On 25 May 2016, the CSB closed its last open recommendation to BP. The CSB has now accepted that all of BP’s responses to its recommendations have been satisfactorily addressed. OSHA matters On 8 March 2010, the US Occupational Safety and Health Administration (OSHA) issued 65 citations to BP Products North America Inc. (BP Products) and BP-Husky Refining LLC (BP-Husky) for alleged violations of the Process Safety Management (PSM) standard at the Toledo refinery, with penalties of approximately $3 million. These citations resulted from an inspection conducted pursuant to OSHA’s Petroleum Refinery Process Safety Management National Emphasis Program. Both BP Products and BP-Husky contested the citations. The outcome of a pre-trial settlement of a number of the citations and a trial of the remainder was a reduction in the total penalty in respect of the citations from the original amount of approximately $3 million to $80,000. The OSH Review Commission granted OSHA’s petition for review and briefing was completed in the first half of 2014. Timing for the issuance of a decision by the Review Commission is currently uncertain. Depending on the outcome of this review, BP may also pay a penalty not to exceed $1 million in respect of similar issues at the BP Texas City refinery. Prudhoe Bay leak In March and August 2006, oil leaked from oil transit pipelines operated by BP Exploration (Alaska) Inc. (BPXA) at the Prudhoe Bay unit on the North Slope of Alaska. On 12 May 2008, a BP p.l.c. shareholder filed a consolidated complaint alleging violations of federal securities law on behalf of a putative class of BP p.l.c. shareholders, based on alleged misrepresentations concerning the integrity of the Prudhoe Bay pipeline before its shutdown on 6 August 2006. On 7 December 2015, the complaint was dismissed with prejudice. On 5 January 2016, plaintiffs filed a notice of appeal of that decision to the Ninth Circuit Court of Appeals, and briefing was completed on that appeal on 14 October 2016. Lead paint matters Since 1987, Atlantic Richfield Company (Atlantic Richfield), a subsidiary* of BP, has been named as a co-defendant in numerous lawsuits brought in the US alleging injury to persons and property caused by lead pigment in paint. The majority of the lawsuits have been abandoned or dismissed against Atlantic Richfield. Atlantic Richfield is named in these lawsuits as alleged successor to International Smelting and Refining and another company that manufactured lead pigment during the period 1920-1946. The plaintiffs include individuals and governmental entities. Several of the lawsuits purport to be class actions. The lawsuits seek various remedies including compensation to lead-poisoned children, cost to find and remove lead paint from buildings, medical monitoring and screening programmes, public warning and education of lead hazards, reimbursement of government healthcare costs and special education for lead-poisoned citizens and punitive damages. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgment in any proceeding. The amounts claimed and, if such suits were successful, the costs of implementing the remedies sought in the various cases could be substantial. While it is not possible to predict the outcome of these legal actions, Atlantic Richfield believes that it has valid defences. It intends to defend such actions vigorously and believes that the incurrence of liability is remote. Consequently, BP believes that the impact of these lawsuits on the group’s results, financial position or liquidity will not be material. Abbott Atlantis related matters In April 2009, Kenneth Abbott, as relator, filed an FCA lawsuit against BP, alleging that BP violated federal regulations, and made false statements in connection with its compliance with those regulations, by failing to have necessary documentation for the Atlantis subsea and other systems. BP is the operator and 56% interest owner of the Atlantis unit, which is in production in the Gulf of Mexico. On 28 August 2014, the court entered final judgment in favour of BP and on 14 March 2017, this was affirmed by the Fifth Circuit Court of Appeals. California False Claims Act matters On 4 November 2014, the California Attorney General filed a notice in California state court that it was intervening in a previously-sealed California False Claims Act (CFCA) lawsuit filed by relator Christopher Schroen against BP, BP Energy Company, BP Corporation North America Inc., BP Products and BPAPC. On 7 January 2015, the California Attorney General filed a complaint in intervention alleging that BP violated the CFCA and the California Unfair Competition Law by falsely and fraudulently overcharging California state entities for natural gas. The relator’s complaint makes similar allegations in addition to individual claims. The complaints seek treble damages, punitive damages, penalties and injunctive relief. Trial is scheduled to commence in the second half of 2017. Scharfstein v. BP West Coast Products, LLC A class action lawsuit was filed against BP West Coast Products, LLC in Oregon State Court under the Oregon Unlawful Trade Practices Act on behalf of customers who used a debit card at ARCO gasoline stations in Oregon during the period 1 January 2011 to 30 August 2013, alleging that ARCO sites in Oregon failed to provide sufficient notice of the 35 cents per transaction debit card fee. In January 2014, the jury rendered a verdict against BP and awarded statutory damages of $200 per class member. On 25 August 2015, the trial court determined the size of the class to be slightly in excess of two million members. On 31 May 2016 the trial court entered a judgment for the amount of $417.3 million. On 1 June 2016 BP filed a notice of appeal. No provision has been made for damages arising out of this class action. International trade sanctions During the period covered by this report, non-US subsidiaries*, or other non-US entities of BP, conducted limited activities in, or with persons from, certain countries identified by the US Department of State as State Sponsors of Terrorism or otherwise subject to US and EU sanctions (Sanctioned Countries). Sanctions restrictions continue to be insignificant to the group’s financial condition and results of operations. BP monitors its activities with Sanctioned Countries, persons from Sanctioned Countries and individuals and companies subject to US and EU sanctions and seeks to comply with applicable sanctions laws and regulations. The US and the EU implemented temporary, limited and reversible relief of certain sanctions related to Iran pursuant to a Joint Plan of Action (JPOA) entered by Iran, China, France, Germany, Russia, the UK and the US with effect from 20 January 2014 and in July 2015, these countries, together with the EU, agreed the Joint Comprehensive Plan of Action (JCPOA). Following confirmation by the International Atomic Energy Agency on 16 January 2016 (Implementation Day) that Iran had fully implemented the JCPOA measures necessary for sanctions relief, the European Union and the United States lifted or suspended certain nuclear related sanctions, with the EU lifting nuclear related primary sanctions and the United States suspending nuclear related secondary sanctions. Following Implementation Day, BP has considered and developed possible business opportunities in relation to Iran, engaged in discussions with Iranian government officials and other Iranian nationals and attended conferences, and will continue to do so. During the second half of 2016, BP Iran Limited leased and refurbished an office in Tehran. In December 2016, BP purchased condensate from National Iranian Oil Company (NIOC). The condensate was loaded in Iran on 23 December 2016 and delivered to BP’s Rotterdam refinery on 15 January 2017. BP intends to continue to explore commercial opportunities with NIOC (or its subsidiaries). BP has a 50% interest in and operates the North Sea Rhum field (Rhum). Iranian Oil Company (U.K.) Limited (IOC UK) holds a 50% interest in Rhum. Production was suspended at Rhum in November 2010. Under a temporary management scheme, the UK government assumed control of and managed IOC UK’s interest in the Rhum field, thereby permitting Rhum operations to recommence in mid-October 2014 in accordance with applicable EU regulations and in compliance with a licence from the US Office of Foreign Assets Control. Following Implementation Day, the temporary management scheme ceased, with control and management of IOC UK’s interest passing back to IOC UK, and BP obtained an updated OFAC licence in relation to the continued operation of Rhum on 29 September 2016. BP has a 28.8% interest in and operates the Azerbaijan Shah Deniz field (Shah Deniz) and a related gas pipeline entity, South Caucasus Pipeline Company Limited (SCPC), and has a 23% non-operated interest in a related gas marketing entity, Azerbaijan Gas Supply Company Limited (AGSC). Naftiran Intertrade Co. Limited and NICO SPV Limited (collectively, NICO) have a 10% non-operating interest in each of Shah Deniz and SCPC and an 8% non-operating interest in AGSC. Shah Deniz, SCPC and AGSC continue in operation as they were excluded from the main operative provisions of the EU regulations as well as from the application of the US sanctions, and fall within the exception for certain natural gas projects under Section 603 of ITRA. BP holds an interest in a non-BP operated Indian joint venture* and sold produced crude oil to an Indian entity in which NICO holds a minority, non-controlling stake. Both the US and the EU have enacted strong sanctions against Syria, including a prohibition on the purchase of Syrian-origin crude and a US prohibition on the provision of services to Syria by US persons. The EU sanctions against Syria include a prohibition on supplying certain equipment used in the production, refining, or liquefaction of petroleum resources, as well as restrictions on dealing with the Central Bank of Syria and numerous other Syrian financial institutions. Following the imposition in 2011 of further US and EU sanctions against Syria, BP terminated all sales of crude oil and petroleum products into Syria, though BP continues to supply aviation fuel to non-governmental Syrian resellers outside of Syria. BP has equity interests in non-operated joint arrangements* with air fuel sellers, resellers, and fuel delivery services around the world. From time to time, the joint arrangement operator or other partners may sell or deliver fuel to airlines from Sanctioned Countries or flights to Sanctioned Countries. BP has registered and paid required fees to maintain registrations of patents and trade marks in Sanctioned Countries. BP sells lubricants in Cuba through a 50:50 joint arrangement and trades in small quantities of lubricants. A d d i t i o n a l d i s c l o s u r e s BP Annual Report and Form 20-F 2016 265 During 2014 the US and the EU imposed sanctions on certain Russian activities, individuals and entities, including Rosneft. Certain sectoral sanctions also apply to entities owned 50% or more by entities on the relevant sectoral sanctions list. Ruhr Oel GmbH (ROG) was a 50:50 joint operation* with Rosneft, operated by BP, which held interests in a number of refineries in Germany. These sanctions have had no material adverse impact on BP or ROG. On 31 December 2016, the previously-announced dissolution of ROG was completed. Disclosure pursuant to Section 219 of ITRA To our knowledge, none of BP’s activities, transactions or dealings are required to be disclosed pursuant to Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA) Section 219, with the following possible exceptions: • Rhum, located in the UK sector of the North Sea, is operated by BP Exploration Operating Company Limited (BPEOC), a non-US subsidiary of BP. Rhum is owned under a 50:50 unincorporated joint arrangement between BPEOC and Iranian Oil Company (U.K.) Limited. The Rhum joint arrangement was originally formed in 1974. On 16 November 2010, production from Rhum was suspended in response to relevant EU sanctions. Operations at the Rhum gas field recommenced in mid-October 2014 in accordance with the UK government’s temporary scheme (see above). During 2016, BP recorded gross revenues of $67.2 million related to its interests in Rhum. BP had a net profit of $31.6 million for the year ended 31 December 2016, including an impairment reversal of $48.9 million in the third quarter of 2016. BP currently intends to continue to hold its ownership stake in the Rhum joint arrangement and act as operator. • In December 2016, BP Singapore Pte. Limited (BPS) purchased a shipment of South Pars condensate from NIOC, which was loaded in Iran on 23 December 2016 and delivered to BP’s Rotterdam refinery on 15 January 2017. BPS made a payment ($52 million equivalent) in consideration for the condensate on 19 January 2017. Upon delivery, the condensate was comingled with other products for refining, and therefore BP is unable to ascertain an amount of gross revenue or gross profit attributable to it. BP intends to continue to explore commercial opportunities with NIOC (or its subsidiaries). • BP Iran Limited leased and refurbished an office in Tehran during 2016. The office is used for administrative activities. In 2016, rental tax payments associated with the Tehran office, with an aggregate US dollar equivalent value of approximately $6,000, were paid from a BP trust account held with Tadvin Co. to Iranian public entities. No gross revenues or net profits were attributable to these activities. BP intends to continue to maintain an office in Tehran. • During 2016, certain BP employees visited Iran for the purpose of meetings with Iranian government officials and other Iranian nationals and attending conferences. Payments were made to Iranian public entities for visas and taxes in relation to such visits with an aggregate US dollar equivalent value of approximately $18,730. No gross revenues or net profits were attributable to these activities, save where otherwise disclosed, and BP intends to continue visits to Iran in connection with various business opportunities. • During 2016, BP Iran Limited entered into a number of confidentiality agreements for the purpose of sharing information with potential local Iranian partners. Two of these confidentiality agreements are with exploration and production companies in which the Iranian-state holds an interest. No gross revenues or net profits were attributable to these activities. BP’s intention to continue to explore commercial opportunities with one, both or neither of these E&P companies is dependent upon the specific outcome of the potential commercial opportunities with NIOC (or its subsidiaries). Material contracts On 13 March 2014, BP, BP Exploration & Production Inc., and other BP entities entered into an administrative agreement with the US Environmental Protection Agency, which resolved all issues related to the suspension or debarment of BP entities arising from the 20 April 2010 explosions and fire on the semi-submersible rig Deepwater 266 BP Annual Report and Form 20-F 2016 Horizon and resulting oil spill. The administrative agreement allows BP entities to enter into new contracts or leases with the US government. Under the terms and conditions of this agreement, which will apply for five years, BP has agreed to a set of safety and operations, ethics and compliance and corporate governance requirements. The agreement is governed by federal law. On 4 April 2016 the district court approved the Consent Decree among BP Exploration & Production Inc., BP Corporation North America Inc., BP p.l.c., the United States and the states of Alabama, Florida, Louisiana, Mississippi and Texas (the Gulf states) which fully and finally resolves any and all natural resource damages (NRD) claims of the United States, the Gulf states, and their respective natural resource trustees and all Clean Water Act (CWA) penalty claims, and certain other claims of the United States and the Gulf states. Concurrently, the definitive Settlement Agreement that BP entered into with the Gulf states (Settlement Agreement) with respect to State claims for economic, property and other losses became effective. BP has filed the Consent Decree and the Settlement Agreement as exhibits to its Annual Report on Form 20-F 2016 filed with the SEC. For further details of the Consent Decree and the Settlement Agreement, see Legal proceedings on page 261. Property, plant and equipment BP has freehold and leasehold interests in real estate and other tangible assets in numerous countries, but no individual property is significant to the group as a whole. For more on the significant subsidiaries of the group at 31 December 2016 and the group percentage of ordinary share capital see Financial statements – Note 36. For information on significant joint ventures* and associates* of the group see Financial statements – Notes 15 and 16. Related-party transactions Transactions between the group and its significant joint ventures and associates are summarized in Financial statements – Note 15 and Note 16. In the ordinary course of its business, the group enters into transactions with various organizations with which some of its directors or executive officers are associated. Except as described in this report, the group did not have material transactions or transactions of an unusual nature with, and did not make loans to, related parties in the period commencing 1 January 2016 to 16 March 2017. Corporate governance practices In the US, BP ADSs are listed on the New York Stock Exchange (NYSE). The significant differences between BP’s corporate governance practices as a UK company and those required by NYSE listing standards for US companies are listed as follows: Independence BP has adopted a robust set of board governance principles, which reflect the UK Corporate Governance Code and its principles-based approach to corporate governance. As such, the way in which BP makes determinations of directors’ independence differs from the NYSE rules. BP’s board governance principles require that all non-executive directors be determined by the board to be ‘independent in character and judgement and free from any business or other relationship which could materially interfere with the exercise of their judgement’. The BP board has determined that, in its judgement, all of the non-executive directors are independent. In doing so, however, the board did not explicitly take into consideration the independence requirements outlined in the NYSE’s listing standards. Committees BP has a number of board committees that are broadly comparable in purpose and composition to those required by NYSE rules for domestic US companies. For instance, BP has a chairman’s (rather than executive) committee, nomination (rather than nominating/ corporate governance) committee and remuneration (rather than compensation) committee. BP also has an audit committee, which NYSE rules require for both US companies and foreign private issuers. These committees are composed solely of non-executive directors whom the board has determined to be independent, in the manner described above. The BP board governance principles prescribe the composition, main tasks and requirements of each of the committees (see the board committee reports on pages 69-79). BP has not, therefore, adopted separate charters for each committee. Under US securities law and the listing standards of the NYSE, BP is required to have an audit committee that satisfies the requirements of Rule 10A-3 under the Exchange Act and Section 303A.06 of the NYSE Listed Company Manual. BP’s audit committee complies with these requirements. The BP audit committee does not have direct responsibility for the appointment, reappointment or removal of the independent auditors instead, it follows the UK Companies Act 2006 by making recommendations to the board on these matters for it to put forward for shareholder approval at the AGM. One of the NYSE’s additional requirements for the audit committee states that at least one member of the audit committee is to have ‘accounting or related financial management expertise’. The board determined that Brendan Nelson possesses such expertise and also possesses the financial and audit committee experiences set forth in both the UK Corporate Governance Code and SEC rules (see Audit committee report on page 69). Mr Nelson is the audit committee financial expert as defined in Item 16A of Form 20-F. Shareholder approval of equity compensation plans The NYSE rules for US companies require that shareholders must be given the opportunity to vote on all equity-compensation plans and material revisions to those plans. BP complies with UK requirements that are similar to the NYSE rules. The board, however, does not explicitly take into consideration the NYSE’s detailed definition of what are considered ‘material revisions’. Code of ethics The NYSE rules require that US companies adopt and disclose a code of business conduct and ethics for directors, officers and employees. BP has adopted a code of conduct, which applies to all employees and members of the board, and has board governance principles that address the conduct of directors. In addition BP has adopted a code of ethics for senior financial officers as required by the SEC. BP considers that these codes and policies address the matters specified in the NYSE rules for US companies. Code of ethics The company has adopted a code of ethics for its group chief executive, chief financial officer, group controller, group head of audit and chief accounting officer as required by the provisions of Section 406 of the Sarbanes-Oxley Act of 2002 and the rules issued by the SEC. There have been no waivers from the code of ethics relating to any officers. BP also has a code of conduct, which is applicable to all employees, officers and members of the board. This was updated (and published) in July 2014. Controls and procedures Evaluation of disclosure controls and procedures The company maintains ‘disclosure controls and procedures’, as such term is defined in Exchange Act Rule 13a-15(e), that are designed to ensure that information required to be disclosed in reports the company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including the company’s group chief executive and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, our management, including the group chief executive and chief financial officer, recognize that any controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. Further, in the design and evaluation of our disclosure controls and procedures our management necessarily was required to apply its judgement in evaluating the cost-benefit relationship of possible controls and procedures. Also, we have investments in certain unconsolidated entities. As we do not control these entities, our disclosure controls and procedures with respect to such entities are necessarily substantially more limited than those we maintain with respect to our consolidated subsidiaries. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. The company’s disclosure controls and procedures have been designed to meet, and management believes that they meet, reasonable assurance standards. The company’s management, with the participation of the company’s group chief executive and chief financial officer, has evaluated the effectiveness of the company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b) as of the end of the period covered by this annual report. Based on that evaluation, the group chief executive and chief financial officer have concluded that the company’s disclosure controls and procedures were effective at a reasonable assurance level. Management’s report on internal control over financial reporting Management of BP is responsible for establishing and maintaining adequate internal control over financial reporting. BP’s internal control over financial reporting is a process designed under the supervision of the principal executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of BP’s financial statements for external reporting purposes in accordance with IFRS. As of the end of the 2016 fiscal year, management conducted an assessment of the effectiveness of internal control over financial reporting in accordance with the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting. Based on this assessment, management has determined that BP’s internal control over financial reporting as of 31 December 2016 was effective. The company’s internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with IFRS and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of BP; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of BP’s assets that could have a material effect on our financial statements. BP’s internal control over financial reporting as of 31 December 2016 has been audited by Ernst & Young, an independent registered public accounting firm, as stated in their report appearing on page 120 of BP Annual Report and Form 20-F 2016. Changes in internal control over financial reporting There were no changes in the group’s internal control over financial reporting that occurred during the period covered by the Form 20-F that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting. A d d i t i o n a l d i s c l o s u r e s BP Annual Report and Form 20-F 2016 267 Indemnity provisions In accordance with BP’s Articles of Association, on appointment each director is granted an indemnity from the company in respect of liabilities incurred as a result of their office, to the extent permitted by law. These indemnities were in force throughout the financial year and at the date of this report. In respect of those liabilities for which directors may not be indemnified, the company maintained a directors’ and officers’ liability insurance policy throughout 2016. During the year, a review of the terms and scope of the policy was undertaken. The policy was renewed during 2016 and continued into 2017. Although their defence costs may be met, neither the company’s indemnity nor insurance provides cover in the event that the director is proved to have acted fraudulently or dishonestly. Certain subsidiaries are trustees of the group’s pension schemes. Each director of these subsidiaries* is granted an indemnity from the company in respect of liabilities incurred as a result of such a subsidiary’s activities as a trustee of the pension scheme, to the extent permitted by law. These indemnities were in force throughout the financial year and at the date of this report. Financial risk management objectives and policies The disclosures in relation to financial risk management objectives and policies, including the policy for hedging, are included in How we manage risk on page 47, Liquidity and capital resources on page 242 and Financial statements – Notes 28 and 29. Exposure to price risk, credit risk, liquidity risk and cash flow risk The disclosures in relation to exposure to price risk, credit risk, liquidity risk and cash flow risk are included in Financial statements – Note 28. Important events since the end of the financial year Disclosures of the particulars of the important events affecting BP which have occurred since the end of the financial year are included in the Strategic report as well as in other places in the Directors’ report. Likely future developments in the business An indication of the likely future developments of the business is included in the Strategic report. Research and development An indication of the activities of the company in the field of research and development is included in Using technology on page 12. Branches As a global group our interests and activities are held or operated through subsidiaries, branches, joint arrangements* or associates* established in – and subject to the laws and regulations of – many different jurisdictions. Employees The disclosures concerning policies in relation to the employment of disabled persons and employee involvement are included in Sustainability – Our people on page 46. Employee share schemes Certain shares held as a result of participation in some employee share plans carry voting rights. Voting rights in respect of such shares are exercisable via a nominee. Dividend waivers are in place in respect of unallocated shares held in employee share plan trusts. Change of control provisions On 5 October 2015, the United States lodged with the district court in MDL 2179 a proposed Consent Decree between the United States, the Gulf states, BP Exploration & Production Inc., BP Corporation North America Inc. and BP p.l.c., to fully and finally resolve any and all natural resource damages claims of the United States, the Gulf states and their respective natural resource trustees and all Clean Water Act penalty claims, and certain other claims of the United States and the Gulf states. Concurrently, BP entered into a definitive Settlement Agreement with the five Gulf states (Settlement Agreement) with respect to state claims for economic, property and other losses. On Principal accountants’ fees and services The audit committee has established policies and procedures for the engagement of the independent registered public accounting firm, Ernst & Young LLP, to render audit and certain assurance and tax services. The policies provide for pre-approval by the audit committee of specifically defined audit, audit-related, tax and other services that are not prohibited by regulatory or other professional requirements. Ernst & Young are engaged for these services when its expertise and experience of BP are important. Most of this work is of an audit nature. The policy has been updated such that all non-audit tax services provided by the audit firm from 2017 onwards are prohibited. In 2016 tax services were awarded either through a full competitive tender process or following an assessment of the expertise of Ernst & Young relative to that of other potential service providers. These services are for a fixed term. Under the policy, pre-approval is given for specific services within the following categories: advice on accounting, auditing and financial reporting matters; internal accounting and risk management control reviews (excluding any services relating to information systems design and implementation); non-statutory audit; project assurance and advice on business and accounting process improvement (excluding any services relating to information systems design and implementation relating to BP’s financial statements or accounting records); due diligence in connection with acquisitions, disposals and joint arrangements* (excluding valuation or involvement in prospective financial information); income tax and indirect tax compliance and advisory services; employee tax services (excluding tax services that could impair independence); provision of, or access to, Ernst & Young publications, workshops, seminars and other training materials; provision of reports from data gathered on non-financial policies and information; provision of the independent third party audit in accordance with US Generally Accepted Government Auditing Standards, over the company’s Conflict Minerals Report – where such a report is required under the SEC rule ‘Conflict Minerals’, issued in accordance with Section 1502 of the Dodd Frank Act; and assistance with understanding non-financial regulatory requirements. BP operates a two-tier system for audit and non-audit services. For audit related services, the audit committee has a pre-approved aggregate level, within which specific work may be approved by management. Non-audit services, including tax services, are pre-approved for management to authorize per individual engagement, but above a defined level must be approved by the chairman of the audit committee or the full committee. In response to the revised regulatory guidelines of the FRC, the audit committee reviewed and updated its policies with effect from 1 January 2017. The defined maximum level for pre-approval will be reduced in 2017 in line with Financial Reporting Council guidance on ‘non-trivial’ engagements. The audit committee has delegated to the chairman of the audit committee authority to approve permitted services provided that the chairman reports any decisions to the committee at its next scheduled meeting. Any proposed service not included in the approved service list must be approved in advance by the audit committee chairman and reported to the committee, or approved by the full audit committee in advance of commencement of the engagement. The audit committee evaluates the performance of the auditors each year. The audit fees payable to Ernst & Young are reviewed by the committee in the context of other global companies for cost effectiveness. The committee keeps under review the scope and results of audit work and the independence and objectivity of the auditors. External regulation and BP policy requires the auditors to rotate their lead audit partner every five years. (See Financial statements – Note 35 and Audit committee report on page 69 for details of fees for services provided by auditors.) Directors’ report information This section of BP Annual Report and Form 20-F 2016 forms part of, and includes certain disclosures which are required by law to be included in, the Directors’ report. 268 BP Annual Report and Form 20-F 2016 4 April 2016, the district court approved the Consent Decree, at which time the Consent Decree and Settlement Agreement became effective. The federal government and the Gulf states may jointly elect to accelerate the payments under the Consent Decree in the event of a change of control or insolvency of BP p.l.c., and the Gulf states individually have similar acceleration rights under the Settlement Agreement. For further details of the Consent Decree and the Settlement Agreement, see Legal proceedings on page 261. Greenhouse gas emissions The disclosures in relation to greenhouse gas emissions are included in Sustainability – Climate change on page 43. Disclosures required under Listing Rule 9.8.4R The information required to be disclosed by Listing Rule 9.8.4R can be located as set out below: Information required (1) Amount of interest capitalized (2) – (11) (12), (13) Dividend waivers (14) Page 145 Not applicable 268 Not applicable Cautionary statement In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’), BP is providing the following cautionary statement. This document contains certain forecasts, projections and forward-looking statements – that is, statements related to future, not past events – with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, (i) certain statements in the Chairman’s letter (pages 4-5), the Group chief executive’s letter (pages 6-7), the Strategic report (inside cover and pages 2-50), Additional disclosures (pages 239-270) and Shareholder information (pages 271-279), including but not limited to statements under the headings ‘The changing world of energy’, ‘How we run our business’, ‘Our strategy’ and ‘Challenging global energy markets’ and including but not limited to statements regarding plans and prospects relating to future value creation, near and long-term growth, capital discipline and growth in sustainable free cash flow and shareholder distributions; future dividend and optional scrip dividend payments; expectations regarding world energy demand through 2035, including the growth in relative demand for renewables, oil and gas; expectations regarding the use of electric vehicles and the expansion of BP’s global business services organization; expectations regarding future emissions and carbon policies and the share of BP’s direct emissions subject to such policies; plans and expectations regarding future capital expenditure, reduction in BP’s cash costs, Other businesses and corporate annual charges (excluding non-operating items), proceeds from divestments, non-operating restructuring charges, net debt levels, and the timing and amount of future payments relating to the Gulf of Mexico oil spill; statements that PSC settlement claims are expected to be substantially paid in 2017; plans and expectations regarding sales commitments of BP and its equity-accounted entities; expectations regarding underlying production and capital investment in 2017; expectations regarding oil prices and their impact on BP’s return on average capital employed; expectations regarding organic capital expenditure and the cash balance point in 2017; plans regarding gearing; plans and expectations for operating cash flow excluding payments relating to the Gulf of Mexico oil spill to cover organic capital expenditure and the dividend at an oil price of around $60 per barrel by the end of 2017 and plans and expectations for driving the balance point closer to $55 per barrel by the end of 2017; expectations that the cash balance point will reduce over the next five years; expectations regarding the effective tax rate in 2017; plans and expectations regarding future levels of BP production through 2020, including increases in production from new projects; plans and expectations regarding investment, development, and production levels and the timing thereof with respect to projects and partnerships in Abu Dhabi, Alaska, Argentina, Australia, Azerbaijan, Bolivia, Brazil, Canada, China, Egypt, Georgia, India, Indonesia, Kuwait, Mauritania, Mexico, Oman, Russia, Senegal, Trinidad & Tobago, Turkey, the UK North Sea, and the United States; plans and expectations regarding plant reliability; plans and expectations regarding the share of LNG production from the Tangguh gas facility sold to the Indonesian state electricity company, the number of jobs the facility will create and the share of the Papuan workforce at the facility; expectations regarding refining margins and refining turnarounds; plans to undertake joint exploration and research with Rosneft; plans and expectations with regard to the strategic aims of Air BP and the lubricants business; plans to retain our carbon neutral accreditation at certain Air BP-operated facilities and to reduce emissions by 5% over the next 10 years; plans and expectations regarding the upgrades at plants in Belgium and South Carolina and the resulting increase in manufacturing efficiency at those facilities; plans and expectations regarding additions to BP’s fleet of oil tankers and LNG tankers; expectations regarding the actions of contractors and partners and their terms of service; BP’s aim to maintain a diverse workforce, create an inclusive environment and ensure equal opportunity, including for women to represent 25% of group leaders by 2020; policies and goals related to risk management plans to address employee engagement; plans and expectations to reduce BP’s reliance on US persons at the Rhum gas field; plans regarding activities, dealings and transactions relating to Iran; plans and expectations regarding the sale of stakes in Magnus and certain associated pipelines and the Sullom Voe Terminal; plans and projections regarding oil and gas reserves, including the turnover time of proved undeveloped reserves to proved developed reserves; plans and expectations regarding the renewal of leases; expectations regarding the future value of assets; expectations regarding future regulations and policy, their impact on BP’s business and plans regarding compliance with such regulations; plans and expectations regarding settlement of claims related to the Deepwater Horizon incident and related legal proceedings; and expectations regarding legal and trial proceedings, court decisions, potential investigations and civil actions by regulators, government entities and/or other entities or parties, and the timing of such proceedings and BP’s intentions in respect thereof; and (ii) certain statements in Corporate governance (pages 51-79) and the Directors’ remuneration report (pages 80-110) with regard to the anticipated future composition of the board of directors; the board’s goals and areas of focus stemming from the board’s annual evaluation; plans regarding the appointment of Deloitte as auditor from 2018; plans regarding the implementation of a new remuneration policy; plans and expectations with regard to the remuneration, pensions and other benefits of executive directors; and goals and areas of focus of board committees, are all forward looking in nature. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; production- sharing agreements effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non- BP Annual Report and Form 20-F 2016 269 A d d i t i o n a l d i s c l o s u r e s compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyberattacks or sabotage; and other factors discussed elsewhere in this report including under Risk factors (pages 49-50). In addition to factors set forth elsewhere in this report, those set out above are important factors, although not exhaustive, that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements. Statements regarding competitive position Statements referring to BP’s competitive position are based on the company’s belief and, in some cases, rely on a range of sources, including investment analysts’ reports, independent market studies and BP’s internal assessments of market share based on publicly available information about the financial results and performance of market participants. 270 BP Annual Report and Form 20-F 2016 Shareholder information 272 Share prices and listings 272 Dividends 273 Shareholder taxation information 275 Major shareholders 276 Annual general meeting 276 Memorandum and Articles of Association 278 Purchases of equity securities by the issuer and affiliated purchasers 278 Fees and charges payable by ADSs holders 279 Fees and payments made by the Depositary to the issuer 279 Documents on display 279 Shareholding administration 279 Exhibits S h a r e h o d e r l i n f o r m a t i o n BP Annual Report and Form 20-F 2016 271 Share prices and listings Markets and market prices The primary market for BP’s ordinary shares is the London Stock Exchange (LSE). BP’s ordinary shares are a constituent element of the Financial Times Stock Exchange 100 Index. BP’s ordinary shares are also traded on the Frankfurt Stock Exchange in Germany. Trading of BP’s shares on the LSE is primarily through the use of the Stock Exchange Electronic Trading Service (SETS), introduced in 1997 for the largest companies in terms of market capitalization whose primary listing is the LSE. Under SETS, buy and sell orders at specific prices may be sent electronically to the exchange by any firm that is a member of the LSE, on behalf of a client or on behalf of itself acting as a principal. The orders are then anonymously displayed in the order book. When there is a match on a buy and a sell order, the trade is executed and automatically reported to the LSE. Trading is continuous from 8.00am to 4.30pm UK time but, in the event of a 20% movement in the share price either way, the LSE may impose a temporary halt in the trading of that company’s shares in the order book to allow the market to re-establish equilibrium. Dealings in ordinary shares may also take place between an investor and a market maker, via a member firm, outside the electronic order book. In the US BP’s securities are traded on the New York Stock Exchange (NYSE) in the form of ADSs, for which JPMorgan Chase Bank, N.A. is the depositary (the Depositary) and transfer agent. The Depositary’s principal office is 4 New York Plaza, Floor 12, New York, NY, 10004, US. Each ADS represents six ordinary shares. ADSs are listed on the NYSE. ADSs are evidenced by American depositary receipts (ADRs), which may be issued in either certificated or book entry form. The following table sets forth, for the periods indicated, the highest and lowest market prices for BP’s ordinary shares and ADSs for the periods shown. These are derived from the highest and lowest intra-day sales prices as reported on the LSE and NYSE, respectively. Year ended 31 December 2012 2013 2014 2015 2016 Year ended 31 December 2015: First quarter (January-March) Second quarter (April-June) Third quarter (July-September) Fourth quarter (October-December) 2016: First quarter (January-March) Second quarter (April-June) Third quarter (July-September) Fourth quarter (October-December) 2017: First quarter (to 16 March) Month of September 2016 October 2016 November 2016 December 2016 January 2017 February 2017 March 2017 (to 16 March) a One ADS is equivalent to six 25 cent ordinary shares. Source: Thomson Reuters Datastream. Pence Dollars Ordinary shares American depositary sharesa High Low High Low 512.00 494.20 526.80 487.50 513.24 463.10 487.50 445.05 411.50 381.80 438.15 464.40 513.24 521.20 453.25 498.45 483.70 513.24 521.20 482.95 474.55 388.56 426.50 364.40 319.90 309.10 376.70 420.15 319.90 328.80 309.10 335.07 408.63 432.15 440.80 411.60 459.30 432.15 458.95 472.80 440.80 448.00 48.34 48.65 53.48 43.85 37.68 42.10 43.85 41.52 37.53 32.38 35.59 37.28 37.68 38.68 35.39 36.83 35.27 37.68 38.68 36.20 34.55 36.25 39.99 34.88 29.35 27.01 34.93 39.27 29.35 29.90 27.01 28.67 32.50 32.53 33.10 33.06 35.55 32.53 35.29 35.73 33.33 33.10 Market prices for the ordinary shares on the LSE and in after-hours trading off the LSE, in each case while the NYSE is open, and the market prices for ADSs on the NYSE, are closely related due to arbitrage among the various markets, although differences may exist from time to time. On 16 March 2017 923,167,362 ADSs (equivalent to approximately 5,539,010,217 ordinary shares or some 28.32% of the total issued share capital, excluding shares held in treasury) were outstanding and were held by approximately 88,594 ADS holders. Of these, about 87,560 had registered addresses in the US at that date. One of the registered holders of ADSs represents some 1,031,491 underlying holders. On 16 March 2017 there were approximately 248,855 ordinary shareholders. Of these shareholders, around 1,570 had registered addresses in the US and held a total of some 4,001,956 ordinary shares. Since a number of the ordinary shares and ADSs were held by brokers and other nominees, the number of holders in the US may not be representative of the number of beneficial holders of their respective country of residence. Dividends BP’s current policy is to pay interim dividends on a quarterly basis on its ordinary shares. Its policy is also to announce dividends for ordinary shares in US dollars and state an equivalent sterling dividend. Dividends on BP ordinary shares will be paid in sterling and on BP ADSs in US dollars. The rate of exchange used to determine the sterling amount equivalent is the average of the market exchange rates in London over the four business days prior to the sterling equivalent announcement date. The directors may choose to declare dividends in any currency provided that a sterling equivalent is announced. It is not the company’s intention to change its current policy of announcing dividends on ordinary shares in US dollars. Information regarding dividends announced and paid by the company on ordinary shares and preference shares is provided in Financial statements – Note 9. A Scrip Dividend Programme (Scrip Programme) was approved by shareholders in 2010 and was renewed for a further three years at the 2015 AGM. It enables BP ordinary shareholders and ADS holders to elect to receive dividends by way of new fully paid BP ordinary shares (or ADSs 272 BP Annual Report and Form 20-F 2016 in the case of ADS holders) instead of cash. The operation of the Scrip Programme is always subject to the directors’ decision to make the Scrip Programme offer available in respect of any particular dividend. Should the directors decide not to offer the Scrip Programme in respect of any particular dividend, cash will be paid automatically instead. Future dividends will be dependent on future earnings, the financial condition of the group, the Risk factors set out on page 49 and other matters that may affect the business of the group set out in Our strategy on page 14 and in Liquidity and capital resources on page 242. The following table shows dividends announced and paid by the company per ADS for the past five years. Dividends per ADSa 2012 2013 2014 2015 2016 UK pence US cents UK pence US cents UK pence US cents UK pence US cents UK pence US cents March 30.57 30.90 48 June September December 30.10 48 Total 33.53 125.10 198 54 48 57 54 36.01 35.01 54 34.24 34.84 58.5 40.00 39.18 60 42.08 41.50 60 60 60 34.58 54 35.76 58.5 39.29 60 45.35 60 57 60 34.80 140.40 219 38.26 143.10 234 39.81 158.28 240 47.59 176.52 240 60 60 a Dividends announced and paid by the company on ordinary and preference shares are provided in Financial statements – Note 9. There are currently no UK foreign exchange controls or restrictions on remittances of dividends on the ordinary shares or on the conduct of the company’s operations, other than restrictions applicable to certain countries and persons subject to EU economic sanctions or those sanctions adopted by the UK government which implement resolutions of the Security Council of the United Nations. Shareholder taxation information This section describes the material US federal income tax and UK taxation consequences of owning ordinary shares or ADSs to a US holder who holds the ordinary shares or ADSs as capital assets for tax purposes. It does not apply, however, inter alia to members of special classes of holders some of which may be subject to other rules, including: tax-exempt entities, life insurance companies, dealers in securities, traders in securities that elect a mark-to-market method of accounting for securities holdings, investors liable for alternative minimum tax, holders that, directly or indirectly, hold 10% or more of the company’s voting stock, holders that hold the shares or ADSs as part of a straddle or a hedging or conversion transaction, holders that purchase or sell the shares or ADSs as part of a wash sale for US federal income tax purposes, or holders whose functional currency is not the US dollar. In addition, if a partnership holds the shares or ADSs, the US federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership and may not be described fully below. A US holder is any beneficial owner of ordinary shares or ADSs that is for US federal income tax purposes (1) a citizen or resident of the US, (2) a US domestic corporation, (3) an estate whose income is subject to US federal income taxation regardless of its source, or (4) a trust if a US court can exercise primary supervision over the trust’s administration and one or more US persons are authorized to control all substantial decisions of the trust. This section is based on the tax laws of the United States, including the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed US Treasury regulations thereunder, published rulings and court decisions, and the taxation laws of the UK, all as currently in effect, as well as the income tax convention between the US and the UK that entered into force on 31 March 2003 (the ‘Treaty’). These laws are subject to change, possibly on a retroactive basis. This section further assumes that each obligation under the terms of the deposit agreement relating to BP ADSs and any related agreement will be performed in accordance with its terms. For purposes of the Treaty and the estate and gift tax Convention (the ‘Estate Tax Convention’) and for US federal income tax and UK taxation purposes, a holder of ADRs evidencing ADSs will be treated as the owner of the company’s ordinary shares represented by those ADRs. Exchanges of ordinary shares for ADRs and ADRs for ordinary shares generally will not be subject to US federal income tax or to UK taxation other than stamp duty or stamp duty reserve tax, as described below. Investors should consult their own tax adviser regarding the US federal, state and local, UK and other tax consequences of owning and disposing of ordinary shares and ADSs in their particular circumstances, and in particular whether they are eligible for the benefits of the Treaty in respect of their investment in the shares or ADSs. Taxation of dividends UK taxation Under current UK taxation law, no withholding tax will be deducted from dividends paid by the company, including dividends paid to US holders. A shareholder that is a company resident for tax purposes in the UK or trading in the UK through a permanent establishment generally will not be taxable in the UK on a dividend it receives from the company. A shareholder who is an individual resident for tax purposes in the UK is subject to UK tax but until 5 April 2016, is entitled to a tax credit on cash dividends paid on ordinary shares or ADSs of the company equal to one-ninth of the cash dividend. From 6 April 2016 the Dividend Tax Credit was replaced by a new tax-free Dividend Allowance and dividends paid by the Company on or after 6 April 2016 do not carry a UK tax credit. A Dividend Allowance has been introduced whereby there is no UK tax due on the first £5,000 of dividends received. Dividends above this level are subject to tax at 7.5% for basic tax payers, 32.5% for higher rate tax payers and 38.1% for additional rate tax payers. Although the first £5,000 of dividend income is not subject to UK income tax, it does not reduce the total income for tax purposes. Dividends within the Dividend Allowance still count towards basic or higher rate bands, and may therefore affect the rate of tax paid on dividends received in excess of the £5,000 allowance. For instance, if an individual has £2,000 of the basic rate band remaining after earning non-dividend income, and receives £6,000 of dividend income, they will be subject to the following scenario. The Dividend Allowance will cover the first £2,000 of dividends which fall into the remaining basic rate band, leaving the remaining £3,000 of the allowance to use in the higher rate band. The first £5,000 dividend income is therefore covered by the allowance and is not subject to tax. The remaining £1,000 of dividend income falls into the higher rate band and is taxed at the rate of 32.5%. How the shareholder pays the tax arising on the dividend income depends on the amount of dividend income they receive in the tax year. If less than £5,000 they will not need to report anything or pay any tax. If between £5,000 and £10,000, the shareholder can pay what they owe by: contacting the helpline; asking HMRC to change their tax code – the tax will be taken from their wages or pension or through completion of the ‘Dividends’ section of their tax return, where one is being filed. If over £10,000 they will be required to file a self- assessment tax return and should complete the ‘Dividends’ section with details of the amounts received. US federal income taxation A US holder is subject to US federal income taxation on the gross amount of any dividend paid by the company out of its current or accumulated earnings and profits (as determined for US federal income tax purposes). Dividends paid to a non-corporate US holder that constitute ‘qualified dividend income’ will be taxable to the holder at a preferential rate, provided that the holder has a holding period in the ordinary shares or ADSs of more than 60 days during the 121-day period beginning 60 days before the ex-dividend date and meets other holding period requirements. Dividends paid by the company with respect to the ordinary shares or ADSs will generally be qualified dividend income. For US federal income tax purposes, a dividend must be included in income when the US holder, in the case of ordinary shares, or the BP Annual Report and Form 20-F 2016 273 S h a r e h o d e r l i n f o r m a t i o n Depositary, in the case of ADSs, actually or constructively receives the dividend and will not be eligible for the dividends-received deduction generally allowed to US corporations in respect of dividends received from other US corporations. US ADS holders should consult their own tax adviser regarding the US tax treatment of the dividend fee in respect of dividends. Dividends will be income from sources outside the US and generally will be ‘passive category income’ or, in the case of certain US holders, ‘general category income’, each of which is treated separately for purposes of computing a US holder’s foreign tax credit limitation. As noted above in UK taxation, a US holder will not be subject to UK withholding tax. Accordingly, the receipt of a dividend will not entitle the US holder to a foreign tax credit. The amount of the dividend distribution on the ordinary shares that is paid in pounds sterling will be the US dollar value of the pounds sterling payments made, determined at the spot pounds sterling/US dollar rate on the date the dividend distribution is includible in income, regardless of whether the payment is, in fact, converted into US dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the pounds sterling dividend payment is includible in income to the date the payment is converted into US dollars will be treated as ordinary income or loss and will not be eligible for the preferential tax rate on qualified dividend income. The gain or loss generally will be income or loss from sources within the US for foreign tax credit limitation purposes. Distributions in excess of the company’s earnings and profits, as determined for US federal income tax purposes, will be treated as a return of capital to the extent of the US holder’s basis in the ordinary shares or ADSs and thereafter as capital gain, subject to taxation as described in Taxation of capital gains – US federal income taxation section below. In addition, the taxation of dividends may be subject to the rules for passive foreign investment companies (PFIC), described below under ‘Taxation of capital gains – US federal income taxation’. Distributions made by a PFIC do not constitute qualified dividend income and are not eligible for the preferential tax rate applicable to such income. Taxation of capital gains UK taxation A US holder may be liable for both UK and US tax in respect of a gain on the disposal of ordinary shares or ADSs if the US holder is (1) resident for tax purposes in the United Kingdom at the date of disposal, (2) if he or she has left the UK for a period not exceeding five complete tax years between the year of departure from and the year of return to the UK and acquired the shares before leaving the UK and was resident in the UK in the previous four out of seven tax years before the year of departure, (3) a US domestic corporation resident in the UK by reason of its business being managed or controlled in the UK or (4) a citizen of the US that carries on a trade or profession or vocation in the UK through a branch or agency or a corporation that carries on a trade, profession or vocation in the UK, through a permanent establishment, and that has used, held, or acquired the ordinary shares or ADSs for the purposes of such trade, profession or vocation of such branch, agency or permanent establishment. However, such persons may be entitled to a tax credit against their US federal income tax liability for the amount of UK capital gains tax or UK corporation tax on chargeable gains (as the case may be) that is paid in respect of such gain. Under the Treaty, capital gains on dispositions of ordinary shares or ADSs generally will be subject to tax only in the jurisdiction of residence of the relevant holder as determined under both the laws of the UK and the US and as required by the terms of the Treaty. US federal income taxation A US holder who sells or otherwise disposes of ordinary shares or ADSs will recognize a capital gain or loss for US federal income tax purposes equal to the difference between the US dollar value of the amount realized on the disposition and the US holder’s tax basis, determined in US dollars, in the ordinary shares or ADSs. Any such capital gain or loss generally will be long-term gain or loss, subject to tax at a preferential rate for a non-corporate US holder, if the US holder’s holding period for such ordinary shares or ADSs exceeds one year. Gain or loss from the sale or other disposition of ordinary shares or ADSs will generally be income or loss from sources within the US for foreign tax credit limitation purposes. The deductibility of capital losses is subject to limitations. We do not believe that ordinary shares or ADSs will be treated as stock of a passive foreign investment company, or PFIC, for US federal income tax purposes, but this conclusion is a factual determination that is made annually and thus is subject to change. If we are treated as a PFIC, unless a US holder elects to be taxed annually on a mark-to-market basis with respect to ordinary shares or ADSs, any gain realized on the sale or other disposition of ordinary shares or ADSs would in general not be treated as capital gain. Instead, a US holder would be treated as if he or she had realized such gain rateably over the holding period for ordinary shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain was allocated, in addition to which an interest charge in respect of the tax attributable to each such year would apply. Certain ‘excess distributions’ would be similarly treated if we were treated as a PFIC. Additional tax considerations Scrip Programme The company has an optional Scrip Programme, wherein holders of BP ordinary shares or ADSs may elect to receive any dividends in the form of new fully paid ordinary shares or ADSs of the company instead of cash. Please consult your tax adviser for the consequences to you. UK inheritance tax The Estate Tax Convention applies to inheritance tax. ADSs held by an individual who is domiciled for the purposes of the Estate Tax Convention in the US and is not for the purposes of the Estate Tax Convention a national of the UK will not be subject to UK inheritance tax on the individual’s death or on transfer during the individual’s lifetime unless, among other things, the ADSs are part of the business property of a permanent establishment situated in the UK used for the performance of independent personal services. In the exceptional case where ADSs are subject to both inheritance tax and US federal gift or estate tax, the Estate Tax Convention generally provides for tax payable in the US to be credited against tax payable in the UK or for tax paid in the UK to be credited against tax payable in the US, based on priority rules set forth in the Estate Tax Convention. UK stamp duty and stamp duty reserve tax The statements below relate to what is understood to be the current practice of HM Revenue & Customs in the UK under existing law. Provided that any instrument of transfer is not executed in the UK and remains at all times outside the UK and the transfer does not relate to any matter or thing done or to be done in the UK, no UK stamp duty is payable on the acquisition or transfer of ADSs. Neither will an agreement to transfer ADSs in the form of ADRs give rise to a liability to stamp duty reserve tax. Under the Treaty, individuals who are residents of either the UK or the US and who have been residents of the other jurisdiction (the US or the UK, as the case may be) at any time during the six years immediately preceding the relevant disposal of ordinary shares or ADSs may be subject to tax with respect to capital gains arising from a disposition of ordinary shares or ADSs of the company not only in the jurisdiction of which the holder is resident at the time of the disposition but also in the other jurisdiction. Purchases of ordinary shares, as opposed to ADSs, through the CREST system of paperless share transfers will be subject to stamp duty reserve tax at 0.5%. The charge will arise as soon as there is an agreement for the transfer of the shares (or, in the case of a conditional agreement, when the condition is fulfilled). The stamp duty reserve tax will apply to agreements to transfer ordinary shares even if the agreement is made outside the UK between two non-residents. Purchases of ordinary shares outside the CREST system are subject 274 BP Annual Report and Form 20-F 2016 either to stamp duty at a rate of £5 per £1,000 (or part, unless the stamp duty is less than £5, when no stamp duty is charged), or stamp duty reserve tax at 0.5%. Stamp duty and stamp duty reserve tax are generally the liability of the purchaser. A subsequent transfer of ordinary shares to the Depositary’s nominee will give rise to further stamp duty at the rate of £1.50 per £100 (or part) or stamp duty reserve tax at the rate of 1.5% of the value of the ordinary shares at the time of the transfer. For ADR holders electing to receive ADSs instead of cash, after the 2012 first quarter dividend payment HM Revenue & Customs no longer seeks to impose 1.5% stamp duty reserve tax on issues of UK shares and securities to non-EU clearance services and depositary receipt systems. US Medicare Tax A US holder that is an individual or estate, or a trust that does not fall into a special class of trusts that is exempt from such tax, is subject to a 3.8% tax on the lesser of (1) the US holder’s ‘net investment income’ (or ‘undistributed net investment income’ in the case of an estate or trust) for the relevant taxable year and (2) the excess of the US holder’s modified adjusted gross income for the taxable year over a certain threshold (which in the case of individuals is between $125,000 and $250,000, depending on the individual’s circumstances). A holder’s net investment income generally includes its dividend income and its net gains from the disposition of shares or ADSs, unless such dividend income or net gains are derived in the ordinary course of the conduct of a trade or business (other than a trade or business that consists of certain passive or trading activities). If you are a US holder that is an individual, estate or trust, you are urged to consult your tax advisers regarding the applicability of the Medicare tax to your income and gains in respect of your investment in the shares or ADSs. Major shareholders The disclosure of certain major and significant shareholdings in the share capital of the company is governed by the Companies Act 2006, the UK Financial Conduct Authority’s Disclosure Guidance and Transparency Rules (DTR) and the US Securities Exchange Act of 1934. Register of members holding BP ordinary shares as at 31 December 2016 Range of holdings 1-200 201-1,000 1,001-10,000 10,001-100,000 100,001-1,000,000 Over 1,000,000a Number of ordinary shareholders 54,634 86,631 97,136 10,729 731 647 Percentage of total ordinary shareholders 21.81 34.58 38.78 4.28 0.29 0.26 Percentage of total ordinary share capital excluding shares held in treasury 0.01 0.24 1.55 1.12 1.44 95.64 Totals 250,508 100.00 100.00 a Includes JPMorgan Chase Bank, N.A. holding 28.31% of the total ordinary issued share capital (excluding shares held in treasury) as the approved depositary for ADSs, a breakdown of which is shown in the table below. Register of holders of American depositary shares (ADSs) as at 31 December 2016a Range of holdings 1-200 201-1,000 1,001-10,000 10,001-100,000 100,001-1,000,000 Over 1,000,000b Totals Number of ADS holders 52,478 23,687 12,532 618 8 1 89,324 Percentage of total ADS holders 58.76 26.52 14.03 0.69 0.00 0.00 Percentage of total ADSs 0.31 1.23 3.55 1.11 0.15 93.65 100.00 100.00 a One ADS represents six 25 cent ordinary shares. b One holder of ADSs represents 1,006,596 underlying shareholders. As at 31 December 2016 there were also 1,376 preference shareholders. Preference shareholders represented 0.43% and ordinary shareholders represented 99.57% of the total issued nominal share capital of the company (excluding shares held in treasury) as at that date. In accordance with DTR 5, we have received notification that as at 31 December 2016 BlackRock, Inc. held 6.39% and The Capital Group Companies, Inc held 3.22% of the voting rights of the issued share capital of the company. As at 16 March 2017 BlackRock, Inc. held 6.14% and The Capital Group Companies, Inc held 2.91% of the voting rights of the issued share capital of the company. Under the US Securities Exchange Act of 1934 BP has received notification of the following interests as at 16 March 2017: Holder JPMorgan Chase Bank N.A., depositary for ADSs, through its nominee Guaranty Nominees Limited BlackRock, Inc. Percentage of ordinary share capital excluding shares held in treasury Holding of ordinary shares 5,539,010,217 1,201,121,362 28.32 6.14 The company’s major shareholders do not have different voting rights. The company has also been notified of the following interests in preference shares as at 16 March 2017: Holder The National Farmers Union Mutual Insurance Society M&G Investment Management Ltd. Hargreaves Lansdown Asset Management Ltd. Holder The National Farmers Union Mutual Insurance Society M&G Investment Management Ltd. Barclays Wealth Bank J. Safra Sarasin Holding of 8% cumulative first preference shares Percentage of class 945,000 528,150 13.07 7.30 489,641 6.77 Holding of 9% cumulative second preference shares Percentage of class 987,000 644,450 317,546 294,000 18.03 11.77 5.80 5.37 In accordance with DTR 5, Smith and Williamson Holdings Limited notified the company that it disposed of its interest in 32,500 8% cumulative first preference shares and BlackRock, Inc. notified the company that its indirect interest in ordinary shares decreased below 5%, during 2014 respectively. UBS Investment Bank notified the company that its indirect interest in ordinary shares increased above 3% on 9 February 2015 and that it decreased below the notifiable threshold on 16 February 2015. UBS Investment Bank notified the company that its indirect interest in ordinary shares increased above 3% on 7 May 2015 and that it decreased below the notifiable threshold on 11 May 2015. The Capital Group of Companies, Inc. notified the company that its indirect interest in ordinary shares decreased below the notifiable threshold on 21 July 2015. UBS Investment Bank notified the company that its indirect interest in ordinary shares increased above 3% on 4 November 2015 and that it decreased below the notifiable threshold on 9 November 2015. BlackRock, Inc. notified the company that its indirect interest in ordinary shares remained above the previously disclosed threshold of 5%, on 26 November 2015, that it decreased below 5% on 4 February 2016 and that it increased above 5% on 15 February 2016. During 2016 and 2017, BlackRock, Inc. notified the company that its indirect interest in ordinary shares moved as follows: decreased below the previously disclosed threshold of 5% on 28 April 2016; increased above 5% on 9 May 2016; decreased below 5% on 29 July 2016; increased above 5% on 8 August 2016; decreased below 5% on 4 November 2016; increased above 5% on 14 November 2016; decreased below 5% on 9 February 2017; and increased above 5% on 22 February 2017. BP Annual Report and Form 20-F 2016 275 S h a r e h o d e r l i n f o r m a t i o n As at 16 March 2017, the total preference shares in issue comprised only 0.43% of the company’s total issued nominal share capital (excluding shares held in treasury), the rest being ordinary shares. Annual general meeting The 2017 AGM will be held on Wednesday 17 May 2017 at 11.30am at ExCeL London, One Western Gateway, Royal Victoria Dock, London, E16 1XL. A separate notice convening the meeting is distributed to shareholders, which includes an explanation of the items of business to be considered at the meeting. All resolutions for which notice has been given will be decided on a poll. Ernst & Young LLP have expressed their willingness to continue in office as auditors and a resolution for their reappointment is included in the Notice of BP Annual General Meeting 2017. BP intends to propose to shareholders at its 2018 AGM, that Deloitte LLP be appointed as the company’s auditor for the financial year 2018. Memorandum and Articles of Association The following summarizes certain provisions of the company’s Memorandum and Articles of Association and applicable English law. This summary is qualified in its entirety by reference to the UK Companies Act 2006 (the Act) and the company’s Memorandum and Articles of Association. For information on where investors can obtain copies of the Memorandum and Articles of Association see Documents on display on page 279. The company’s Articles of Association may be amended by a special resolution at a general meeting of the shareholders. At the annual general meeting (AGM) held on 17 April 2008 shareholders voted to adopt new Articles of Association, largely to take account of changes in UK company law brought about by the Act. Further amendments to the Articles of Association were approved by shareholders at the AGM held on 15 April 2010. At the AGM held on 16 April 2015 shareholders voted to adopt new Articles of Association to reflect developments in practice and to provide clarification and additional flexibility. Objects and purposes BP is a public company limited by shares, incorporated under the name BP p.l.c. and is registered in England and Wales with the registered number 102498. The provisions regulating the operations of the company, known as its ‘objects’, were historically stated in a company’s memorandum. The Act abolished the need to have object provisions and so at the AGM held on 15 April 2010 shareholders approved the removal of its objects clause together with all other provisions of its Memorandum that, by virtue of the Act, are treated as forming part of the company’s Articles of Association. Directors The business and affairs of BP shall be managed by the directors. The company’s Articles of Association provide that directors may be appointed by the existing directors or by the shareholders in a general meeting. Any person appointed by the directors will hold office only until the next general meeting, notice of which is first given after their appointment and will then be eligible for re-election by the shareholders. A director may be removed by BP as provided for by applicable law and shall vacate office in certain circumstances as set out in the Articles of Association. In addition, the company may by special resolution remove a director before the expiration of his/her period of office and, subject to the Articles of Association, may by ordinary resolution appoint another person to be a director instead. There is no requirement for a director to retire on reaching any age. The Articles of Association place a general prohibition on a director voting in respect of any contract or arrangement in which the director has a material interest other than by virtue of such director’s interest in shares in the company. However, in the absence of some other material interest not indicated below, a director is entitled to vote and to be counted in a quorum for the purpose of any vote relating to a resolution concerning the following matters: • The giving of security or indemnity with respect to any money lent or obligation taken by the director at the request or benefit of the company or any of its subsidiaries. 276 BP Annual Report and Form 20-F 2016 • Any proposal in which the director is interested, concerning the underwriting of company securities or debentures or the giving of any security to a third party for a debt or obligation of the company or any of its subsidiaries. • Any proposal concerning any other company in which the director is interested, directly or indirectly (whether as an officer or shareholder or otherwise) provided that the director and persons connected with such director are not the holder or holders of 1% or more of the voting interest in the shares of such company. • Any proposal concerning the purchase or maintenance of any insurance policy under which the director may benefit. • Any proposal concerning the giving to the director of any other indemnity which is on substantially the same terms as indemnities given or to be given to all of the other directors or to the funding by the company of his expenditure on defending proceedings or the doing by the company of anything to enable the director to avoid incurring such expenditure where all other directors have been given or are to be given substantially the same arrangements. • Any proposal concerning an arrangement for the benefit of the employees and directors or former employees and former directors of the company or any of its subsidiary undertakings, including but without being limited to a retirement benefits scheme and an employees’ share scheme, which does not accord to any director any privilege or advantage not generally accorded to the employees or former employees to whom the arrangement relates. The Act requires a director of a company who is in any way interested in a contract or proposed contract with the company to declare the nature of the director’s interest at a meeting of the directors of the company. The definition of ‘interest’ includes the interests of spouses, children, companies and trusts. The Act also requires that a director must avoid a situation where a director has, or could have, a direct or indirect interest that conflicts, or possibly may conflict, with the company’s interests. The Act allows directors of public companies to authorize such conflicts where appropriate, if a company’s Articles of Association so permit. BP’s Articles of Association permit the authorization of such conflicts. The directors may exercise all the powers of the company to borrow money, except that the amount remaining undischarged of all moneys borrowed by the company shall not, without approval of the shareholders, exceed two times the amount paid up on the share capital plus the aggregate of the amount of the capital and revenue reserves of the company. Variation of the borrowing power of the board may only be affected by amending the Articles of Association. Remuneration of non-executive directors shall be determined in the aggregate by resolution of the shareholders. Remuneration of executive directors is determined by the remuneration committee. This committee is made up of non-executive directors only. There is no requirement of share ownership for a director’s qualification. Dividend rights; other rights to share in company profits; capital calls If recommended by the directors of BP, BP shareholders may, by resolution, declare dividends but no such dividend may be declared in excess of the amount recommended by the directors. The directors may also pay interim dividends without obtaining shareholder approval. No dividend may be paid other than out of profits available for distribution, as determined under IFRS and the Act. Dividends on ordinary shares are payable only after payment of dividends on BP preference shares. Any dividend unclaimed after a period of 12 years from the date of declaration of such dividend shall be forfeited and reverts to BP. If the company exercises its right to forfeit shares and sells shares belonging to an untraced shareholder then any dividends or other monies unclaimed in respect of those shares will be forfeited after a period of two years. The directors have the power to declare and pay dividends in any currency provided that a sterling equivalent is announced. It is not the company’s intention to change its current policy of paying dividends in US dollars. At the company’s AGM held on 15 April 2010, shareholders approved the introduction of a Scrip Dividend Programme (Scrip Programme) and to include provisions in the Articles of Association to enable the company to operate the Scrip Programme. The Scrip Programme was renewed at the company’s AGM held on 16 April 2015 for a further three years. The Scrip Programme enables ordinary shareholders and BP ADS holders to elect to receive new fully paid ordinary shares (or BP ADSs in the case of BP ADS holders) instead of cash. The operation of the Scrip Programme is always subject to the directors’ decision to make the scrip offer available in respect of any particular dividend. Should the directors decide not to offer the scrip in respect of any particular dividend, cash will automatically be paid instead. Apart from shareholders’ rights to share in BP’s profits by dividend (if any is declared or announced), the Articles of Association provide that the directors may set aside: • A special reserve fund out of the balance of profits each year to make up any deficit of cumulative dividend on the BP preference shares. • A general reserve out of the balance of profits each year, which shall be applicable for any purpose to which the profits of the company may properly be applied. This may include capitalization of such sum, pursuant to an ordinary shareholders’ resolution, and distribution to shareholders as if it were distributed by way of a dividend on the ordinary shares or in paying up in full unissued ordinary shares for allotment and distribution as bonus shares. Any such sums so deposited may be distributed in accordance with the manner of distribution of dividends as described above. Holders of shares are not subject to calls on capital by the company, provided that the amounts required to be paid on issue have been paid off. All shares are fully paid. Voting rights The Articles of Association of the company provide that voting on resolutions at a shareholders’ meeting will be decided on a poll other than resolutions of a procedural nature, which may be decided on a show of hands. If voting is on a poll, every shareholder who is present in person or by proxy has one vote for every ordinary share held and two votes for every £5 in nominal amount of BP preference shares held. If voting is on a show of hands, each shareholder who is present at the meeting in person or whose duly appointed proxy is present in person will have one vote, regardless of the number of shares held, unless a poll is requested. Shareholders do not have cumulative voting rights. For the purposes of determining which persons are entitled to attend or vote at a shareholders’ meeting and how many votes such persons may cast, the company may specify in the notice of the meeting a time, not more than 48 hours before the time of the meeting, by which a person who holds shares in registered form must be entered on the company’s register of members in order to have the right to attend or vote at the meeting or to appoint a proxy to do so. Holders on record of ordinary shares may appoint a proxy, including a beneficial owner of those shares, to attend, speak and vote on their behalf at any shareholders’ meeting, provided that a duly completed proxy form is received not less than 48 hours (or such shorter time as the directors may determine) before the time of the meeting or adjourned meeting or, where the poll is to be taken after the date of the meeting, not less than 24 hours (or such shorter time as the directors may determine) before the time of the poll. Record holders of BP ADSs are also entitled to attend, speak and vote at any shareholders’ meeting of BP by the appointment by the approved depositary, JPMorgan Chase Bank N.A., of them as proxies in respect of the ordinary shares represented by their ADSs. Each such proxy may also appoint a proxy. Alternatively, holders of BP ADSs are entitled to vote by supplying their voting instructions to the depositary, who will vote the ordinary shares represented by their ADSs in accordance with their instructions. Proxies may be delivered electronically. Corporations who are members of the company may appoint one or more persons to act as their representative or representatives at any shareholders’ meeting provided that the company may require a corporate representative to produce a certified copy of the resolution appointing them before they are permitted to exercise their powers. Matters are transacted at shareholders’ meetings by the proposing and passing of resolutions, of which there are two types: ordinary or special. An ordinary resolution requires the affirmative vote of a majority of the votes of those persons voting at a meeting at which there is a quorum. A special resolution requires the affirmative vote of not less than three quarters of the persons voting at a meeting at which there is a quorum. Any AGM requires 21 clear days’ notice. The notice period for any other general meeting is 14 clear days subject to the company obtaining annual shareholder approval, failing which, a 21 clear day notice period will apply. Liquidation rights; redemption provisions In the event of a liquidation of BP, after payment of all liabilities and applicable deductions under UK laws and subject to the payment of secured creditors, the holders of BP preference shares would be entitled to the sum of (1) the capital paid up on such shares plus, (2) accrued and unpaid dividends and (3) a premium equal to the higher of (a) 10% of the capital paid up on the BP preference shares and (b) the excess of the average market price over par value of such shares on the LSE during the previous six months. The remaining assets (if any) would be divided pro rata among the holders of ordinary shares. Without prejudice to any special rights previously conferred on the holders of any class of shares, BP may issue any share with such preferred, deferred or other special rights, or subject to such restrictions as the shareholders by resolution determine (or, in the absence of any such resolutions, by determination of the directors), and may issue shares that are to be or may be redeemed. Variation of rights The rights attached to any class of shares may be varied with the consent in writing of holders of 75% of the shares of that class or on the adoption of a special resolution passed at a separate meeting of the holders of the shares of that class. At every such separate meeting, all of the provisions of the Articles of Association relating to proceedings at a general meeting apply, except that the quorum with respect to a meeting to change the rights attached to the preference shares is 10% or more of the shares of that class, and the quorum to change the rights attached to the ordinary shares is one third or more of the shares of that class. Shareholders’ meetings and notices Shareholders must provide BP with a postal or electronic address in the UK to be entitled to receive notice of shareholders’ meetings. Holders of BP ADSs are entitled to receive notices under the terms of the deposit agreement relating to BP ADSs. The substance and timing of notices are described above under the heading Voting rights. Under the Act, the AGM of shareholders must be held once every year, within each six month period beginning with the day following the company’s accounting reference date. All general meetings shall be held at a time and place (in England) determined by the directors. If any shareholders’ meeting is adjourned for lack of quorum, notice of the time and place of the adjourned meeting may be given in any lawful manner, including electronically. Powers exist for action to be taken either before or at the meeting by authorized officers to ensure its orderly conduct and safety of those attending. Limitations on voting and shareholding There are no limitations, either under the laws of the UK or under the company’s Articles of Association, restricting the right of non-resident or foreign owners to hold or vote BP ordinary or preference shares in the company other than limitations that would generally apply to all of the shareholders and limitations applicable to certain countries and persons subject to EU economic sanctions or those sanctions adopted by the UK government which implement resolutions of the Security Council of the United Nations. Disclosure of interests in shares The Act permits a public company to give notice to any person whom the company believes to be or, at any time during the three years prior to the issue of the notice, to have been interested in its voting shares requiring them to disclose certain information with respect to those interests. Failure to supply the information required may lead to disenfranchisement of the relevant shares and a prohibition on their BP Annual Report and Form 20-F 2016 277 S h a r e h o d e r l i n f o r m a t i o n transfer and receipt of dividends and other payments in respect of those shares and any new shares in the company issued in respect of those shares. In this context the term ‘interest’ is widely defined and will generally include an interest of any kind whatsoever in voting shares, including any interest of a holder of BP ADSs. Called-up share capital Details of the allotted, called-up and fully-paid share capital at 31 December 2016 are set out in Financial statements – Note 30. At the AGM on 14 April 2016, authorization was given to the directors to allot shares up to an aggregate nominal amount equal to $3,081 million. Authority was also given to the directors to allot shares for cash and to dispose of treasury shares, other than by way of rights issue, up to a maximum of $462 million, without having to offer such shares to existing shareholders. These authorities were given for the period until the next AGM in 2017 or 14 July 2017, whichever is the earlier. These authorities are renewed annually at the AGM. Purchases of equity securities by the issuer and affiliated purchasers At the AGM on 14 April 2016, authorization was given to the company to repurchase up to 1.8 billion ordinary shares for the period until the next AGM in 2017 or 14 July 2017, being the latest dates by which an AGM must be held for that year. This authorization is renewed annually at the AGM. No ordinary shares were repurchased by the company during 2016. The following table provides details of ordinary share purchases made by the Employee Share Ownership Plans (ESOPs) and other purchases of ordinary shares and ADSs made to satisfy the requirements of certain employee share-based payment plans. 2016 January 10 – January 11 May 3 September 7 November 7 – November 16 December 19 2017 January 3 – January 31 February 7 March 1 – March 16 Number of shares purchased by ESOPs or for certain employee share-based plansa Average price paid per share $ 1,190,000 1,650,000 1,480,908 30,412 5,280,000 Nil 250,000 Nil 5.08 5.65 5.82 5.63 6.09 5.80 a All share purchases were of ordinary shares of 25 cents each and/or ADSs (each representing six ordinary shares) and were on/open market transactions. Fees and charges payable by ADSs holders The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of the distributable property to pay the fees. The charges of the Depositary payable by investors are as follows: Type of service Depositing or substituting the underlying shares Selling or exercising rights Withdrawing an underlying share Expenses of the Depositary Dividend fees Global Invest Direct (“GID”) Plan Depositary actions Issuance of ADSs against the deposit of shares, including deposits and issuances in respect of: • Share distributions, stock splits, rights, merger. • Exchange of securities or other transactions or event or other distribution affecting the ADSs or deposited securities. Distribution or sale of securities, the fee being an amount equal to the fee for the execution and delivery of ADSs that would have been charged as a result of the deposit of such securities. Acceptance of ADSs surrendered for withdrawal of deposited securities. Expenses incurred on behalf of holders in connection with: • Stock transfer or other taxes and governmental charges. • Delivery by cable, telex, electronic and facsimile transmission. • Transfer or registration fees, if applicable, for the registration of transfers of underlying shares. • Expenses of the Depositary in connection with the conversion of foreign currency into US dollars (which are paid out of such foreign currency). ADS holders who receive a cash dividend are charged a fee which BP uses to offset the costs associated with administering the ADS programme. New investors and existing ADS holders can buy or sell BP ADSs by enrolling in BP’s GID Plan, sponsored and administered by the Depositary. Fee $5.00 per 100 ADSs (or portion thereof) evidenced by the new ADSs delivered. $5.00 per 100 ADSs (or portion thereof). $5.00 for each 100 ADSs (or portion thereof) evidenced by the ADSs surrendered. Expenses payable are subject to agreement between the company and the Depositary by billing holders or by deducting charges from one or more cash dividends or other cash distributions. $0.005 per BP ADS per quarter per cash distribution. Cost per transaction is $2.00 for recurring, $2.00 for one-time automatic investments, and $5.00 for investment made by check, plus $0.12 commission per share. 278 BP Annual Report and Form 20-F 2016 Fees and payments made by the Depositary to the issuer The Depositary has agreed to reimburse certain company expenses related to the company’s ADS programme and incurred by the company in connection with the ADS programme arising during the year ended 31 December 2016. The Depositary reimbursed to the company, or paid amounts on the company’s behalf to third parties, or waived its fees and expenses, of $15,621,791.96 for the year ended 31 December 2016. The table below sets out the types of expenses that the Depositary has agreed to reimburse and the fees it has agreed to waive for standard costs associated with the administration of the ADS programme relating to the year ended 31 December 2016. Category of expense reimbursed, waived or paid directly to third parties Fees for delivery and surrender of BP ADSs Dividend feesa Total Amount reimbursed, waived or paid directly to third parties for the year ended 31 December 2016 $ 874,061.17 14,747,730.79 15,621,791.96 a Dividend fees are charged to ADS holders who receive a cash distribution, which BP uses to offset the costs associated with administering the ADS programme. Under certain circumstances, including removal of the Depositary or termination of the ADR programme by the company, the company is required to repay the Depositary certain amounts reimbursed and/or expenses paid to or on behalf of the company during the 12-month period prior to notice of removal or termination. Documents on display BP Annual Report and Form 20-F 2016 is available online at bp.com/annualreport. To obtain a hard copy of BP’s complete audited financial statements, free of charge, UK based shareholders should contact BP Distribution Services by calling +44 (0)870 241 3269 or by emailing bpdistributionservices@bp.com. If based in the US or Canada shareholders should contact Issuer Direct by calling +1 888 301 2505 or by emailing bpreports@issuerdirect.com. The company is subject to the information requirements of the US Securities Exchange Act of 1934 applicable to foreign private issuers. In accordance with these requirements, the company files its Annual Report and Form 20-F and other related documents with the SEC. It is possible to read and copy documents that have been filed with the SEC at its headquarters located at 100 F Street, NE, Washington, DC 20549, US. You may also call the SEC at +1 800-SEC-0330. In addition, BP’s SEC filings are available to the public at the SEC’s website. BP discloses in this report (see Corporate governance practices (Form 20-F Item 16G) on page 266) significant ways (if any) in which its corporate governance practices differ from those mandated for US companies under NYSE listing standards. Shareholding administration If you have any queries about the administration of shareholdings, such as change of address, change of ownership, dividend payments, the Scrip Programme or to change the way you receive your company documents (such as the BP Annual Report and Form 20-F and Notice of BP Annual General Meeting) please contact the BP Registrar or the BP ADS Depositary. Ordinary and preference shareholders The BP Registrar, Capita Asset Services The Registry, 34 Beckenham Road Beckenham, Kent BR3 4TU, UK Freephone in UK 0800 701107 From outside the UK +44 (0)20 3170 3678 Fax +44 (0)1484 601512 ADS holders The BP ADS Depositary, JPMorgan Chase Bank, N.A. PO Box 64504, St Paul, MN 55164-0504, US Toll-free in US and Canada +1 877 638 5672 From outside the US and Canada +1 651 306 4383 Exhibits The following documents are filed in the Securities and Exchange Commission (SEC) EDGAR system, as part of this Annual Report on Form 20-F, and can be viewed on the SEC’s website. Exhibit 1 Exhibit 4.1 Exhibit 4.2 Exhibit 4.3 Exhibit 4.4 Exhibit 4.7 Exhibit 4.10 Exhibit 7 Exhibit 8 Exhibit 11 Exhibit 12 Exhibit 13 Exhibit 15.1 Exhibit 15.2 Exhibit 15.3 Exhibit 15.4 Exhibit 15.5 Memorandum and Articles of Association of BP p.l.c.*******† The BP Executive Directors’ Incentive Plan******† Amended BP Deferred Annual Bonus Plan 2005****† Amended Director’s Secondment Agreement for R W Dudley*****† Amended Director’s Service Contract and Secondment Agreement for R W Dudley**† Director’s Service Contract for Dr B Gilvary***† The BP Share Award Plan 2015*******† Computation of Ratio of Earnings to Fixed Charges (Unaudited)† Subsidiaries (included as Note 36 to the Financial Statements) Code of Ethics*† Rule 13a – 14(a) Certifications† Rule 13a – 14(b) Certifications#† Consent of DeGolyer and MacNaughton† Report of DeGolyer and MacNaughton† Administrative Agreement dated as of 13 March 2014 among the US Environmental Protection Agency, BP p.l.c., and other BP subsidiaries******† Consent Decree*******† Gulf states Settlement Agreement*******† * Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 31 December 2009. ** Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 31 December 2010. *** Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 31 December 2011. **** Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 31 December 2012. ***** Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 31 December 2013. ****** Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 31 December 2014. ******* Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 31 December 2015. # Furnished only. † Included only in the annual report filed in the Securities and Exchange Commission EDGAR system. The total amount of long-term securities of the Registrant and its subsidiaries authorized under any one instrument does not exceed 10% of the total assets of BP p.l.c. and its subsidiaries on a consolidated basis. The company agrees to furnish copies of any or all such instruments to the SEC on request. S h a r e h o d e r l i n f o r m a t i o n BP Annual Report and Form 20-F 2016 279 Glossary Abbreviations ADR American depositary receipt. ADS American depositary share. 1 ADS = 6 ordinary shares. Barrel (bbl) 159 litres, 42 US gallons. bcf/d Billion cubic feet per day. bcfe Billion cubic feet equivalent. bcma Billion cubic metres per annum. b/d Barrels per day. boe/d Barrels of oil equivalent per day. DoJ US Department of Justice. GAAP Generally accepted accounting practice. Gas Natural gas. GHG Greenhouse gas. GWh Gigawatt hour. HSSE Health, safety, security and environment. IFRS International Financial Reporting Standards. KPIs Key performance indicators. LNG Liquefied natural gas. LPG Liquefied petroleum gas. mb/d Thousand barrels per day. mboe/d Thousand barrels of oil equivalent per day. mmb/d Million barrels per day. mmboe/d Million barrels of oil equivalent per day. mmBtu Million British thermal units. mmcf/d Million cubic feet per day. mmte Million tonnes. MW Megawatt. MteCO2 Million tonnes of CO2 equivalent. NGLs Natural gas liquids. PSA Production-sharing agreement. 280 BP Annual Report and Form 20-F 2016 PTA Purified terephthalic acid. RC Replacement cost. SEC The United States Securities and Exchange Commission. Definitions Unless the context indicates otherwise, the definitions for the following glossary terms are given below. Adjusted effective tax rate (ETR) Non-GAAP measure. The adjusted ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis excluding the impact of reductions in the rate of the UK North Sea supplementary charge (in 2016 and 2015) by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects. Information on underlying RC profit or loss is provided below. BP believes it is helpful to disclose the adjusted ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period, and a reconciliation to GAAP information is provided on page 285. Associate An entity over which the group has significant influence and that is neither a subsidiary nor a joint arrangement of the group. Significant influence is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies. Brent A trading classification for North Sea crude oil that serves as a major benchmark price for purchases of oil worldwide. Capital expenditure on an accruals basis Non-GAAP measure. It comprises additions to property, plant and equipment, intangible assets and investments in joint ventures and associates, and reflects consideration payable in business combinations. It does not include additions arising from asset exchanges and certain other non-cash items. The nearest equivalent measure on an IFRS basis for the group is Additions to non-current assets. BP believes that Capital expenditure on an accruals basis provides useful information for investors as it is the measure used by management to plan and prioritize the group’s investment of its resources and allows investors to understand how the group balances funds between shareholder distributions and investment for the future. Further information and a reconciliation to GAAP information is provided on page 285. Cash costs Non-GAAP measure. Cash costs are a subset of production and manufacturing expenses plus distribution and administration expenses and excludes costs that are classified as non-operating items. They represent the substantial majority of the remaining expenses in these line items but exclude certain costs that are variable, primarily with volumes (such as freight costs). Management believes that the presentation of cash costs is a performance measure that provides investors with useful information regarding the company’s financial condition because it considers these expenses to be the principal operating and overhead expenses that are most directly under their control although they also include certain foreign exchange and commodity price effects. A reconciliation to GAAP information is provided on page 285. Consolidation adjustment – UPII Unrealized profit in inventory arising on inter-segment transactions. Commodity trading contracts BP’s Upstream and Downstream segments both participate in regional and global commodity trading markets in order to manage, transact and hedge the crude oil, refined products and natural gas that the group either produces or consumes in its manufacturing operations. These physical trading activities, together with associated incremental trading opportunities, are discussed in Upstream on page 24 and in Downstream on page 30. The range of contracts the group enters into in its commodity trading operations is described below. Using these contracts, in combination with rights to access storage and transportation capacity, allows the group to access advantageous pricing differences between locations, time periods and arbitrage between markets. Exchange-traded commodity derivatives Contracts that are typically in the form of futures and options traded on a recognized exchange, such as Nymex and ICE. Such contracts are traded in standard specifications for the main marker crude oils, such as Brent and West Texas Intermediate; the main product grades, such as gasoline and gasoil; and for natural gas and power. Gains and losses, otherwise referred to as variation margin, are generally settled on a daily basis with the relevant exchange. These contracts are used for the trading and risk management of crude oil, refined products, and natural gas and power. Realized and unrealized gains and losses on exchange-traded commodity derivatives are included in sales and other operating revenues for accounting purposes. Over-the-counter contracts Contracts that are typically in the form of forwards, swaps and options. Some of these contracts are traded bilaterally between counterparties or through brokers, others may be cleared by a central clearing counterparty. These contracts can be used both for trading and risk management activities. Realized and unrealized gains and losses on over-the-counter (OTC) contracts are included in sales and other operating revenues for accounting purposes. Many grades of crude oil bought and sold use standard contracts including US domestic light sweet crude oil, commonly referred to as West Texas Intermediate, and a standard North Sea crude blend – Brent, Forties, Oseberg and Ekofisk (BFOE). Forward contracts are used in connection with the purchase of crude oil supplies for refineries, products for marketing and sales of the group’s oil production and refined products. The contracts typically contain standard delivery and settlement terms. These transactions call for physical delivery of oil with consequent operational and price risk. However, various means exist and are used from time to time, to settle obligations under the contracts in cash rather than through physical delivery. Because the physically settled transactions are delivered by cargo, the BFOE contract additionally specifies a standard volume and tolerance. Gas and power OTC markets are highly developed in North America and the UK, where commodities can be bought and sold for delivery in future periods. These contracts are negotiated between two parties to purchase and sell gas and power at a specified price, with delivery and settlement at a future date. Typically, the contracts specify delivery terms for the underlying commodity. Some of these transactions are not settled physically as they can be achieved by transacting offsetting sale or purchase contracts for the same location and delivery period that are offset during the scheduling of delivery or dispatch. The contracts contain standard terms such as delivery point, pricing mechanism, settlement terms and specification of the commodity. Typically, volume, price and term (e.g. daily, monthly and balance of month) are the main variable contract terms. Swaps are often contractual obligations to exchange cash flows between two parties. A typical swap transaction usually references a floating price and a fixed price with the net difference of the cash flows being settled. Options give the holder the right, but not the obligation, to buy or sell crude, oil products, natural gas or power at a specified price on or before a specific future date. Amounts under these derivative financial instruments are settled at expiry. Typically, netting agreements are used to limit credit exposure and support liquidity. Spot and term contracts Spot contracts are contracts to purchase or sell a commodity at the market price prevailing on or around the delivery date when title to the inventory is taken. Term contracts are contracts to purchase or sell a commodity at regular intervals over an agreed term. Though spot and term contracts may have a standard form, there is no offsetting mechanism in place. These transactions result in physical delivery with operational and price risk. Spot and term contracts typically relate to purchases of crude for a refinery, products for marketing, or third- party natural gas, or sales of the group’s oil production, oil products or gas production to third parties. For accounting purposes, spot and term sales are included in sales and other operating revenues when title passes. Similarly, spot and term purchases are included in purchases for accounting purposes. Dividend yield Sum of the four quarterly dividends announced in respect of the year as a percentage of the year-end share price on the respective exchange. Effective tax rate (ETR) on replacement cost (RC) profit or loss Non-GAAP measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Information on RC profit or loss is provided below. BP believes it is helpful to disclose the ETR on RC profit or loss because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period, and a reconciliation to GAAP information is provided on page 285. Fair value accounting effects Non-GAAP adjustments to IFRS profit or loss. We use derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity. BP enters into physical commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of BP’s gas production. Under IFRS these contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. In addition, derivative instruments are used to manage the price risk associated with certain future natural gas sales. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into. IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences. BP enters into contracts for pipelines and storage capacity, oil and gas processing and liquefied natural gas (LNG) that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses. The way BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. Under management’s internal measure of performance the inventory and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period. The fair values of certain derivative instruments used to risk manage certain LNG and oil and gas contracts and gas sales contracts, are deferred to match with the underlying exposure and the commodity contracts for business requirements are accounted for on an accruals basis. We BP Annual Report and Form 20-F 2016 281 S h a r e h o d e r l i n f o r m a t i o n believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole. Free cash flow Operating cash flow less net cash used in investing activities, as presented in the group cash flow statement. Gearing See Net debt and net debt ratio definition. Henry Hub A distribution hub on the natural gas pipeline system in Erath, Louisiana, that lends its name to the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange and the over-the-counter swaps traded on Intercontinental Exchange. Hydrocarbons Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels. Inorganic capital expenditure A subset of Capital expenditure on an accruals basis and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on an accruals basis. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in projects which expand the group’s activities through acquisition. A reconciliation of capital expenditure on an accruals basis to GAAP information is provided on page 285. See also page 240. Inventory holding gains and losses The difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. See Replacement cost (RC) profit or loss definition below. Joint arrangement An arrangement in which two or more parties have joint control. Joint control Contractually agreed sharing of control over an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Joint operation A joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. Joint venture A joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Liquids Comprises crude oil, condensate and natural gas liquids. For the Upstream segment, it also includes bitumen. LNG train An LNG train is a processing facility used to liquefy and purify natural gas in the formation of LNG. Net cash margin per barrel Net cash margin is defined by Solomon Associates as the net margin achieved after subtracting cash operating expenses and adding any refinery revenue from other sources. Net cash margin is expressed in US dollars per barrel of net refinery input. Net debt and net debt ratio (gearing) Non-GAAP measures. Net debt is calculated as gross finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. The net debt ratio is defined as the ratio of net debt to the total of net debt plus total shareholders’ equity. All components of equity are included in the denominator of the calculation. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. See Financial statements – Note 26 for information on gross debt, which is the nearest equivalent measure to net debt on an IFRS basis. We are unable to present reconciliations of forward-looking information for net debt ratio to gross debt ratio, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in a GAAP estimate. Net income per barrel Non-GAAP measure. Net income per barrel is calculated by taking underlying replacement cost profit before interest and tax for the Downstream segment, deducting tax at an assumed 28% effective tax rate and dividing the result by the group’s total refining capacity. BP uses this measure to assess performance relative to peer companies. Net generating capacity The sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP’s share of equity- accounted entities. The gross data is the equivalent capacity on a gross-joint venture basis, which includes 100% of the capacity of equity-accounted entities where BP has partial ownership. Non-operating items Charges and credits are included in the financial statements that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by segment and type is shown on page 240. Operating cash flow Net cash provided by (used in) operating activities as stated in the group cash flow statement. When used in the context of a segment rather than the group, the terms refer to the segment’s share thereof. Operating cash flow excluding amounts related to the Gulf of Mexico oil spill Non-GAAP measure. It is calculated by excluding post-tax operating cash flows relating to the Gulf of Mexico oil spill as reported in Financial statements – Note 2 from net cash provided by operating activities as reported in the group cash flow statement. BP believes it is helpful to disclose net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill because this measure allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is net cash provided by operating activities. Major projects Have a BP net investment of at least $250 million, or are considered to be of strategic importance to BP or of a high degree of complexity. Operating cash margin Operating cash margin is operating cash flow divided by the applicable number of barrels of oil equivalent produced. 282 BP Annual Report and Form 20-F 2016 Operating management system (OMS) BP’s OMS helps us manage risks in our operating activities by setting out BP’s principles for good operating practice. It brings together BP requirements on health, safety, security, the environment, social responsibility and operational reliability, as well as related issues, such as maintenance, contractor relations and organizational learning, into a common management system. Organic capital expenditure A subset of Capital expenditure on an accruals basis and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure on an accruals basis less inorganic capital expenditure. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in developing and maintaining the group’s assets. An analysis of additions to non-current assets by segment, and a reconciliation of capital expenditure on an accruals basis to GAAP information is provided on page 285. See also page 240. We are unable to present reconciliations of forward-looking information for organic capital expenditure to additions to non-current assets, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include changes in decommissioning assets and asset exchanges, that are difficult to predict in advance in order to include in a GAAP estimate. Plant reliability Plant reliability is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns and weather. Production-sharing agreement (PSA) An arrangement through which an oil company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery. Realizations Realizations are the result of dividing revenue generated from hydrocarbon sales, excluding revenue generated from purchases made for resale and royalty volumes, by revenue generating hydrocarbon production volumes. Revenue generating hydrocarbon production reflects the BP share of production as adjusted for any production which does not generate revenue. Adjustments may include losses due to shrinkage, amounts consumed during processing, and contractual or regulatory host committed volumes such as royalties. For the Upstream segment, realizations include transfers between businesses. Refining availability Represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime. Refining marker margin (RMM) The average of regional indicator margins weighted for BP’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by BP in any period because of BP’s particular refinery configurations and crude and product slate. Replacement cost (RC) profit or loss Reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS. RC profit or loss for the group is a non-GAAP measure. Management believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP’s management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to BP shareholders. See Financial statements – Note 5, and a reconciliation to GAAP information is provided on page 240. RC profit or loss per share Non-GAAP measure. Earnings per share is defined in Financial statements – Note 10. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders, and a reconciliation to GAAP information is provided on page 285. Reserves replacement ratio The extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery, and extensions and discoveries. Return on average capital employed Non-GAAP measure. Return on average capital employed (ROACE) is underlying replacement cost profit, after adding back non-controlling interest and interest expense net of notional tax at an assumed 35%, divided by average capital employed, excluding cash and cash equivalents and goodwill. BP believes it is helpful to disclose the ROACE because this measure gives an indication of the company’s capital efficiency. The nearest GAAP measures of the numerator and denominator are profit or loss for the period attributable to BP shareholders and average capital employed respectively. The reconciliation of the numerator and denominator is provided on page 285. We are unable to present forward-looking information of the nearest GAAP measures of the numerator and denominator for ROACE, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to calculate a meaningful comparable GAAP forward-looking financial measure. These items include inventory holding gains or losses and interest net of tax, that are difficult to predict in advance in order to include in a GAAP estimate. Subsidiary An entity that is controlled by the BP group. Control of an investee exists when an investor is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Tier 1 process safety events Losses of primary containment from a process of greatest consequence – causing harm to a member of the workforce or costly damage to equipment or exceeding defined quantities. Tight oil and gas Natural oil and gas reservoirs locked in hard sandstone rocks with low permeability, making the underground formation extremely tight. UK National Balancing Point A virtual trading location for sale, purchase and exchange of UK natural gas. It is the pricing and delivery point for the Intercontinental Exchange natural gas futures contract. Unconventionals Resources found in geographic accumulations over a large area, that usually present additional challenges to development such as low permeability or high viscosity. Examples include shale gas and oil, coalbed methane, gas hydrates and natural bitumen deposits. These typically require specialized extraction technology such as hydraulic fracturing or steam injection. Underlying production Production after adjusting for divestments and entitlement impacts in our production-sharing agreements. 2017 underlying production does not include the Abu Dhabi onshore concession renewal. BP Annual Report and Form 20-F 2016 283 S h a r e h o d e r l i n f o r m a t i o n Underlying RC profit or loss Non-GAAP measure. RC profit or loss after adjusting for non-operating items and fair value accounting effects. See pages 240 and 285 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. BP believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate BP’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, year on year, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss for the year attributable to BP shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. A reconciliation to GAAP information is provided on page 240. Underlying RC profit or loss per share Non-GAAP measure. Earnings per share is defined Financial statements – Note 10. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders and a reconciliation to GAAP information is provided on page 285. Trade marks Trade marks of the BP group appear throughout this report. They include: ACTIVE Aral ARCO BP Castrol DUALOCK EDGE GTX MAGNATEC PTAir Albert Heijn to go is a registered trade mark of Albert Heijn. Fulcrum BioEnergy is a registered trade mark of Fulcrum BioEnergy, Inc. M&S Simply Food is a registered trade mark of Marks & Spencer plc. REWE to go is a registered trade mark of REWE. RocketRoute is a registered trade mark of RocketRoute Limited. Pick n Pay is a registered trade mark of Pick n Pay Stores Limited. 284 BP Annual Report and Form 20-F 2016 Non-GAAP measures reconciliations Non-GAAP information on fair value accounting effects The impacts of fair value accounting effects, relative to management’s internal measure of performance, and a reconciliation to GAAP information is set out below. Further information on fair value accounting effects is provided on page 280. Upstream Unrecognized (gains) losses brought forward from previous perioda Favourable (unfavourable) impact relative to management’s measure of performance Exchange translation gains (losses) on fair value accounting effects Unrecognized (gains) losses carried forward Downstreamb Unrecognized (gains) losses brought forward from previous perioda Favourable (unfavourable) impact relative to management’s measure of performance Unrecognized (gains) losses carried forward Favourable (unfavourable) impact relative to management’s measure of performance – by region Upstream US Non-US Downstreamb US Non-US Taxation credit (charge) 2016 263 (637) (19) (393) 377 (448) (71) (379) (258) (637) (321) (127) (448) (1,085) 329 (756) 2015 191 105 – 296 188 156 344 (66) 171 105 102 54 156 261 (56) 205 $ million 2014 160 31 – 191 (679) 867 188 23 8 31 914 (47) 867 898 (341) 557 a 2016 brought forward fair value accounting effect balances include a $33-million adjustment between Upstream and Downstream as part of the transfer of certain emission trading balances between these segments. b Fair value accounting effects arise solely in the fuels business. Reconciliation of non-GAAP information Upstream RC profit (loss) before interest and tax adjusted for fair value accounting effects Impact of fair value accounting effects RC profit (loss) before interest and tax Downstream RC profit before interest and tax adjusted for fair value accounting effects Impact of fair value accounting effects RC profit before interest and tax Total group Profit (loss) before interest and tax adjusted for fair value accounting effects Impact of fair value accounting effects Profit (loss) before interest and tax 2016 2015 1,211 (637) 574 5,610 (448) 5,162 655 (1,085) (430) (1,042) 105 (937) 6,955 156 7,111 (8,179) 261 (7,918) $ million 2014 8,903 31 8,934 2,871 867 3,738 5,514 898 6,412 Reconciliation of production and manufacturing expenses and distribution and administration expenses to cash costs Income statement data Production and manufacturing expenses Distribution and administration expenses Total costs Adjusted for certain non-operating items Gulf of Mexico oil spill Restructuring, integration and rationalization costs Other items Adjusted for certain variable costs Transportation and shipping costs Other variable costs Cash costs 2016 2015 29,077 10,495 39,572 6,640 763 (59) 32,228 8,179 3,892 20,157 37,040 11,553 48,593 11,709 1,088 (121) 35,917 8,945 3,181 23,791 $ million 2014 27,375 12,266 39,641 781 441 19 38,400 8,777 2,445 27,178 S h a r e h o d e r l i n f o r m a t i o n BP Annual Report and Form 20-F 2016 285 Reconciliation of basic earnings per ordinary share to RC profit (loss) per share and to underlying RC profit per share Per ordinary share – cents Profit (loss) for the yeara Inventory holding (gains) losses, before tax Taxation charge (credit) on inventory holding gains and losses RC profit (loss) for the year Net (favourable) unfavourable impact of non-operating items and fair value accounting effects, before tax Taxation charge (credit) on non-operating items and fair value accounting effects Underlying RC profit for the year a Profit attributable to BP shareholders. 2016 0.61 (8.52) 2.58 (5.33) 35.99 (16.87) 13.79 2015 2014 2013 (35.39) 10.31 (3.10) (28.18) 82.23 (21.83) 32.22 20.55 33.78 (10.43) 43.90 44.79 (22.69) 66.00 123.87 1.53 (0.32) 125.08 (48.83) (5.33) 70.92 Reconciliation of additions to non-current assets to capital expenditure on an accruals basis 2012 57.89 3.12 (0.96) 60.05 32.11 (2.45) 89.71 $ million Additions to non-current assetsb Upstream Downstream Rosneft Other businesses and corporate Additions to other investments Element of business combinations not related to non-current assets (Additions to) reductions in decommissioning asset Asset exchangesc 2016 2015 2014 2013 2012 17,879 3,109 – 216 21,204 48 (4) 656 (2,525) 17,635 2,130 – 315 20,080 35 (31) (553) (73) 22,587 3,121 – 784 26,492 160 (366) (2,505) (288) 19,499 4,449 11,941 1,027 36,916 41 39 (384) (5) 22,603 5,246 – 1,419 29,268 33 (72) (4,025) (157) Capital expenditure on an accruals basis 19,379 19,458 23,493 36,607 25,047 b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates. c 2016 principally relates to the contribution of BP’s Norwegian upstream business into Aker BP ASA in exchange for a 30% interest in Aker BP ASA and the dissolution of the group’s German refining joint operation with Rosneft. Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss and adjusted ETR Taxation (charge) credit Taxation on profit or loss for the year Adjusted for taxation on inventory holding gains and losses Taxation on a RC profit or loss basis Adjusted for taxation on non-operating items and fair value accounting effects Adjusted for the impact of the reduction in the rate of the UK North Sea supplementary charge Adjusted taxation Effective tax rate ETR on profit or loss for the year Adjusted for inventory holding gains and losses ETR on RC profit or loss Adjusted for non-operating items and fair value accounting effects Adjusted for the impact of the reduction in the rate of the UK North Sea supplementary charge Adjusted ETR 2016 2,467 (483) 2,950 3,162 434 (646) 2016 107 (31) 76 (69) 16 23 2015 3,171 569 2,602 4,000 915 $ million 2014 2013 2012 (947) 1,917 (2,864) 4,171 (6,463) 60 (6,523) 1,009 (6,880) 183 (7,063) 467 – – – (2,313) (7,035) (7,532) (7,530) 2015 2014 2013 33 1 34 (15) 12 31 19 7 26 10 – 36 21 – 21 14 – 35 % 2012 38 – 38 (8) – 30 286 BP Annual Report and Form 20-F 2016 Return on average capital employed (ROACE) Profit (loss) for the year attributable to BP shareholders Inventory holding (gains) losses, net of tax Non-operating items and fair value accounting effects, net of tax Underlying RC profit Interest expense, net of taxa Non-controlling interests Adjusted underlying RC profit Total equity Gross debt Capital employed (2016 average $153,349 million) Less: Goodwill Cash and cash equivalents 2016 2015 115 (1,114) 3,584 2,585 635 57 (6,482) 1,320 11,067 2014 3,780 4,293 4,063 2013 23,451 230 (10,253) 5,905 12,136 13,428 576 82 546 223 549 307 $ million 2012 11,017 411 5,643 17,071 549 234 3,277 6,563 12,905 14,284 17,854 96,843 58,300 155,143 11,194 23,484 98,387 53,168 151,555 11,627 26,389 112,642 52,854 165,496 11,868 29,763 130,407 48,192 178,599 12,181 22,520 119,752 48,800 168,552 12,190 19,635 120,465 113,539 123,865 143,898 136,727 Average capital employed excluding goodwill and cash and cash equivalents 117,002 118,702 133,882 140,313 133,457 ROACE a Calculated on a post-tax basis using a notional tax rate of 35%. 2.8% 5.5% 9.6% 10.2% 13.4% The Directors’ report on pages 51-79, 111-112, 187-214 and 239-287 was approved by the board and signed on its behalf by David J Jackson, company secretary on 6 April 2017. BP p.l.c. Registered in England and Wales No. 102498 BP Annual Report and Form 20-F 2016 287 S h a r e h o d e r l i n f o r m a t i o n Signatures The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf. BP p.l.c. (Registrant) /s/ David J Jackson Company secretary 6 April 2017 288 BP Annual Report and Form 20-F 2016 Cross reference to Form 20-F A. B. C. D. A. B. C. D. A. B. C. D. E. F. G. A. B. C. D. E. A. B. C. A. B. A. B. C. D. E. F. A. B. C. D. E. F. G. H. I. A. B. C. D. Item 1. Item 2. Item 3. Item 4. Item 4A. Item 5. Item 6. Item 7. Item 8. Item 9. Item 10. Item 11. Item 12. Item 13. Item 14. Item 15. Item 16A. Item 16B. Item 16C. Item 16D. Item 16E. Item 16F. Item 16G. Item 17. Item 18. Item 19. Identity of Directors, Senior Management and Advisors Offer Statistics and Expected Timetable Key Information Selected financial data Capitalization and indebtedness Reasons for the offer and use of proceeds Risk factors Information on the Company History and development of the company Business overview Organizational structure Property, plants and equipment Unresolved Staff Comments Operating and Financial Review and Prospects Operating results Liquidity and capital resources Research and development, patent and licenses Trend information Off-balance sheet arrangements Tabular disclosure of contractual commitments Safe harbor Directors, Senior Management and Employees Directors and senior management Compensation Board practices Employees Share ownership Major Shareholders and Related Party Transactions Major shareholders Related party transactions Interests of experts and counsel Financial Information Consolidated statements and other financial information Significant changes The Offer and Listing Offer and listing details Plan of distribution Markets Selling shareholders Dilution Expenses of the issue Additional Information Share capital Memorandum and articles of association Material contracts Exchange controls Taxation Dividends and paying agents Statements by experts Documents on display Subsidiary information Quantitative and Qualitative Disclosures about Market Risk Description of securities other than equity securities Debt Securities Warrants and Rights Other Securities American Depositary Shares Defaults, Dividend Arrearages and Delinquencies Material Modifications to the Rights of Security Holders and Use of Proceeds Controls and Procedures Audit Committee Financial Expert Code of Ethics Principal Accountant Fees and Services Exemptions from the Listing Standards for Audit Committees Purchases of Equity Securities by the Issuer and Affiliated Purchasers Change in Registrant’s Certifying Accountant Corporate governance Financial Statements Financial Statements Exhibits Page n/a n/a 240-241 n/a n/a 49-50 2-3, 21-39, 136-146, 153-155, 242-243, 257, 276, 291 2-19, 20-47, 53, 130, 142-145, 242, 244-250, 257-261, 269-270 23, 180, 291 23, 29, 38, 150, 164, 212-214, 243-256, 265 None 21-39, 49-50, 123, 125-142, 145, 153-155, 163, 165-168, 168-171, 242, 257-258, 265-266 18, 22, 124-125, 132, 150, 163-168, 211-212, 242-243 12, 22, 42, 145 8-9, 20, 21-23, 26, 31 164-165, 242-243 243 269 52-61, 65 18-19, 80-110, 178 52-57, 62-79, 80-110 46, 179 46, 80-110, 157, 179 275 153-154, 266 n/a 119-186, 242, 261-264, 272-273 146 272 n/a 272 n/a n/a n/a n/a 275-278 265 273 273-275 n/a n/a 279 180 165-171 n/a n/a n/a 278-279 None None 47-48, 120-121, 267 56, 69, 267 267 72, 179, 268 None 278 None 266-267 n/a 119-214 279 S h a r e h o d e r l i n f o r m a t i o n BP Annual Report and Form 20-F 2016 289 Information about this report 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.’ Our agent in the US: BP America Inc. 501 Westlake Park Boulevard Houston, Texas 77079 US Tel +1 281 366 2000 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 2016. A cross reference to Form 20-F requirements is included on page 289. This document contains the Strategic report on the inside front cover and pages 2-50 and the Directors’ report on pages 51-79, 111-112, 187-214 and 239-287. The Strategic report and the Directors’ report together include the management report required by DTR 4.1 of the UK Financial Conduct Authority’s Disclosure Guidance and Transparency Rules. The Directors’ remuneration report is on pages 80-110. The consolidated financial statements of the group are on pages 113-186 and the corresponding reports of the auditor are on pages 114-121. The parent company financial statements of BP p.l.c. are on pages 215-238. The Directors’ statements (comprising the Statement of directors’ responsibilities; Risk management and internal control; Going concern; Longer-term viability; and Fair balanced and understandable), the independent auditor’s report on the annual report and accounts to the members of BP p.l.c., the parent company financial statements of BP p.l.c. and corresponding auditor’s report, a non-GAAP measure of operating cash flow excluding the Gulf of Mexico oil spill payments in the group chief executive’s letter on page 6 and in the tables on pages 18 and 22 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. BP Annual Report and Form 20-F 2016 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 2016, forms any part of this document. References in this document to other documents on the BP website, such as BP Energy Outlook, BP Sustainability Report, BP Statistical Review of World Energy and BP Technology Outlook are included as an aid to their location and are not incorporated by reference into this document. BP p.l.c. is the parent company of the BP group of companies. The company was incorporated in 1909 in England and Wales and changed its name to BP p.l.c. in 2001. Where we refer to the company, we mean BP p.l.c. 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 272 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. * See Glossary. 290 BP Annual Report and Form 20-F 2016 Acknowledgements Design: SALTERBAXTER MSLGROUP Typesetting: Donnelley Financial Solutions Printing: Pureprint Group Limited, UK, ISO 14001, FSC® certified and CarbonNeutral® Photography: Aaron Tait, Arnaldo Kikuti, Arnhel De Serra, Barry Halton, Bob Wheeler, Chidiebere Igbokwe, Diki Nugro, Giles Barnard, Graham Trott, Marc Morrison, Mehmet Binay, Richard Davies, Shahin Abassaliyev, Stuart Conway, Tamas Leko, Tom Vander Sande Paper: This document is printed on Oxygen paper and board. Oxygen is made using 100% recycled pulp, a large percentage of which is de-inked. It is manufactured at a mill with ISO 9001 and 14001 accreditation and is FSC® (Forest Stewardship Council) certified. This document has been printed using vegetable inks. Printed in the UK by Pureprint Group using their printing technology. BP’s corporate reporting suite includes information about our financial and operating performance, sustainability performance and also on global energy trends and projections. B P A n n u a l R e p o r t a n d F o r m 2 0 - F 2 0 1 6 Annual Report and Form 20-F 2016 3 Annual Report and Form 20-F 2016 Details of our financial and operating performance in print and online. Sustainability Report 2016 BP Energy Outlook 2017 edition Details of our sustainability performance with additional information online. Provides our projections of future energy trends and factors that could affect them out to 2035. bp.com/annualreport bp.com/sustainability bp.com/energyoutlook Financial and Operating Information 2012-2016 Statistical Review of World Energy 2017 Five-year financial and operating data in PDF and Excel format. bp.com/financialandoperating An objective review of key global energy trends. bp.com/statisticalreview BP social media Join the conversation, get the latest news, see photos and films from the field and find out about working with us. Feedback Your feedback is important to us. You can email the corporate reporting team at corporatereporting@bp.com or provide your feedback online at bp.com/annualreportfeedback You can also telephone +44 (0)20 7496 4000 or write to: Corporate reporting BP p.l.c. 1 St James’s Square London SW1Y 4PD, UK You can order BP’s printed publications free of charge from: bp.com/papercopies US and Canada Issuer Direct Toll-free: +1 888 301 2505 bpreports@precisionir.com UK and rest of world BP Distribution Services Tel: +44 (0)870 241 3269 Fax: +44 (0)870 240 5753 bpdistributionservices@bp.com © BP p.l.c. 2017 

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