BP
Annual Report 2018

Plain-text annual report

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 8 Growing the business and advancing the energy transition BP Annual Report and Form 20-F 2018 Advancing energy to improve people’s lives Contents Strategic report Overview 2 4 6 8 9 BP at a glance How we run our business Chairman’s letter Group chief executive’s letter The changing energy mix Strategy 10 Our strategy 12 BP investor proposition 14 Major project start-ups Performance 16 Measuring our progress 18 Global energy markets 19 Group performance 22 Upstream 28 Downstream 34 Rosneft 37 Other businesses and corporate 38 Alternative energy Innovation in BP 40 43 Sustainability 43 Safety and security 45 Climate change 48 Managing our impacts 49 Value to society 49 Human rights 50 Ethical conduct 51 Our people 53 How we manage risk 55 Risk factors Helge Lund succeeded Carl-Henric Svanberg as chairman. Helge joined the board in July and took the chair on 1 January 2019. See page 6. Financial statements 113 Consolidated financial statements of the BP group 134 Notes on financial statements 210 Supplementary information on oil and natural gas (unaudited) 238 Parent company financial statements of BP p.l.c. Corporate governance Additional disclosures Introduction from the chairman 58 Board of directors 63 Executive team 68 70 Board activity in 2018 74 Shareholder engagement 74 75 Audit committee 81 International advisory board Safety, ethics and environment assurance committee Remuneration committee 83 84 Geopolitical committee 85 Chairman’s committee 86 87 Directors’ remuneration report 110 Directors’ statements Nomination and governance committee 273 Contents Including information on liquidity and capital resources, oil and gas disclosures, upstream regional analysis and legal proceedings. Shareholder information 305 Contents Including information on dividends, our annual general meeting and share prices. 315 Glossary 320 Non-GAAP measures reconciliations 323 Signatures 324 Cross-reference to Form 20-F 325 Information about this report Glossary Words and terms with this symbol are defined in the glossary on page 315. Cautionary statement This document should be read in conjunction with the cautionary statement on page 303. What we do We provide customers with fuel for transport, energy for heat and light, power for industry, lubricants to keep engines moving and the petrochemicals products used to make everyday items such as paints, clothes and packaging. Find out more about our activities on page 4. Our people and our values The BP values express who we are and what we stand for. They capture the individual and collective behaviours we expect from everyone who works for us. Our people help build enduring relationships based on mutual trust with governments, customers, partners, suppliers and communities. Read more about our people on page 51 or visit bp.com/values. Safety Respect Excellence Courage One team Our performance in 2018 See how our businesses have performed and how we are reducing our emissions, improving our products and creating low carbon businesses. Find out more on pages 16 to 56. Our strategy Our four strategic priorities are designed to allow us to be competitive at a time when prices, policy, technology and customer preferences are evolving rapidly. Find out more on page 10. Informing our thinking Global prosperity is shaping economic and energy trends. By 2040: GDP doubling >2.5 billion people lifted from low incomes See how we consider a range of scenarios on page 9. BP Annual Report and Form 20-F 2018 1 BP at a glance We are a global energy business with wide reach across the world’s energy system. We have operations in Europe, North and South America, Australasia, Asia and Africa. Data as at or for the year ended 31 December 2018 unless otherwise stated. Scale 73,000 78 employees countries 18,700 retail sites 63,000 square kilometres of new exploration access 19,945 million barrels of oil equivalent – proved hydrocarbon reservesa a On a combined basis of subsidiaries and equity- accounted entities. BP in action Highlights of some of our activities in 2018. Completed a significant turnaround at our largest refinery, Whiting in the US. Acquired Chargemaster, operator of the UK’s largest electric vehicle charging network. Purchased a 16.5% interest in the UK’s Clair field from ConocoPhillips – increasing our share to 45.1%. Opened more than 220 REWE to Go® convenience retail sites in Germany. Acquired a portfolio of unconventional assets from BHP in some of the best basins across Texas and Louisiana. Signed a production-sharing agreement with SOCAR to explore and develop in the North Absheron basin in Azerbaijan’s Caspian Sea. Opened our 440th BP-branded retail site in Mexico. Formed a strategic alliance with Petrobras to explore joint projects in upstream, downstream, trading and low carbon. And accessed new acreage in the Santos basin, offshore Brazil, making us the second-largest exploration holder in the basin. 2 2 See Glossary See Glossary BP Annual Report and Form 20-F 2018 BP Annual Report and Form 20-F 2018 Signed an agreement with the governments of Mauritania and Senegal to enable development of the BP-operated Greater Tortue Ahmeyim gas project. Gained approval for the Ghazeer project to develop the second phase of the Khazzan field in Oman. Performance $9.4bn 3.7 16 profit attributable to BP shareholders million barrels of oil equivalent per day – hydrocarbon productiona tier 1 process safety events (2017 $3.4 billion) KPI (2017 3.6mmboe/d) KPI (2017 18) KPI $12.7bn 100% underlying replacement cost profit group proved reserves replacement ratio a KPI See key performance indicators on page 16. (2017 $6.2 billion) KPI (2017 143%) KPI a On a combined basis of subsidiaries and equity- accounted entities. Completed a deal to develop resources in the Kharampurskoe and Festivalnoye licence areas in Russia, jointly with Rosneft. Invested in PowerShare – a Chinese company that’s connecting EV drivers, charge point operators and power suppliers. And signed a memorandum of understanding with NIO Capital to explore opportunities in advanced mobility. Six major projects started up in 2018 S t r a t e g i c r e p o r t – o v e r v i e w See pages 14 and 15. More on our renewables activity Investments in electric vehicle technology on page 42. Low carbon ambitions on pages 46-48. Took delivery of British Partner – the first of six state-of-the-art liquefied natural gas ships being constructed in South Korea. Fuelled the first non-stop flight from Perth to London with Air BP jet fuel produced at our nearby Kwinana refinery. Lightsource BP delivered its first Indian solar project. And BP sanctioned the second phase of the KG D6 development in the ‘Satellite cluster’ deepwater gas fields in India with Reliance. BP Annual Report and Form 20-F 2018 BP Annual Report and Form 20-F 2018 BP Annual Report and Form 20-F 2018 BP Annual Report and Form 20-F 2018 See Glossary 3 3 How we run our business Business model foundations Safe and reliable operations Talented people From the deep sea to the desert, from rigs to retail, we deliver energy products and services to people around the world. 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 and equip our people with the right skills for the future. Our performance and ability to thrive globally depend on it. We provide customers with fuel for transport, energy for heat and light, power for industry, lubricants to keep engines moving and the petrochemicals products used to make everyday items such as paints, clothes and packaging. We have a diverse portfolio across businesses, resource types and geographies. Having upstream, downstream and renewables businesses, along with well-established trading capabilities, helps to mitigate the impact of commodity pricing cycles. Our geographic reach gives us access to growing markets and new resources, as well as diversifying exposure to geopolitical events. We are helping to meet the dual challenge of society’s need for more energy while reducing emissions through our ‘reduce, improve, create’ framework (see page 46). We believe that our long history, well-recognized brands and customer offers, combined with our unique partnership with Rosneft, help differentiate us from our peers. Our role in society The energy we produce helps 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 great employer. We believe the societies and communities we work in should benefit from our presence. We aim to create positive, meaningful and sustainable impacts in those communities through our social investments. We contribute to economies around the world by employing local people, helping to develop national and local suppliers, and through the funds we pay to governments from taxes and other agreements. See bp.com/society for more information on how we generate value to society. See Safety and security on page 43. See Our people on page 51. 1 Finding oil and gas 2 Developing and extracting oil and gas Creating value 1 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, and develop and use technology to reduce costs and risks. 2 Developing and extracting oil and gas We develop the resources that meet our return threshold and produce hydrocarbons that 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. We also seek to grow or extend the life of existing fields – such as our Clair Ridge project, which is helping unlock additional resources from the Clair field in the UK North Sea. See Upstream on page 22. 3 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 carbon products, as well as derivatives and currencies. BP’s traders serve more than 12,000 customers across some 140 countries in a year. Our customers range from independent power producers to utilities and municipalities. We are the largest trader of natural gas in North America. We use our market intelligence to analyse supply and demand for commodities across our global network. 4 BP Annual Report and Form 20-F 2018  Technology and innovation Partnerships and collaboration Governance and oversight New technologies help us produce energy safely and more efficiently. We selectively invest in areas with the potential to add greatest value to our business, now and in the future, including building lower carbon businesses. 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 Innovation in BP on page 40. See Rosneft on page 34 and Upstream analysis by region on page 279. See How we manage risk on page 53 and Corporate governance on page 57. 3 Transporting and trading 4 Manufacturing and marketing S t r a t e g c i r e p o r t – o v e r v i e w 6 Venturing 5 Generating renewable energy 4 Manufacturing and marketing fuels and products We produce refined petroleum products at our refineries and supply distinctive fuels 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, including lower carbon products. 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 lubricant markets across the world. 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. See Downstream on page 28. 5 Generating renewable energy We have been investing in renewables for many years. Our focus is on biofuels, biopower, wind energy and solar energy. We operate a biofuels business in Brazil, using one of the world’s most sustainable and advantaged feedstocks to produce renewable ethanol and power. We also provide renewable power through our significant interests in onshore wind energy in the US, and develop and deploy technology to drive efficiency. And in solar energy we target the growing demand for large-scale solar projects worldwide through Lightsource BP. See Alternative energy on page 38 and Climate change on page 45. 6 Venturing We invest in high-tech companies to help accelerate and commercialize new technologies, products and business models. Our focus is on five areas that are core to our strategy for advancing the energy transition: advanced mobility, bio and low carbon products, carbon management, digital transformation and power and storage. See bp.com/venturing. BP Annual Report and Form 20-F 2018 5 Strategic report – overview Chairman’s letter $8.1bn total dividends distributed to BP shareholders 6.3% ordinary shareholders annual dividend yield 6.4% ADS shareholders annual dividend yield 6 See Glossary BP Annual Report and Form 20-F 2018 I am of the view that more energy with fewer emissions – the dual challenge – can be met if a progressive and pragmatic approach is taken to the energy transition. Dear fellow shareholder, 2018 has been a year of very good operating performance, important strategic progress and continued change. Our teams have delivered strong results across the business and we are well positioned to continue to deliver value as we play our part in the dual challenge of delivering more energy with fewer emissions. It was an honour to be appointed chairman of BP. I have huge respect for the responsibilities that come with the role and I will do my utmost to provide thoughtful leadership to the board of directors and support for Bob Dudley and his team as we advance BP in a changing energy landscape. BP’s strong position is a great tribute to my predecessor as chairman, Carl-Henric Svanberg. During his nine-year tenure Carl-Henric did an outstanding job of guiding our company through difficult times. On behalf of the board, I want to thank him for his contribution. It has been a pleasure to get to know my new colleagues on the board, and I believe we have a wide ranging combination of diversity, skills, experience and knowledge that we need to steer the company through a landscape that is both uncertain and presents possibilities. Last year we welcomed Dame Alison Carnwath and Pamela Daley to the board, each with extensive experience gained in a range of executive and non-executive roles in large companies. And this year we say farewell to Alan Boeckmann and Admiral Frank ‘Skip’ Bowman. Alan and Skip have both made valuable contributions during their tenures, particularly through their leadership and membership of our safety, ethics and environment assurance committee. Strengthening organizational culture and capability The work of the board will continue to evolve over time to make sure that BP is best positioned to advance the energy transition, embrace digital disruption and meet society’s changing expectations of major companies. In my short time so far at BP I have already seen for myself many examples of the commitment of our people. Their drive and determination have brought BP to where it is today, and I want to thank them for their hard work. It is critically important we continue to strengthen our organizational capabilities – both by developing our people and by continuing to attract the world’s top talent. We look forward to doing this by continuing to foster a diverse and inclusive culture, where everyone feels valued. i S t r a t e g c r e p o r t – o v e r v i e w Our progressive, pragmatic approach to the energy transition There are two defining priorities for our industry. One is to produce more energy to meet growing global demand as emerging economies develop and provide people with a better quality of life. The other is to play our part in reducing greenhouse gas emissions. I am of the view that more energy with fewer emissions – the dual challenge – can be met if a progressive and pragmatic approach is taken to the energy transition. In BP we recognize that energy in many forms will be required, produced in ways that are cleaner and better. That is why we see ourselves not just as an oil and gas business but as a global energy business. We also recognize that we must be constantly improving and seeking out new ideas and possibilities. We must be able to learn fast and harness all the potential of the rapid advances in digital and other new technologies. Earning trust through strong values Pursuing this approach, BP is guided by its values of safety, respect, excellence, courage and one team. These are values I personally share. I believe they help to build trust with our people, partners, the communities in which we work, and with you, the owners of the company. Above all, our primary focus has to always be on operating safely and reliably, minute by minute, day after day. Protecting people, the environment and our assets is always our top priority and the bedrock on which success is built. I think of it as having the tightest defence in the league, like a good football team. If you have a strong defence, you can be more forward looking, compete harder and be better positioned to win. We value the dialogue we have with you and others, sharing our achievements, our challenges and our plans and seeking your views. This report is one of many ways we update you on our activities and progress. This year, the board is pleased to support a resolution that has been proposed by a group of investors at our annual general meeting in May. The resolution, if passed, will pave the way for additional reporting to help investors better understand how BP’s strategy is consistent with the Paris climate goals. We see this as an important opportunity for investors to appraise our progress in responding to the dual challenge. Further details can be found in the Notice of Meeting, to be published in April. Our clear purpose Finally, I think it is important for BP’s success that we have a clear purpose – one that is strongly linked to society’s needs. That is why one of the first things I have done with the board is review our purpose in line with our strategy and values. Our purpose is to advance energy to improve people’s lives. Today the world needs more energy than ever but with fewer emissions. To help meet this dual challenge we have to be financially strong and make sure we continue to be an attractive investment through the energy transition. I look forward to working with Bob and the team as we advance the energy transition, delivering through our strategy, guided by our values and inspired by our purpose. I also look forward to hearing from you, and meeting many of you, in the coming months and years as we look to reward your trust and confidence in BP. Helge Lund Chairman 29 March 2019 More information Corporate governance Page 57 BP Annual Report and Form 20-F 2018 7 Group chief executive’s letter Dear fellow shareholder, I am pleased to report that 2018 was another remarkable year for BP. Our safety performance continued to improve overall, helping to create record operational reliability, which led to strong production, and record refining throughput. Strength in numbers This ultimately contributed to us maintaining a healthy balance sheet as we more than doubled our underlying profit, nearly doubled our return on average capital employed, and significantly increased operating cash flow. It was a year in which we secured our biggest deal in 20 years, acquiring BHP’s world-class unconventional oil and gas onshore US assets. We also made progressive moves in mobility, such as the acquisition of the UK’s leading electric vehicle charging network to create BP Chargemaster. BP is in good shape. Our strategy is delivering value for you, our shareholders, while being flexible and agile for the energy transition underway. • We continued to focus on advantaged oil and gas in the Upstream, delivering new supplies of gas from four of our six new major projects brought online in 2018. We are also expanding our LNG portfolio and developing new markets in transport and power. • In the Downstream, we expanded our retail offer, as seen by more than 25% growth in our convenience partnerships, to around 1,400 sites worldwide. • As we pursue venturing and low carbon across multiple fronts, Lightsource BP doubled its global solar presence to 10 countries. • And we underpinned all this by continuing to modernize our plants, processes, and portfolio by harnessing the potential of digital and new technologies to provide greater efficiencies, reliability and safety. 8 Our strategy is delivering value for you, our shareholders, while being flexible and agile for the energy transition underway. Advancing the energy transition The deals we made and the strategy we have in place are evidence that BP is a forward-looking energy business. One that is already playing an active role in advancing the energy transition. That’s why we are making bold changes across our entire business to reduce emissions in our operations, improve products to help customers reduce their own emissions, and to create new low carbon businesses. This is our ‘reduce, improve, create’ (RIC) framework which we are backing up with clear targets. I am pleased to report we are making good progress against these targets. BP is also working with peers on a range of fronts, in particular to tackle methane emissions and create opportunities for carbon capture, utilization and storage. You’ll see this in our work with the Oil and Gas Climate Initiative, which I chair, and whose members now represent 30% of global oil and gas production. As well as action across the industry, at BP we understand that meeting our own low carbon ambitions is a shared responsibility across our entire business. That’s why we are now incentivizing around 36,000 employees who are eligible for an annual cash bonus to play a role by linking their reward to one of our emissions reduction targets. Possibilities everywhere We will continue to be open and transparent about our ambitions, plans and progress, recognizing that the trust of our shareholders and other stakeholders is essential to BP remaining a reliable and attractive long-term investment. And only by ensuring we remain a world-class investment, can we most effectively play our part in advancing a low carbon future. As a global energy business with scale, expertise and strong relationships around the world, we don’t just believe we have an important part to play in the dual challenge, we see value-generating opportunities for BP throughout the energy transition. We’re making good progress delivering our strategy while flexing and adapting to an environment that is changing fast. We have a great team at BP and I would like to thank them all for their continued dedication and relentless commitment to advancing the energy transition. Bob Dudley Group chief executive 29 March 2019 GAAP equivalents Profit attributable to shareholders: $9.4bn (2017: $3.4bn) Average capital employed: $165.5bn (2017: $159.4bn) BP Annual Report and Form 20-F 2018The changing energy mix The BP Energy Outlook explores the forces shaping the global energy transition out to 2040 and the key uncertainties surrounding that transition. We use the scenarios in the Outlook together with a range of other analysis and information when forming our long-term strategy. i S t r a t e g c r e p o r t – o v e r v i e w The demand for energy is set to increase significantly – growing economies need energy to support their industry and infrastructure. In all the scenarios considered, world GDP more than doubles by 2040 driven by increasing prosperity in fast-growing developing economies. That said, oil and gas could meet at least 50% of the world’s energy needs in 2040 – even in a scenario consistent with the Paris goals, with the share of gas growing aided by increasing use of carbon capture, use and storage. In the evolving transition scenario, this improvement in living standards causes energy demand to increase by a third by 2040, driven mainly by India, China and other developing Asian economies. The rate of growth however is slower than in the previous 20 years, as the world increasingly learns to produce more with less energy. Despite this, a substantial proportion of the world’s population in 2040 could live in countries where the average energy consumption per person is relatively low. At the same time, the energy mix is changing as technology advances, consumer preferences shift and policy measures evolve. Renewables are now the fastest-growing energy source in the world today and in our evolving transition scenario we estimate that they could account for 15% of all energy consumption in 2040 – and in other scenarios more. Gas offers a cleaner alternative to coal for power generation and can lower emissions at scale. It also provides a valuable partner for renewables intermittency, delivers heating at the high temperatures required by industry and is increasingly used in transportation. Across our scenarios, gas grows robustly, overtaking coal as the second-largest source of energy by 2030. Oil demand grows for the next 10 years in our evolving transition scenario, before gradually levelling out due to factors such as accelerating gains in vehicle efficiency and greater use of biofuels, natural gas and electricity. The largest source of oil demand growth is the non-combusted use of oil, for example as a feedstock for petrochemicals. Energy consumption – 2040 projections % 4 3 % 3 2 % 8 2 % 4 % 7 % 4 Actual energy mix 2017 Evolving transition 2040 % 7 2 % 6 2 % 0 2 % 4 % 7 % 5 1 Rapid transition 2040 % 3 2 % 6 2 % 7 % 6 % 9 % 9 2 0 5 10 15 20 Billion tonnes of oil equivalent. The sum of the fuel shares may not equal 100% due to rounding. Oil Gas Coal Nuclear Hydro Renewables 1 Evolving transition This scenario assumes that government policies, technology and social preferences continue to evolve in a manner and speed seen over the recent past. 2 Rapid transition This scenario is consistent with the Paris goals, and is broadly similar to the reduction in carbon emissions in the IEA’s Sustainable Development Scenario. 1 Evolving transition • World energy demand increases by one third 2 Rapid transition • Oil demand in 2040 decreases by 14Mb/d. from 2017 to 2040. Biofuels grow by 4Mb/d. • CO2 emissions from energy use increase • CO2 emissions from energy use decline by 7% by 2040. by around 45% by 2040. • Oil and gas account for more than half of • Global energy consumption grows by global energy in 2040. around one fifth. More information BP Energy Outlook See bp.com/energyoutlook for more information on our projections of future energy trends and factors that could affect them out to 2040. BP Technology Outlook See bp.com/technologyoutlook for information on how technology could influence the way we meet the energy challenge into the future. 9 BP Annual Report and Form 20-F 2018 Our strategy Society is demanding solutions for more energy, delivered in new and better ways for a low carbon future. Our strategy is designed to meet this dual challenge. Through new technologies, energy will be produced more efficiently and in new ways, helping to meet the expected rise in demand. Our strategy allows us to be competitive at a time when prices, policy, technology and customer preferences are evolving rapidly. We believe having a balanced portfolio with advantaged oil and gas, a competitive downstream and a range of low carbon activities, with the flexibility of our strategy, gives us optionality whatever path the transition takes. With the experience we have and the portfolio we’ve created, we can embrace the energy transition in a way that enhances our investor proposition, while continuing to meet the need for energy. More information Financial framework How this underpins our commitment to disciplined investment and growing shareholder value. See page 13. 10 See Glossary BP Annual Report and Form 20-F 2018 Growing advantaged oil and gas in the upstream Invest in more oil and gas, producing both with increasing efficiency. Key highlights Transforming US onshore Purchased unconventional assets from BHP, giving us access to some of the best basins in the onshore US. See Upstream on page 24. Collaborative partnerships Signed a new production-sharing agreement with SOCAR, Azerbaijan’s state oil and gas company, to jointly explore and develop block D230 in the Caspian Sea. And formed a strategic alliance with Petrobras to explore joint projects in upstream, downstream, trading and low carbon in Brazil. See Upstream analysis by region on page 279. Project approvals Sanctioned Ghazeer in Oman – the second phase of development in the Khazzan gas field; Alligin and Vorlich in the UK North Sea; the Cassia Compression and Matapal gas projects in Trinidad; KG D6 Satellites in India; Zinia 2 in Angola; Manuel and Atlantis Phase 3 in the Gulf of Mexico; and Tortue in Mauritania and Senegal. See Upstream on page 22. Major project start-ups Started up six major projects, making a significant contribution to the 900,000 barrels per day of expected new production from major project start-ups between 2016 and 2021. See Upstream on page 22. Market-led growth in the downstream Venturing and low carbon across multiple fronts Modernizing the whole group S t r a t e g c i r e p o r t – s t r a t e g y Innovate with advanced products and strategic partnerships. Pursue new opportunities to meet evolving technology, consumer and policy trends. Simplify our processes and enhance our productivity through digital solutions. Key highlights Convenience partnerships Harnessing battery power Using wearable technologies Opened more than 220 additional REWE to Go® retail sites in Germany, taking the total number of convenience partnership sites to around 1,400 across our global retail network. Made a series of investments in electric vehicle technology and infrastructure to help us respond to rising demand for battery charging facilities, including the acquisition of Chargemaster, operator of the UK’s largest electric vehicle charging network. Trialled new technologies, such as smart glasses in the US and digital vests in Oman, to help increase safety and efficiency at our operations. See Downstream on page 28. See Innovation in BP on page 42. See page 52. Growing retail in new markets Expanded our network to 440 BP-branded retail sites in Mexico and opened our first sites in Indonesia. Advancing solar Lightsource BP has doubled the number of countries where it has a presence since December 2017. See Downstream on page 28. See Climate change on page 45. Sustainable aviation fuel Entered into an innovative collaboration between Air BP and Neste, a leading renewable products producer, to secure and promote the supply of sustainable aviation fuel. Turning waste to fuel Licensed technology, developed by BP and Johnson Matthey, to Fulcrum BioEnergy® for use at their planned US commercial-scale waste-to-fuels plant. Strong brands and partnerships Strengthened our lubricants and fuels partnership with Renault Sport Racing – extending our BP Castrol sponsorship and broadening the relationship to include joint development of advanced mobility solutions and new technologies. See Downstream page 28. See Climate change on page 45. Cleaner power Working with the Oil and Gas Climate Initiative to progress the Clean Gas Project, which plans to use natural gas to generate power, and then capture and transport the CO2 by pipeline for storage in a formation under the southern North Sea. See bp.com/sustainability for more information. Cloud-based technologies Deployed Plant Operations Advisor on our four platforms in the US Gulf of Mexico. The cloud-based tool helps reduce the time it could take engineers to diagnose a problem from hours to minutes. See Innovation in BP on page 40. Intelligent operations Installed APEX technology across all our upstream BP-operated assets to gather data about every well and help identify efficiency improvements. See Innovation in BP on page 40. Process automation Reduced the time it takes to complete manual tasks, such as contract management and customer data processing, by using robotic process automation. This is helping to optimize our business processes, drive productivity and improve customer satisfaction. BP Annual Report and Form 20-F 2018 11 BP investor proposition BP investor proposition Safer Fit for the future Focused on returns Safe, reliable and efficient execution A distinctive portfolio fit for a changing world Value based, disciplined investment and cost focus Growing sustainable free cash flow and distributions to shareholders over the long term Our investor proposition is to grow sustainable free cash flow and distributions to shareholders over the long term. We believe our strategy enables this, through a focus on safe, reliable and efficient execution, leveraging our distinctive portfolio, and disciplined investment to support growing returns. Safer Safety is one of our core values and our number one priority. We are focused on being systematic, disciplined and process driven. A safe business doesn’t just protect people, it also helps improve operating performance, leading to improved business and financial performance. In recent years overall safety events have declined, and we’ve increased upstream plant reliability and downstream refining availability . See Measuring our progress on page 16 and Safety on page 43. Fit for the future As an integrated business, we benefit from having upstream, downstream, renewable energy businesses and an established trading function. Our balanced portfolio spans resource types and geographies with a strong and distinctive set of assets, brands and relationships. In the Upstream we are growing ‘advantaged’ oil and gas – that means low cost or high margin. This improves the likelihood that the hydrocarbons we produce are resilient and competitive in terms of demand in a low carbon world. We have strong incumbent positions in many of the world’s top hydrocarbon basins and a robust pipeline of growth opportunities – see page 27. We started up six major projects in 2018. The Downstream business has a strong and focused presence. We have advantaged manufacturing facilities, considerable potential for growth in our marketing businesses, and are expanding our retail network in rapidly growing markets such as Mexico, Indonesia and China. We also provide products – such as fuels with ACTIVE technology – and offers that help consumers lower their emissions – see page 28. Through our well-established supply and trading function we generate value by providing the link between our businesses and third-party customers. In November BP and partners in banking and trading launched VAKT, the world’s first blockchain platform for managing post-trade oil and commodities commercially. And we’re increasing our activity in renewables, building on our existing solar, wind and biofuels businesses, and creating new business models. For example Lightsource BP has doubled the number of countries where it has a presence since December 2017 – see page 47. Embedded within our strategy is our commitment to advance a low carbon future. We plan to deliver this across our entire business by reducing emissions in our operations, improving our products and services, and creating low carbon businesses. See Our low carbon ambitions on page 46. We are actively managing the portfolio to remain resilient in a changing world and believe we have enough flexibility in our portfolio to reshape our business and balance sheet in around 10 years should we need to. This enables us to monitor changing trends and legislation, and provides us with optionality to adjust our portfolio and adapt to the future. Focused on returns We have a disciplined financial framework that is central to our strategy, and clear growth plans out to 2021 and beyond. Recent portfolio additions and new long-term agreements – for example our purchase of BHP’s unconventional onshore assets in the US and we signed with SOCAR in the new production-sharing agreement Azerbaijan – have strengthened our position. We have held our capital frame of $15-17 billion a year for organic expenditure for the past three years and expect to do so at least out to 2021. We believe we can continue to generate robust organic growth within this framework and that the strength of our balance sheet will allow us to deal with any near-term volatility. We remain confident in our guidance on returns of greater than 10% by 2021 at an oil price of $55/bbl (based on real 2017 Brent oil prices). See Group performance on page 19. Distributions to shareholders Our commitment to growing distributions to shareholders is underpinned by our progressive dividend policy and share buyback programme. In July 2018 we announced a 2.5% increase to our dividend, and over the year distributed total dividends to shareholders of $8.1 billion. We have remained active in our share buyback programme, buying back 50 million ordinary shares in 2018 at a cost of $355 million including fees and stamp duty. 12 See Glossary BP Annual Report and Form 20-F 2018 2.5% dividend increase in July $8.1bn total dividends distributed to BP shareholders in 2018 Our financial framework We maintain a disciplined financial framework, which underpins our investment choices and supports growth in sustainable free cash flow, returns and distributions to shareholders. Our balance sheet and cash cover metrics are strong, and during 2018 this enabled us to acquire the BHP Lower 48 assets, funded using available cash. Alongside the real momentum across our businesses, and in line with growing free cash flow and the receipt of divestment proceeds, we continue to expect to deliver the 2021 targets laid out two years ago. S t r a t e g c i r e p o r t – s t r a t e g y Capital expenditure Divestments 2018 outcome Guidance 2019-2021 Organic capital expenditure was $15.1 billion*, at the bottom end of our guidance. We expect organic capital expenditure to be in the range of $15-17 billion per year. Total divestment and other proceeds of $3.5 billiona achieved. This was in line with guidance of more than $3 billion for the year. Gulf of Mexico oil spill payments 2018 payments totalled $3.2 billion, in line with our guidance of just over $3 billion. Gearing Gearing at the end of 2018 was 30.3%**. Group return on average capital employed (ROACE) ROACE was 11.2%***, almost double that in 2017. Distributions We increased the quarterly dividend by 2.5% in July and repurchased 50 million ordinary shares at a cost of $355 million in 2018. We expect more than $10 billion of divestments over the next two years. This includes divestments announced as part of the BHP transaction. We expect payments of around $2 billion in 2019, stepping down to around $1 billion per year for the next 14 years. We expect gearing to be in the range of 20-30%. We expect ROACE to be more than 10% by 2021 at $55/bbl (based on real 2017 Brent oil prices). Progressive dividend and a continued share buyback programme, which is expected to fully offset the impact of scrip dilution since the third quarter of 2017 by the end of 2019. Our published guidance will be updated for any impacts associated with the new lease accounting standard, IFRS 16 ‘Leases’, during 2019. a This includes a $0.6 billion loan repayment to BP relating to the refinancing of Trans Adriatic Pipeline AG. Divestment proceeds for 2018 were $2.9 billion. Balancing our sources and uses of cashb Following the rebalancing of organic sources and uses of cash in 2017, operating cash flow excluding the Gulf of Mexico oil spill payments exceeded organic capital expenditure and dividends in 2018. After adjusting for a working capital build in the year, BP’s free cash flow surplus was $6.5 billion equivalent to an organic cash break even oil price of $50 per barrel on a full dividend basis. We continue to expect the cash break even to reduce over time in line with growing operating cash flow across the businesses and organic capital expenditure in the range of $15-17 billion per year. Organic sources and uses of cash b ($ billion) For the year ended 31 December 2018 30 25 20 15 10 5 30 25 20 15 10 5 2017 Sources Uses Sources Uses Nearest equivalent GAAP measures * Capital expenditure: $25.1 billion. ** Gross debt ratio: 39.3%. *** Numerator: Profit attributable to BP shareholders $9.4 billion; Denominator: Average capital employed $165.5 billion. b This does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. c 2018 includes a $0.6 billion loan repayment to BP relating to the refinancing of Trans Adriatic Pipeline AG. 2017 includes proceeds of $0.8 billion received relating to the initial public offering of BP Midstream Partners LP’s common units, which are shown within financing activities in the group cash flow statement. Other sources and uses of cashb ($ billion) For the year ended 31 December 2018 15 10 5 2017 15 10 5 Sources Uses Sources Uses Organic sources Organic uses Operating cash flow excluding Gulf of Mexico oil spill payments Others Organic capital expenditure Cash dividends paid Share buyback Other sources Divestment and other proceedsc Other uses Operating cash flow – Gulf of Mexico oil spill Inorganic capital expenditure BP Annual Report and Form 20-F 2018 BP Annual Report and Form 20-F 2018 See Glossary 13 Major project start-ups Atoll Phase 1, Egypt We developed and delivered first gas from Atoll Phase 1 less than three years after its discovery. It supports our commitment to help realize Egypt’s oil and gas potential and meet the increasing demand from its growing population. Operator Pharaonic Petroleum Company Partners BP (100%) Project type Conventional gas 110km subsea tieback 6,400 metres well depth, more than Mount Kilimanjaro Cairo Suez <3 years to deliver Clair Ridge, UK North Sea Clair Ridge is the second phase development of the Clair field – the largest in the UK continental shelf. Operator BP Partners BP (45.1%), Shell (28%), Chevron (19.4%), Conoco Phillips (7.5%), Project type Conventional oil Thunder Horse Northwest Expansion, US 16 months from sanction to first oil We started up the Thunder Horse Northwest Expansion project 16 months after it was sanctioned. The project is on our largest platform in the deepwater Gulf of Mexico. Operator BP Partners BP (75%), ExxonMobil (25%) Project type Deepwater oil 14 BP Annual Report and Form 20-F 2018Western Flank B, Australia Taas-Yuryakh expansion, Russia Led by our partner Rosneft, the Taas-Yuryakh expansion project in Eastern Siberia is an example of successful collaboration in the remote Russian region of Sakha (Yakutia). Operator Taas Partners Rosneft (50.1%), Oil India, Indian Oil, Bharat PetroResources (29.9%), BP (20%) Project type Conventional oil and gas Located off the north-west coast of Australia, the Western Flank B project develops five fields via an eight subsea well tieback to the Goodwyn A platform. Operator Partners Woodside BP, BHP, Chevron, Shell, Woodside and Japan Australia LNG (16.67% each) Project type LNG Photo credit: Woodside Energy Ltd. Shah Deniz Stage 2, Azerbaijan 26 subsea wells 500km of subsea flow lines Shah Deniz Stage 2 was our biggest major project start-up in 2018. It includes complex offshore and onshore projects with pipeline developments across the Southern Gas Corridor. Operator BP Partners BP (28.8%), SOCAR (16.7%), PETRONAS (15.5%), Lukoil (10%), NICO (10%), TPAO (19%) Project type Conventional gas Azerbaijan 2 new bridge- linked platforms constructed by 5,000+ workers and installed in the Caspian Sea Georgia 2 new compressor stations each approximately the size of 20 football pitches Turkey 2,760 metres the highest point of the 1,850km TANAP pipeline, in eastern Turkey S t r a t e g c i r e p o r t – s t r a t e g y 15 BP Annual Report and Form 20-F 2018 Measuring our progress We assess our performance across a wide range of measures and indicators that are consistent with our strategy and investor proposition. Our key performance indicators (KPIs) provide a balanced set of metrics that give emphasis to both financial and non-financial measures. These help the board and executive management assess performance against our strategic priorities and business plans, with non-financial metrics playing a useful role as leading indicators of future performance. BP management uses these measures to evaluate operating performance and make financial, strategic and operating decisions. Safer Tier 1 process safety eventsa REM Reported recordable injury frequencya REM REM REM 2018 2017 2016 2015 2014 16 18 16 20 10 20 28 30 40 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. 2018 performance We have seen a slight decrease in tier 1 process safety events. However there is always more we can do and we remain focused on achieving better results today and in the future. 2018 2017 2016 2015 2014 0.20 0.22 0.21 0.24 0.31 0.1 0.4 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. 0.2 0.3 2018 performance We have seen a decrease in our RIF compared with 2017. Our goals stay the same – to have no accidents, no harm to people and no damage to the environment. More information Focused on returns Strategy Pages 10-13 Changes to KPIs In 2018 we introduced a target to achieve 3.5 million tonnes of sustainable GHG emissions reductions in our operations worldwide by 2025. Progress towards this target has now been incorporated into the assessment of the group’s performance that is a factor in determining annual bonuses for eligible BP employees worldwide. This will apply to our performance assessment in 2019 and beyond. We are also changing downstream refining availability to BP- operated downstream refining availability to more closely align with our BP-operated upstream plant reliability measure. 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. REM Measures used for the remuneration policy approved by shareholders at the 2017 AGM. Underlying replacement cost profit ($ billion) REM 2018 2017 2016 2015 2014 (6.5) 9.4 3.4 6.2 0.1 2.6 5.9 3.8 0 REM 12.7 12.1 Operating cash flow ($ billion) REM REM 2018 2017 2016 2015 2014 26.1 22.9 24.1 10.7 18.9 17.6 20.3 19.1 32.8 32.8 Profit (loss) for the year Underlying RC profit for the year (non-GAAP) Underlying RC profit is a useful measure for investors because it is one of the profitability measures BP management uses to assess performance. It assists management in understanding the underlying trends in operational performance on a comparable year-on-year basis. It reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. Adjustments are also made for non-operating items and fair value accounting effects . 2018 performance The significant increase in both profit for the year and underlying RC profit was largely due to higher profits in Upstream, reflecting major project start-ups and higher prices, partly offset by higher taxes. Operating cash flow excluding Gulf of Mexico oil spill payments (non-GAAP)b Operating cash flow Operating cash flow is net cash flow provided by operating activities, as reported in the group cash flow statement. Operating activities are the principal revenue-generating activities of the group and other activities that are not investing or financing activities. We believe it is helpful to disclose net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill because this measure allows for more meaningful comparisons between reporting periods. 2018 performance Operating cash flow was higher due to improved business results, including the benefit of higher oil prices and lower Gulf of Mexico oil spill payments, which amounted to $3.2 billion in 2018, partly offset by higher working capital. Return on average capital employed (%) REM Total shareholder return (%) REM REM Measures for the annual bonus are focused on safety, reliable operations and financial performance. Measures for performance shares are focused on shareholder value, capital discipline and future growth. 2018 2017 2016 2015 2014 2.8 5.8 5.5 11.2 9.6 Return on average capital employed (non-GAAP) gives an indication of a company’s capital efficiency, dividing the underlying RC profit after adding back net interest by average capital employed, excluding cash and goodwill. See page 321 for more information including the nearest equivalent GAAP data. 2018 performance The increase reflects improved business results, including the impact of higher prices and the benefit of further upstream major project start-ups in the year. REM These measures were used for executive remuneration under the terms of our discontinued 2014-16 policy. More information Directors’ remuneration Page 87 Footnotes key a This represents reported incidents occurring within BP’s operational HSSE reporting boundary. That boundary includes BP’s own operated facilities and certain other locations or situations. b These bars on the chart do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. c Relates to BP employees. 16 See Glossary 2018 2017 2016 2015 2014 (4.6) 0.5 20.0 9.5 29.0 55.5 (12.8) (8.3) (16.5) (11.6) -20 0 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. 2018 performance Reduced TSR reflects a reduction in the share price in 2018 compared with share price growth in 2017, largely offset by higher dividend in 2018. BP Annual Report and Form 20-F 2018Fit for the future Reserves replacement ratio (%) Production (mboe/d) Upstream unit production costs ($/boe) REM 2018 2017 2016 2015 2014 REM 100 143 109 61 63 2018 2017 2016 2015 2014 3,268 3,239 3,141 3,683 3,595 2018 2017 2016 2015 2014 7.15 7.11 8.46 10.46 12.75 60 80 100 120 140 160 3,000 3,200 3,400 3,600 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. 2018 performance The ratio of 100.4% was in line with our five-year average reserves replacement ratio, due to new project investments and revisions in our existing projects. Production is a useful measure for tracking how our major projects are helping to grow our business. 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. 2018 performance BP’s total reported production, including Upstream and Rosneft segments, was 2.4% higher than in 2017. This was due to major project ramp-ups and improved plant reliability. The upstream unit production cost indicator shows how supply chain, headcount and scope optimization impact cost efficiency. 2018 performance Higher unit production costs, compared with 2017, were due to increased well-work activity and the impact of higher prices on production entitlements. Refining availability (%) REM Major project delivery Upstream plant reliability (%) REM REM 2018 2017 2016 2015 2014 90 94.9 95.3 95.3 94.7 94.9 2018 2017 2016 2015 2014 6 6 6 7 7 2018 2017 2016 2015 2014 8 90 4 4 2 95.7 94.7 95.3 95.0 93.4 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. 2018 performance Refining availability remained strong, underpinned by our global reliability improvement programmes. The result was, however, lower than 2017 reflecting increased maintenance, particularly at our Gelsenkirchen refinery. We monitor the progress of our major projects to gauge whether we are delivering our core pipeline of projects under construction on time. BP-operated upstream plant reliability is calculated as 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Projects take many years to complete, requiring differing amounts of resource, so a smooth or increasing trend should not be anticipated. 2018 performance The result was a record, reflecting our focus on efficiency of execution, and use of advanced new technologies and digital applications. 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. 2018 performance We started up six major projects in Australia, Azerbaijan, Egypt, Russia, the UK and US. Greenhouse gas emissions (million tonnes of CO2 equivalent) Diversity and inclusionc (%) Employee engagement (%) 2018 2017 2016 2015 2014 46.5 49.4 50.1 49.0 48.7 20 40 60 We provide data on greenhouse gas (GHG) emissions material to our business on a carbon dioxide-equivalent basis. This comprises direct emissions of CO2 and methane. Our GHG KPI comprises 100% emissions from subsidiaries and the percentage of emissions equivalent to our share of joint arrangements and associates , other than BP’s share of Rosneft. 2018 performance The primary reasons for the overall decrease include actions taken by our businesses to reduce emissions in areas such as flaring, methane and energy efficiency, and operational changes such as increased gas being captured and exported to the liquefied natural gas facility in Angola. 2018 2017 2016 2015 2014 24 24 24 21 22 23 19 18 21 21 5 10 15 20 25 30 Women Non UK/US Each year we report the percentage of women and individuals from countries other than the UK and the US among BP’s group leaders. 2018 performance While the percentage of our group leaders who are non-UK/US remained the same, the percentage of female group leaders rose. As a global business we are committed to increasing the diversity of our workforce and leadership. 2018 2017 2016 2015 2014 66 66 73 71 73 We conduct an annual employee survey to understand and monitor levels of employee engagement and identify areas for improvement. 2018 performance We changed our survey questions in 2017 to reflect the new priorities set out in our refreshed strategy. The scores prior to 2017 are based on questions on priorities set out in 2012, so the numbers are not directly comparable. See Glossary 17 Strategic report – performanceBP Annual Report and Form 20-F 2018Global energy markets Average oil prices increased again in 2018, but remained well below the prices seen in 2011-13. Co-ordinated OPEC and non-OPEC production restraint early in the year and robust global demand growth were countered by record growth in US production. The world economy grew at 3% in 2018, reflecting slower growth in both advanced and emerging economies. This was slightly lower than the 3.1% seen in 2017, but around the average of nearly 3% over the past 20 years. Growth in advanced economies slightly decelerated to 2.2% from 2.4% in 2017, reflecting temporary factors, such as natural disasters in Japan, slowing net exports in Europe and the ongoing trade disputes. Emerging markets showed a similar broad-based deceleration, growing by 4.2% in 2018, compared with 4.3% in 2017. The slowdown in emerging markets activity reflects softening global trade and tightening monetary conditions. Oil Crude oil prices ($/bbl – quarterly average) Brent dated 150 120 90 60 09 10 11 12 13 14 15 16 17 2018 Prices Dated Brent crude oil prices averaged $71.31 per barrel in 2018 – a second consecutive annual increase but still well below the average of over $110 seen in 2011-13. Prices drifted higher over the first half of the year as production restraint remained in place among OPEC and co-operating non-OPEC countries, then rose more rapidly to reach their annual peak near $85 in October. In the face of rising prices, producers relaxed their restraint at mid-year and prices fell sharply late in the year, ending 2018 at their annual low point of about $50. Consumptiona Global consumption increased by 1.3 million barrels per day (mmb/d) to 99.2mmb/d for the year (1.3%) – a fourth consecutive increase greater than the 10-year average – due to continued lower than average oil prices and stronger world economic growth. Demand once again grew most rapidly in Asia’s emerging economies (+0.8mmb/d), but OECD demand also increased for a fourth consecutive year. Productiona Global oil production grew by a robust 2.6mmb/d (2.7%) to average 100.0mmb/d, with non-OPEC countries (+2.7mmb/d) accounting for all of the increase. The US saw record production growth of 2.2mmb/d. In contrast OPEC production declined by 0.1mmb/d – the second consecutive annual decline – although it began to recover later in the year. Inventoriesa These changes resulted in global supply significantly exceeding demand in 2018, especially later in the year. In the face of production restraint from OPEC and co-operating non-OPEC countries early in the year, commercial oil inventories in the OECD were below the five- 18 See Glossary year average for much of the year. But with the reversal of production restraint inventories began to rise, and by the end of December were slightly above the five-year average, standing at 2,858 million barrels. Natural gas Natural gas prices ($/mmBtu – quarterly average) Henry Hub 12 10 8 6 4 2 09 10 11 12 13 14 15 16 17 2018 Prices Gas prices rebounded in all key markets in 2018. Asian and European gas prices have increased to $9.76/mmBtu and 60.38 pence per therm respectively, up from $7.13/mmBtu and 44.95 pence per therm in 2017. This was driven by higher oil, coal, and CO2 prices (in Europe) as well as a relatively tight liquefied natural gas (LNG) market. Asian prices were strong at above $10/mmBtu during summer due to high Asian LNG demand and a tight LNG market, but dropped below $9/mmBtu in late 2018 due to warm weather in Asia and growing LNG supplies. While LNG supply increased strongly, all of these incremental LNG supplies were absorbed by Asia – with China accounting for around half of that growth. US spot prices averaged $3.11/mmBtu – after being flat at $3/mmBtu for most of the year, they rebounded during the last quarter due to low storage levels. Consumption Global consumption is estimated to have increased more rapidly in 2018 than in 2017, driven by strong growth in the US and China. US demand growth was largely driven by increasing gas use in the power sector as power generation recovered and an estimated 14GW of coal capacity was retired in 2018. Chinese gas demand continued to grow at a double-digit rate on the back of coal-to-gas switching in the industrial and buildings sectors. Production Total gas production increased substantially in 2018. Significant production increases were achieved in the US and Australia – supported by the start of new LNG trains – and Russia. Global LNG supply capacity expanded slightly faster than in 2017, with around 28mtpa of LNG capacity starting commercial operations. Several trains came online in Australia, Russia, the US and Cameroon. a From IEA Oil Market Report, 13 February 2019 ©, OECD/IEA 2019 More information Prices and margins Pages 25 and 30 BP Annual Report and Form 20-F 2018S t r a t e g c i r e p o r t – p e r f o r m a n c e Group performance We saw significant growth in earnings, cash and returns. The continued strong cash flow growth underpins the balance sheet as we absorb the BHP acquisition and deliver more than $10 billion of divestments over the next two years. Dr Brian Gilvary Group chief financial officer $12.7bn underlying replacement cost (RC) profit $26.1bn operating cash flow excluding Gulf of Mexico oil spill payments a (2017 $6.2 billion) (2017 $24.1 billion) $9.4bn profit attributable to BP shareholders $22.9bn operating cash flow (2017 $3.4 billion) (2017 $18.9 billion) Financial and operating performance Segment RC profit (loss) before interest and tax ($ billion) 2018 2017 2016 (15) (10) (5) 0 5 10 15 20 25 Downstream Upstream Rosneft Other businesses and corporate (includes costs related to the Gulf of Mexico oil spill) Consolidation adjustment – UPII Group RC profit (loss) before interest and tax 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 RC profit (loss) Net (favourable) adverse impact of non-operating items and fair value $ million except per share amounts 2016 (430) 2017 9,474 (2,294) (3,712) (79) 3,389 (853) 225 2,761 (1,865) 2,467 (57) 115 (1,597) 483 (999) 2018 19,378 (2,655) (7,145) (195) 9,383 801 (198) 9,986 accounting effects , before tax 3,380 3,730 6,746 Taxation charge (credit) on non-operating items and fair value accounting effects Underlying RC profit Dividends paid per share – cents – pence a This does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. b Profit (loss) attributable to BP shareholders. (643) 12,723 40.5 30.568 (325) 6,166 40.0 30.979 (3,162) 2,585 40.0 29.418 More information Upstream Page 22 Downstream Page 28 Rosneft Page 34 Other businesses and corporate Page 37 Oil and gas disclosures for the group Page 285 See Glossary 19 BP Annual Report and Form 20-F 2018 Results Profit for the year ended 31 December 2018 was $9.4 billion, compared with $3.4 billion in 2017. Including inventory holding losses, replacement cost (RC) profit was $10.0 billion, compared with $2.8 billion in 2017. After adjusting for a net charge for non-operating items of $2.8 billion and net favourable fair value accounting effects of $68 million (both on a post-tax basis), underlying RC profit for the year ended 31 December 2018 was $12.7 billion, an increase of $6.6 billion compared with 2017. The increase was predominantly due to higher results in Upstream, as well as Downstream and Rosneft segments, partly offset by higher taxes. The upstream result reflected higher oil prices, record plant reliability and the benefit of new major projects start-ups. The downstream result reflected stronger refining margins and strong fuels marketing growth. The Rosneft segment result primarily reflected higher oil prices. Profit for the year ended 31 December 2017 was $3.4 billion, compared with $115 million in 2016. Excluding inventory holding gains, RC profit was $2.8 billion, compared with a loss of $1.0 billion in 2016. After adjusting for a net charge for non-operating items of $3.3 billion and net adverse fair value accounting effects of $96 million (both on a post-tax basis), underlying RC profit for the year ended 31 December 2017 was $6.2 billion, an increase of $3.6 billion compared with 2016. The increase was predominantly due to higher results in both Upstream and Downstream segments. The upstream result reflected higher oil and gas prices and increased production. The downstream result reflected strong refining performance, including an improved margin environment and growth in fuels marketing. Non-operating items The net charge for non-operating items was $2.8 billion post-tax in 2018, mainly related to additional charges for the Gulf of Mexico oil spill, environmental and other provisions, and further restructuring costs. The group restructuring programme originally announced in 2014 has now been completed. The net charge for non-operating items was $3.3 billion post-tax in 2017. This includes a charge of $1.7 billion recognized in the fourth quarter relating to business economic loss and other claims associated with the Gulf of Mexico oil spill and a $0.9 billion deferred tax charge following the change in the US tax rate enacted in December 2017. In addition, the net charge also reflected an impairment charge in relation to upstream assets. More information on non-operating items and fair value accounting effects can be found on pages 276 and 320. See Financial statements – Note 2 for further information on the impact of the Gulf of Mexico oil spill on BP’s financial results. Taxation The charge for corporate income taxes was $7,145 million in 2018 compared with $3,712 million in 2017. The increase mainly reflects the higher level of profit in 2018. In 2017 the charge for corporate income taxes included a one-off deferred tax charge of $0.9 billion in respect of the revaluation of deferred tax assets and liabilities following the reduction in the US federal corporate income tax rate. A further credit of $121 million following a clarification of the legislation has been included in 2018. The effective tax rate (ETR) on the profit or loss for the year was 43% in 2018, 52% in 2017 and 107% in 2016. The ETR for all three years was impacted by various one-off items. Adjusting for inventory holding impacts, non-operating items which include the impact of the US tax rate change, fair value accounting effects and the deferred tax adjustments as a result of the reduction in the UK North Sea supplementary charge in 2016, the adjusted ETR on RC profit was 38% in 2018 (2017 38%, 2016 23%). The adjusted ETR for 2017 was higher than 2016, predominantly due to changes in the geographical mix of profits, notably the impact of the renewal of our interest in the Abu Dhabi onshore oil concession. In the current environment the adjusted ETR in 2019 is expected to be around 40%. Cash flow and net debt information Operating cash flow excluding Gulf of Mexico oil spill paymentsa Operating cash flow Net cash used in investing activities Net cash provided by (used in) financing activities Cash and cash equivalents at end 2018 2017 $ million 2016 26,091 22,873 24,098 18,931 17,583 10,691 (21,571) (14,077) (14,753) (4,079) (3,296) 1,977 of year 22,468 25,586 23,484 Capital expenditure Organic capital expenditure Inorganic capital expenditure Gross debt Net debt Gross debt ratio (%) Net debt ratio (%) (15,140) (9,948) (25,088) 65,799 44,144 39.3% 30.3% (16,501) (1,339) (17,840) 63,230 37,819 38.6% 27.4% (16,675) (777) (17,452) 58,300 35,513 37.6% 26.8% 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 2018 was $22.9 billion, $4.0 billion higher than the $18.9 billion reported in 2017. Operating cash flow in 2018 reflects $3.5 billion of pre-tax cash outflows related to the Gulf of Mexico oil spill (2017 $5.3 billion). Compared with 2017, operating cash flows in 2018 reflected improved business results, including a more favourable price environment and higher production, partly offset by working capital effects, and a $1.7 billion increase in income taxes paid. adversely impacted cash flow in the Movements in working capital year by $4.8 billion. There was an adverse impact on working capital from the Gulf of Mexico oil spill of $3.1 billion. Other working capital effects, principally an increase in other current and non-current assets partially offset by a decrease in inventory, had an adverse effect of $1.7 billion. BP actively manages its working capital balances to optimize and reduce volatility in cash flow. There was an increase in net cash provided by operating activities of $8.2 billion in 2017 compared with 2016, of which $1.7 billion related to lower pre-tax cash outflows related to the Gulf of Mexico oil spill. Compared with 2016, operating cash flows in 2017 were impacted by improved business results, including a more favourable price environment and higher production, working capital effects, and a $2.5-billion increase in income taxes paid. 20 See Glossary BP Annual Report and Form 20-F 2018 Movements in working capital adversely impacted cash flow in 2017 by $3.4 billion. There was an adverse impact on working capital from the Gulf of Mexico oil spill of $5.2 billion. Other working capital effects, arising from a variety of different factors had a favourable effect of $1.8 billion. Receivables and inventories increased during the year principally due to higher oil prices. The effect of this on operating cash flow was more than offset by a corresponding increase in payables. Net cash used in investing activities Net cash used in investing activities for the year ended 31 December 2018 increased by $7.5 billion compared with 2017. The increase mainly reflected higher inorganic capital expenditure of $6.7 billion in relation to the BHP acquisition and a reduction of $0.6 billion in net disposal proceeds. The decrease of $0.7 billion in 2017 compared with 2016 mainly reflected an increase of $0.8 billion in disposal proceeds. Debt Gross debt at the end of 2018 increased by $2.6 billion from the end of 2017. The gross debt ratio at the end of 2018 increased by 0.7%. Net debt at the end of 2018 increased by $6.3 billion from the 2017 year-end position. The net debt ratio at the end of 2018 increased by 2.9%. At current oil prices, and in line with growing free cash flow supported by divestment proceeds, we expect gearing to move towards the middle of our targeted range of 20-30% in 2020. Net debt and the net debt ratio are non-GAAP measures. See Financial statements – Note 27 for gross debt, which is the nearest equivalent measure on an IFRS basis, and for further information on net debt. Cash and cash equivalents at the end of 2018 were $3.1 billion lower than 2017. For information on financing the group’s activities, see Financial statements – Note 29 and Liquidity and capital resources on page 277. Group reserves and production (including Rosneft segment)a 2018 2017 2016 There were no significant cash flows in respect of acquisitions in 2017 and 2016. Estimated net proved reserves (net of royalties) Total capital expenditure for 2018 was $25.1 billion (2017 $17.8 billion), of which organic capital expenditure was $15.1 billion (2017 $16.5 billion). Sources of funding are fungible, but the majority of the group’s funding requirements for new investment comes from cash generated by existing operations. We expect organic capital expenditure to be in the range of $15-17 billion in 2019. Divestment proceeds for 2018 were $2.9 billion (2017 $3.4 billion, 2016 $2.6 billion). In addition, we received a $0.6-billion loan repayment relating to the refinancing of Trans Adriatic Pipeline AG, and total divestment and other proceeds for 2018 amounted to $3.5 billion. In 2017 divestment proceeds included amounts received for the disposal of our interest in the Shanghai SECCO Petrochemical Company Limited joint venture . In addition, we received $0.8 billion in relation to the initial public offering of BP Midstream Partners LP’s common units, shown within financing activities in the group cash flow statement, and total divestment and other proceeds for 2017 amounted to $4.3 billion. BP intends to complete more than $10 billion of divestments over the next two years, which includes plans announced following the BHP transaction. Net cash used in financing activities Net cash used in financing activities for the year ended 31 December 2018 was $4.1 billion, compared with $3.3 billion used in financing activities in 2017. This was mainly the result of an increase of $0.9 billion in net proceeds from financing offset by a reduction of $1.1 billion in cash received in relation to non-controlling interests and an increase in dividend payments of $0.5 billion. In 2017 the net cash used in financing activities reflected a reduction of $3.5 billion in net proceeds from financing. The total dividend paid in cash in 2017 was $1.5 billion higher than in 2016. Total dividends distributed to shareholders in 2018 were 40.50 cents per share, 0.50 cents higher than 2017. This amounted to a total distribution to shareholders of $8.1 billion (2017 $7.9 billion, 2016 $7.5 billion), of which shareholders elected to receive $1.4 billion (2017 $1.7 billion, 2016 $2.9 billion) in shares under the scrip dividend programme. The total amount distributed in cash during the year amounted to $6.7 billion (2017 $6.2 billion, 2016 $4.6 billion). Liquids (mmb) Natural gas (bcf) Total hydrocarbons (mmboe) Of which: Equity-accounted entitiesb Production (net of royalties) Liquids (mb/d) Natural gas (mmcf/d) Total hydrocarbons (mboe/d) Of which: Subsidiaries Equity-accounted entitiesc 11,456 49,239 19,945 10,672 45,060 18,441 10,333 43,368 17,810 9,757 8,949 8,679 2,191 8,659 3,683 2,328 1,355 2,260 7,744 3,595 2,164 1,431 2,048 7,075 3,268 1,939 1,329 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 34 and Supplementary information on oil and natural gas on page 210 for further information. c Includes BP’s share of Rosneft. See Rosneft on page 34 and Oil and gas disclosures for the group on page 285 for further information. Total hydrocarbon proved reserves at 31 December 2018, on an oil-equivalent basis including equity-accounted entities, increased by 8% compared with 31 December 2017. The change includes a net increase from acquisitions and disposals of 1,498mmboe (increase of 993mmboe within our subsidiaries, increase of 505mmboe within our equity-accounted entities). Acquisition activity in our subsidiaries occurred in the US and the UK, and divestment activity in our subsidiaries was in the US and the UK. In our equity-accounted entities, acquisitions occurred in Russia. Total hydrocarbon production for the group was 2% higher compared with 2017. The increase comprised an 8% increase (1% decrease for liquids and 17% increase for gas) for subsidiaries and a 5% decrease (5% decrease for liquids and 5% decrease for gas) for equity-accounted entities. See Glossary 21 Strategic report – performanceBP Annual Report and Form 20-F 2018Upstream 2018 has been a good year for Upstream, where we increased confidence in 2021 delivery and underpinned our ability to continue growth well into the next decade. Bernard Looney Chief executive, Upstream 63,000km 2 95.7% 7 new exploration access BP-operated upstream plant reliability successful completion of turnarounds (2017 28,000km2) (2017 94.7%) 9 6 final investment decisions major project start-ups (2017 6) 2.5 million barrels of oil equivalent per day – hydrocarbon production Upstream profitability ($ billion) 2018 2017 2016 2015 2014 -0.5 -0.9 0.6 1.2 14.3 14.6 5.2 5.9 8.9 15.2 (2017 3) (2017 7) (2017 2.5mmboe/d) Replacement cost (RC) profit (loss) before interest and tax Underlying RC profit (loss) before interest and tax Business model The Upstream segment is responsible for our activities in oil and natural gas exploration, field development and production. We do this through five global technical and operating functions. Exploration Wells and projects Global operations organization 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. Strategy Our strategy has three parts and is enabled by: Quality execution We want to be the best at what we do – everywhere we work. This starts with executing our activity safely. In every basin, we will benchmark against the competition and aim to be the best – whether it be operating facilities reliably and cost effectively, with a focus on emissions, drilling wells, managing our reservoirs, exploring, building projects, or deploying technology. Through the quality of our execution, scale and infrastructure, we aim to be competitive in every basin, and as a business, get more from a unit of capital than our peers. 22 See Glossary Growing advantaged oil and gas We will manage our portfolio through disciplined investment in many of the world’s great oil and gas basins. We plan to grow both oil and gas production. Natural gas is a big lever for reducing greenhouse gas emissions. This means taking a leadership role in tackling the challenge of methane. Our gas portfolio will be complemented by advantaged oil assets – oil we can produce at a lower cost or higher margin, creating a portfolio that is flexible for different price environments. Returns-led growth We want to grow – but not at any cost. We always look to grow returns and value. We believe this growth will come from many sources – production growth, expanding and managing our margins, operational efficiency, unit cost reduction, and capital efficiency with disciplined levels of capital reinvestment. BP Annual Report and Form 20-F 2018Underpinning our business model and strategy is our transformation agenda. We have around 1,000 projects across the Upstream aimed at sustainably improving both performance and how it feels to work in the Upstream. We believe in the potential of this agenda to transform the efficiency of our business, and we are delivering real value today to the bottom line. In addition to our core Upstream exploration, development and production activities, the segment is responsible for midstream transportation, storage and processing. We also market and trade natural gas, including liquefied natural gas (LNG), power and natural gas liquids (NGL). In 2018 our activities took place in 33 countries. The US Lower 48 business continues to operate as a separate, asset-focused, onshore business, and changed its name to BPX Energy in October. With the exception of BPX Energy, we deliver our exploration, development and production activities through five global technical and operating functions. We optimize and integrate the delivery of our activities across 12 regions, with support provided by global functions in specialist areas of expertise: technology, finance, procurement and supply chain, human resources, information technology and legal. In 2016 we identified a future growth target of 900,000 barrels of oil equivalent per day of production from new major projects by 2021 and we remain on track to deliver that. We expect this production to deliver 35% higher operating cash margins on average than our 2015 upstream assets, which supports our value over volume strategy. 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 believe we are balanced and flexible – 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. Financial performance Sales and other operating revenuesa RC profit before interest and tax Net (favourable) adverse impact of non-operating items and fair value accounting effects Underlying RC profit (loss) before interest and tax Organic capital expenditure b BP average realizationsc Crude oild Natural gas liquids Liquids Natural gas US natural gas Total hydrocarbons d Average oil marker pricese Brent West Texas Intermediate Average natural gas marker prices Average Henry Hub gas pricef Average UK National Balancing 2018 2017 56,399 14,328 45,440 5,221 $ million 2016 33,188 574 222 644 (1,116) 14,550 12,027 5,865 13,763 (542) 14,344 67.81 29.42 64.98 3.92 2.43 43.47 71.31 65.20 51.71 26.00 49.92 $ per barrel 39.99 17.31 38.27 $ per thousand cubic feet 2.84 1.90 $ per barrel of oil equivalent 28.24 3.19 2.36 35.38 54.19 50.79 $ per barrel 43.73 43.34 3.09 $ per million British thermal units 2.46 pence per therm 3.11 Point gas price e 60.38 44.95 34.63 a Includes sales to other segments. b A reconciliation to GAAP information at the group level is provided on page 275. c Realizations are based on sales by consolidated subsidiaries only, which excludes equity-accounted entities. d Includes condensate and bitumen. e All traded days average. f Henry Hub First of Month Index. See Glossary 23 Strategic report – performanceBP Annual Report and Form 20-F 2018Growing advantaged oil and gas in the upstream 470,000 acres of access Transforming US onshore BP is transforming its US onshore oil and gas business with our purchase of world-class unconventional assets from BHP. This acquisition gives us access to some of the best basins in the onshore US and positions BP as a top producer in the region. The transaction includes 470,000 acres of licences across a new position in the liquids-rich Permian-Delaware basin, and two premium positions in the Eagle Ford and Haynesville basins. Together these assets will significantly increase the liquid hydrocarbon proportion of our production and resources – helping to upgrade and reposition BPX Energy, which was previously known as the US Lower 48 business. BPX Energy has operated as a separate business since 2015. Its innovative approach to using new technology such as big-data analytics, augmented reality, drones and advanced drilling techniques, have helped the business achieve significant improvements in operational and financial performance. We plan to apply this approach to operations at our newly acquired basins. 24 BP Annual Report and Form 20-F 2018 United States Oklahoma New Mexico Texas Permian Haynesville Houston Eagle Ford 83,000 ~3,400 ~29,000 194,000 ~720 ~85,000 Louisiana 194,000 ~1,400 ~83,000 Size (acres) Number of drilling sites Current production (boe/d) Permian • Delaware sub-basin of the Permian in West Texas. • 83,000 acres with around 3,400 drilling sites. • Current production – around 29,000boe/d (~70% liquids). Eagle Ford • Karnes Trough and Eagle Ford in South Texas. • 194,000 acres with 1,400 gross drilling locations. • Current production – around 83,000boe/d (~70% liquids). Haynesville • East Texas and Louisiana. • 194,000 acres with 720 gross drilling locations. • Current production – around 85,000boe/d, all gas. As at 31 December 2018. Market prices Brent remains an integral marker to the production portfolio, from which a significant proportion of production is priced directly or indirectly. Brent ($/bbl) 150 120 90 60 30 2018 2017 2016 Five-year range Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Dated Brent crude oil prices averaged $71.31 per barrel in 2018 – a second consecutive annual increase but still well below the average of more than $110 seen in 2011-13. Prices drifted higher over the first half of the year, then rose more rapidly to reach an annual peak near $85 in October, before falling sharply and ending the year at an annual low point of about $50. Oil demand recorded a fourth consecutive above-average increase, growing by 1.3mmb/d. Global production increased by an even more robust 2.6mmb/d, with all of the increase coming from non-OPEC countries (2.7mmb/d); the US recorded record production growth of 2.2mmb/d. OPEC production fell slightly (-0.1mmb/d) for a second consecutive year as the group engaged with co-operating non-OPEC countries in production restraint early in the year, although OPEC production began to recover in the second half of the year as production restraint was eased. Henry Hub ($/mmBtu) 9 6 3 2018 2017 2016 Five-year range Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Henry Hub prices decreased to $3.09/mmBtu in 2018 from $3.11/ mmBtu in 2017. The UK National Balancing Point hub price was 60.38 pence per therm in 2018, 34% higher than in 2017 (44.95), on the back of increasing coal, oil and CO2 prices. Asian spot prices rose to $9.76/ mmBtu in 2018, up from $7.13/mmBtu supported by higher coal, and oil prices as well as a relatively tight LNG market – except in the later part of 2018, where ample LNG supplies combined with warm weather caused Asian spot prices to drop to below $9/mmBtu. For more information on global energy markets in 2018 see page 18. Financial results Sales and other operating revenues for 2018 increased compared with 2017, primarily reflecting higher liquids realizations, higher production and higher gas marketing and trading revenues. The increase in 2017 compared with 2016 primarily reflected higher liquids realizations, higher production and higher gas marketing and trading revenues. Replacement cost profit before interest and tax for the segment included a net non-operating charge of $183 million. This primarily relates to impairment charges associated with a number of assets, following changes in reserves estimates, the decision to dispose of certain assets and the decision to relinquish a number of leases expiring in the near future, partially offset by reversals of prior year impairment charges. See Financial statements – Note 5 for further information. Fair value accounting effects had an adverse impact of $39 million relative to management’s view of performance. The 2017 result included a net non-operating charge of $671 million, primarily related to impairment charges associated with a number of assets, following changes in reserves estimates, and the decision to dispose of certain assets. Fair value accounting effects had a favourable impact of $27 million relative to management’s view of performance. The 2016 result included a net non-operating gain of $1,753 million, primarily related 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. Fair value accounting effects had an adverse impact of $637 million. After adjusting for non-operating items and fair value accounting effects, the underlying replacement cost result before interest and tax was significantly higher in 2018 compared with 2017. This primarily reflected higher liquids and gas realizations, higher production and lower exploration write-offs. Compared with 2016 the 2017 result reflected higher liquids realizations, and higher production including the impact of the Abu Dhabi onshore concession renewal and major projects start-ups, partly offset by higher depreciation, depletion and amortization, and higher exploration write-offs. Organic capital expenditure was $12.0 billion. In total, disposal transactions generated $2.1 billion in proceeds in 2018, with a corresponding reduction in net proved reserves of 229mmboe within our subsidiaries. The major disposal transactions during 2018 were the disposal of our interests in the Bruce, Keith and Rhum fields in the UK North Sea and our interest in the Greater Kuparuk Area in the US, the consideration for which was a 16.5% interest in the Clair field in North Sea. More information on disposals is provided in Upstream analysis by region on page 279 and Financial statements – Note 4. Outlook for 2019 • Five new major projects expected to start up in 2019. • We expect underlying production to be higher than 2018 due to major projects. The actual reported outcome will depend on the exact timing of project start-ups, acquisitions and divestments, OPEC quotas and entitlement impacts in our production-sharing agreements . • Upstream capital investment is expected to increase, largely as a result of our increased presence in the onshore US. • We expect oil prices will continue to be volatile in the near term. Exploration The group explores for oil and natural gas under a wide range of licensing, joint arrangement and other contractual agreements. We may do this alone or, more frequently, with partners. Our exploration and new access teams work 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. See Glossary 25 Strategic report – performanceBP Annual Report and Form 20-F 2018 New access in 2018 We gained access to new acreage covering around 63,000km2 in 10 countries – Australia, Azerbaijan, Brazil, Canada, Egypt, Madagascar, Mexico, São Tomé and Príncipe, the UK North Sea and the US Gulf of Mexico. Exploration success We participated in three potentially commercial discoveries in 2018 – Manuel and Nearly Headless Nick in the US Gulf of Mexico and Bongos in Trinidad. Exploration and appraisal costs Excluding lease acquisitions, the costs for exploration and appraisal were $1,298 million (2017 $1,655 million, 2016 $1,402 million). These costs included exploration and appraisal activities, which were capitalized within intangible fixed assets, and geological and geophysical exploration costs, which were charged to income as incurred. Approximately 5% of exploration and appraisal costs were directed towards appraisal activity. We participated in 29 gross (19 net) exploration and appraisal wells in eight countries. Exploration expense Total exploration expense of $1,445 million (2017 $2,080 million, 2016 $1,721 million) included the write-off of expenses related to unsuccessful drilling activities, lease expiration or uncertainties around development in the Gulf of Mexico ($450 million), Egypt ($236 million), and others ($759 million), as well as geological and geophysical exploration costs (see Financial statements – Note 8). 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 the segment’s equity-accounted entities at 31 December 2018, increased by 11% (an increase of 7% for subsidiaries and an increase of 47% for equity-accounted entities) compared with proved reserves at 31 December 2017. Proved reserves replacement ratio The proved reserves replacement ratio for the segment in 2018 was 69% for subsidiaries and equity-accounted entities (2017 127%), 66% for subsidiaries alone (2017 133%) and 106% for equity-accounted entities alone (2017 78%). For more information on proved reserves replacement for the group see page 285. Upstream proved reserves (mmboe) 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 2018 2017 2016 million barrels 4,378 794 5,172 576 15 590 4,954 808 5,762 30,355 4,559 34,914 10,188 1,594 11,782 4,129 674 4,803 318 18 336 4,447 692 5,139 3,778 771 4,549 373 16 389 4,151 787 4,938 billion cubic feet 28,888 2,580 31,468 29,263 2,274 31,537 million barrels of oil equivalent 9,131 1,232 9,492 1,085 10,577 10,363 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 2018 upstream operations in Argentina, Bolivia, Mexico, Russia and Norway as well as some of our operations in Angola were conducted through equity-accounted entities. d Includes 12 million barrels (14 million barrels at 31 December 2017 and 16 million barrels at 31 December 2016) in respect of the 30% non-controlling interest in BP Trinidad & Tobago LLC. e Includes 1,573 billion cubic feet of natural gas (1,860 billion cubic feet at 31 December 2017 and 2,026 billion cubic feet at 31 December 2016) in respect of the 30% non-controlling interest in BP Trinidad & Tobago LLC. Developments We achieved six major project start-ups in 2018 – in Azerbaijan, Australia, the Gulf of Mexico, Egypt, Russia and the UK North Sea. In addition to these, we made good progress on projects in Trinidad, Egypt and the UK North Sea. • Trinidad – Work on the Angelin project progressed well after we started the drilling programme in late 2018, and we announced first gas production in February 2019. Liquids 1. Subsidiaries 2. Equity-accounted entities Total Gas 3. Subsidiaries 4. Equity-accounted entities Total 4,954 808 5,762 5,234 786 6,020 4 • Egypt – Raven, the third phase of the West Nile Delta development project is on target to achieve first gas in second half of 2019 with well commissioning activities underway. 1 • UK North Sea – At Culzean, perforation of wells on the Total-operated project is about to get underway after completion of trees installation. Production is expected in the first half of 2019. Subsidiaries’ development expenditure incurred, excluding midstream activities, was $9.9 billion (2017 $10.7 billion, 2016 $11.1 billion). 3 2 26 See Glossary BP Annual Report and Form 20-F 2018  Our project pipeline *BP operated Project Gas Oil Type Location 2018 start-ups Shah Deniz Stage 2* Western Flank B Atoll Phase 1* Clair Ridge* Taas Expansion Thunder Horse North West Expansion* US Gulf of Mexico Azerbaijan Australia Egypt UK North Sea Russia Expected start-ups 2019-2021 Projects currently under construction Angelin*a Cassia Compression* Culzean KG D6 R-Series KG D6 Satellites Khazzan Phase 2* Tangguh Expansion* West Nile Delta Giza and Fayoum*a West Nile Delta Raven* Alligin* Atlantis Phase 3 Constellationa Mad Dog Phase 2* Manuel* Vorlich* Zinia 2 a Production commenced in early 2019. Trinidad Trinidad UK North Sea India India Oman Indonesia Egypt Egypt UK North Sea US Gulf of Mexico US Gulf of Mexico US Gulf of Mexico US Gulf of Mexico UK North Sea Angola Beyond 2021 We have a deep hopper of projects that are currently under appraisal. Our focus here is to ensure we maximize value 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: across six of the seven continents. • a range of development types: from exploration to brownfield and near-field. 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 assets. Our principal areas of production are Angola, Argentina, Australia, Azerbaijan, Egypt, Oman, Trinidad, the UAE, the UK and the US. With BP-operated plant reliability increasing from around 86% in 2011 to 96% in 2018, efficient delivery of turnarounds and strong infill drilling performance, we have maintained base decline at less than 3% on average over the last five 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 Subsidiaries Equity-accounted entitiesc Natural gas liquids Subsidiaries Equity-accounted entitiesc Total liquids Subsidiaries Equity-accounted entitiesc Natural gas Subsidiaries Equity-accounted entitiesc Total hydrocarbons Subsidiaries Equity-accounted entitiesc 2018 2017 2016 thousand barrels per day 1,051 121 1,172 88 8 96 1,139 129 1,268 6,900 474 7,374 1,064 199 1,263 85 8 93 1,149 207 1,356 943 179 1,122 82 4 86 1,025 184 1,208 million cubic feet per day 5,302 5,889 547 494 5,796 6,436 thousand barrels of oil equivalent per day 1,939 2,164 302 269 2,208 2,466 2,328 211 2,539 a Because of rounding, some totals may not agree exactly with the sum of their component parts. b Includes condensate and bitumen. c Includes BP’s share of production of equity-accounted entities in the Upstream segment. Our total hydrocarbon production for the segment in 2018 was 3.0% higher compared with 2017. The increase comprised a 7.6% increase (0.9% decrease for liquids and 17.2% increase for gas) for subsidiaries and a 30.0% decrease (37.6% for liquids and 13.4% for gas) for equity-accounted entities compared with 2017. For more information on production see Oil and gas disclosures for the group on page 285. In aggregate, underlying production increased versus 2017. 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 and power marketing and trading activities Our integrated supply and trading function markets and trades our own and third-party natural gas (including LNG), biogas, 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. We are expanding our LNG portfolio, which includes global partnerships with utility companies, gas distributors and national oil and gas companies. 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 29 and the range of contracts used is described in Glossary – commodity trading contracts on page 315. See Glossary 27 Strategic report – performanceBP Annual Report and Form 20-F 2018Downstream In 2018 we have continued to demonstrate, through the execution of our strategy, that we have a competitively advantaged business. Our strategy is fit for now and fit for the future. Tufan Erginbilgic Chief executive, Downstream 10% fuels marketing earnings growth (17% on an underlying RC profit basis) 1,400 convenience partnership sites 46% of lubricant sales were premium grade (2017 >10%) (2017 1,100) (2017 44%) 94.9% 1.7 11.9 refining availability million barrels of oil refined per day million tonnes of petrochemicals produced (2017 95.3%) (2017 1.7mmb/d) (2017 15.3mmte) Business model The Downstream segment has global marketing and manufacturing operations. It is the product and service-led arm of BP, made up of three businesses Downstream profitability ($ billion) 2018 2017 2016 2015 2014 6.9 7.6 7.2 7.0 7.1 7.5 5.2 5.6 3.7 4.4 Replacement cost (RC) profit before interest and tax Underlying RC profit before interest and tax Fuels Lubricants Petrochemicals Includes refineries, logistic networks and fuels marketing businesses, which together with global oil supply and trading activities, make up our integrated fuels value chains (FVCs). We sell refined petroleum products including gasoline, diesel and aviation fuel, and have a significant presence in the convenience retail sector and a growing presence in the advanced mobility and low carbon sectors. Manufactures and markets lubricants and related products and services to the automotive, industrial, marine and energy markets globally. We add value through brand, technology and relationships, such as collaboration with original equipment manufacturing partners. Manufactures and markets products that are produced using industry-leading proprietary BP technology, and are then used by others to make essential consumer products such as food packaging, textiles and building materials. We also license our technologies to third parties. Strategy 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 is to deliver underlying earnings growth and build competitively advantaged businesses. It is fit for now and fit for the future. The execution of our strategy in 2018 has continued to deliver, with underlying replacement cost profit growing to $7.6 billion in the year. Safe and reliable operations This remains our core value and first priority and we continue to drive improvements in personal and process safety performance. Profitable marketing growth We invest in higher-returning fuels marketing and lubricants businesses with growth potential and reliable cash flows. 28 See Glossary Advantaged manufacturing We aim to have a competitively advantaged refining and petrochemicals portfolio underpinned by operational excellence and to grow earnings potential, making the businesses more resilient to margin volatility. 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 delivering and developing new products, offers and business models that support the transition to a lower carbon and digitally enabled future. BP Annual Report and Form 20-F 2018 Market-led growth in the downstream S t r a t e g c i r e p o r t – p e r f o r m a n c e Convenience partnerships Throughout 2018 BP continued to transform its global retail business. We’ve refreshed our forecourts, rolled out more BP fuels with ACTIVE technology and further enhanced our customer offers. And that’s not all, we’re also rapidly expanding our convenience partnerships. >25% increase in convenience partnership sites We increased the number of convenience partnership sites by over 25% in 2018 – taking the total to around 1,400 sites across our network. Much of this growth was in Germany, where our strategic partnership with REWE to Go® is expanding rapidly. Since opening our first site in 2014, we now have over 460 in the country, and around half of those opened in 2018. Our REWE to Go® sites deliver substantially higher returns than an industry average site, driven by our differentiated customer offer including fresh, quality food and drink. We also continue to grow our convenience partnership model in established markets such as the UK with M&S Simply Food® and in October we opened our first partnership site in Luxembourg with MyAuchan®. We have rolled out our Ultimate fuel to forecourts in China. Global markets Our footprint in Mexico is growing and we now have 440 BP-operated sites, more than 300 of which were opened in 2018. We are also continuing to progress our plans for growth in China, and in Indonesia we opened our first sites at the end of the year. BP Annual Report and Form 20-F 2018 29 Financial performance 2018 2017 $ million 2016 Sale of crude oil through spot and term contracts 62,484 47,702 31,569 Marketing, spot and term sales of refined products 195,020 159,475 126,419 Other sales and operating revenues Sales and other operating revenuesa RC profit before interest and taxb Fuels Lubricants Petrochemicals Net (favourable) adverse impact of non-operating items and fair value accounting effects Fuels Lubricants Petrochemicals Underlying RC profit before interest and taxb Fuels Lubricants Petrochemicals Organic capital expenditure c 13,185 12,676 9,695 270,689 219,853 167,683 5,261 1,065 614 6,940 381 227 13 621 5,642 1,292 627 7,561 2,781 4,679 1,457 1,085 7,221 193 22 (469) (254) 4,872 1,479 616 6,967 2,399 3,337 1,439 386 5,162 390 84 (2) 472 3,727 1,523 384 5,634 2,102 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. c A reconciliation to GAAP information at the group level is provided on page 275. Financial results Sales and other operating revenues in 2018 were higher due to higher crude and product prices. Sales and other operating revenues in 2017 were higher than 2016 due to higher crude and product prices as well as higher sales volumes. Replacement cost (RC) profit before interest and tax for 2018 included a net non-operating charge of $716 million, primarily reflecting restructuring costs. The 2017 result included a net non-operating gain of $389 million, primarily reflecting the gain on disposal of our share in the Shanghai SECCO Petrochemical Company Limited (SECCO) joint venture in petrochemicals, while the 2016 result 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. In addition fair value accounting effects had a favourable impact of $95 million, compared with an adverse impact of $135 million in 2017 and $448 million in 2016. After adjusting for non-operating items and fair value accounting effects, underlying RC profit before interest and tax in 2018 was $7,561 million. Outlook for 2019 We anticipate lower industry refining margins, narrower North American heavy crude oil discounts and a lower level of turnaround activity than in 2018. 30 See Glossary Our fuels business Our fuels strategy focuses primarily on fuels value chains (FVCs). This includes building an advantaged refining portfolio through operating reliability and efficiency, location advantage and feedstock flexibility, as well as commercial optimization opportunities. 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. Our fuels marketing business comprises retail, business-to-business and aviation fuels. It is a material part of Downstream with a strong track record of growth. We have an advantaged portfolio of assets with good growth potential, attractive returns and reliable cash flows. We continue to grow our fuels marketing business through our differentiated marketing offers and strategic convenience partnerships. We also partner with leading retailers, creating distinctive retail offers that aim to deliver good returns and reliable profit growth and cash generation. Underlying RC profit before interest and tax for our fuels business was higher compared with 2017, reflecting continued growth in fuels marketing and refining despite 2018 having one of the highest levels of turnaround activity in our history. This was partially offset by a weaker contribution from supply and trading. Compared with 2016, the 2017 result was higher, reflecting stronger refining performance and growth in fuels marketing, partially offset by a weaker contribution from supply and trading. Refining marker margin We track the refining margin environment using 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 Crude marker Alaska North Slope West Texas Intermediate US Midwest Northwest Europe Brent Mediterranean Australia BP RMM Azeri Light Brent 2018 2017 $ per barrel 2016 16.2 16.0 11.1 9.8 11.5 13.1 18.8 16.9 11.7 10.4 12.9 14.1 16.9 13.2 10.0 9.0 10.9 11.8 The global RMM averaged $13.1/bbl in 2018, $1/bbl lower than in 2017. The RMM was lower mainly due to weaker gasoline margins as a result of lower demand growth and higher inventory levels in the US. BP refining marker margin ($/bbl) 32 24 16 8 2018 2017 2016 Five-year range Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec BP Annual Report and Form 20-F 2018 Refining At 31 December 2018 we owned or had a share in 11 refineriesa 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 284. Underlying growth in our refining business is underpinned by our multi-year business improvement plans, which comprise globally consistent programmes focused on operating reliability and efficiency, advantaged feedstocks and commercial optimization. Operating reliability is a core foundation of our refining business and in 2018 operations remained strong, with refining availability of 94.9% (2017 95.3%) and refinery utilization rates at 91% (2017 90%). As a result we achieved record levels of refining throughput on a current portfolio basis despite high turnaround activity. Our refinery portfolio – along with our supply capability – enables us to process advantaged crudes. For example, in the US, our three refineries all have location-advantaged access to Canadian crudes which are typically cheaper than other crudes. Our commercial optimization programme aims to maximize value from our refineries by capturing opportunities in every step of the value chain, from crude selection through to yield optimization and utilization improvements. In 2018 we delivered continued improvement in our net cash margin per barrel and extended lower carbon bio-processing into more of our refineries. , a measure of the competitiveness of our refinery portfolio, The refining result was higher in 2018 compared with 2017, reflecting increased commercial optimization and strong operations, which in North America allowed us to capture the benefits from higher North American heavy crude oil discounts, partially offset by lower industry refining margins and a higher level of turnaround activity. Compared with 2016, refining performance continued to improve in 2017, capturing higher industry refining margins and efficiency benefits as well as increased commercial optimization including the benefits of higher levels of advantaged feedstock. This was, however, partially offset by a higher level of planned turnaround activity. 2018 2017 2016 Refinery throughputsab US Europe Rest of world Total Refining availability 703 781 241 1,725 94.9 713 773 216 1,702 thousand barrels per day 646 803 236 1,685 % 95.3 95.3 a This does not include BP’s interest in Pan American Energy Group, which is reported through the Upstream segment. b Refinery throughputs reflect crude oil and other feedstock volumes. Fuels marketing and logistics Across our fuels marketing businesses, 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. Through our retail business, we supply fuel and convenience 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 in the transport and industrial sectors. Retail is the most material part of our fuels marketing business and a significant source of earnings growth through our strong market positions, brands and distinctive customer offers. This is underpinned by the strength of our retail convenience partnerships, technology such as our advanced fuels and use of digital technology, as well as our customer relationships. This differentiation enables our growth in existing markets and supports our growth plans in new material markets such as Mexico, India, Indonesia and China. During 2018 we continued our expansion in Mexico with 440 BP-branded sites operational at the end of the year. In the fourth quarter of 2018 we also opened our first retail sites in Indonesia. See Glossary 31 Strategic report – performanceBP Annual Report and Form 20-F 2018We have a clear strategy and focused activity set for the transition to a lower carbon and digitally enabled future. We are actively implementing and developing new offers and business models centred around digital and advanced mobility trends. In 2018 we acquired Chargemaster, the operator of the UK’s largest electric vehicle charging network and invested in StoreDot, a leading developer of ultra-fast charging battery technology and FreeWire, a manufacturer of mobile rapid charging systems for electric vehicles. Our ambition is to roll out more than 2,000 additional charging points in the UK, bringing the total to around 9,000 by 2021, including more than 400 new ultra-fast chargers at our retail forecourts – see page 42. These investments and our differentiated fuels and convenience offers support BP’s aim to become the leading fuel provider for both conventional and electric vehicles. Fuels marketing performance in 2018 was significantly higher compared with 2017, reflecting the benefits from our strategic improvement programmes, enabling improved margin capture and supply chain optimization. Our convenience partnership model is now in around 1,400 sites across our network, with more than 460 sites in Germany with our REWE to Go® offer. Compared with 2016, fuels marketing performance in 2017 was higher, reflecting continued earnings growth supported by higher premium fuel volumes, and the continued roll out of our convenience partnership model.. thousand barrels per day Aviation Our Air BP business is one of the world’s largest suppliers of aviation fuels and services, selling fuel to commercial airlines, the military and general aviation customers at around 800 locations across more than 50 countries. We have marketing sales of more than 430,000 barrels per day. Air BP’s services include the design, build and operation of fuelling facilities, technical consultancy and training, supporting customers to meet their lower carbon goals and digital fuelling solutions to increase efficiency and reduce risk. Our Air BP business is differentiated through its strong market positions, brand strength, partnerships, technology and customer relationships. Our strategy is to maintain a strong presence in our core geographies of Australia, New Zealand, Europe, the Middle East and the US, while expanding into major growth markets that offer long-term competitive advantages, such as Asia, Africa and Latin America. In 2018 we continued to develop new offers and solutions in response to the needs of our customers. This included a collaboration with Neste, a leading producer of renewable products, to advance the supply of sustainable aviation fuels. We also launched the world’s first commercially deployed airfield automation system that actively helps prevent misfuelling. This digital platform for operators and airports provides an integrated, real-time, global solution to strengthen safety barriers and mitigate risks during the fuelling process. Sales volumes Marketing salesa Trading/supply salesb Total refined product sales Crude oilc Total 2018 2,736 3,194 5,930 2,624 8,554 2017 2,799 3,149 5,948 2,616 8,564 2016 2,825 2,775 5,600 2,169 7,769 Oil 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: a Marketing sales include branded and unbranded sales of refined fuel products and lubricants to both business-to-business and business-to-consumer customers, including service station dealers, jobbers, airlines, small and large resellers such as hypermarkets as well as the military. b Trading/supply sales are fuel sales to large unbranded resellers and other oil companies. c Crude oil sales relate to transactions executed by our integrated supply and trading function, primarily for optimizing crude oil supplies to our refineries and in other trading. 2018 includes 102 thousand barrels per day relating to revenues reported by the Upstream segment. Retail sitesd US Europe Rest of world Total Number of BP-branded retail sites 2018 7,200 8,200 3,300 18,700 2017 7,200 8,100 3,000 18,300 2016 7,100 8,100 2,800 18,000 d 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. 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, it seeks 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 29 and the range of contracts used is described in Glossary – commodity trading contracts on page 315. 32 BP Annual Report and Form 20-F 2018Our lubricants business We manufacture and market 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. 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. Our strategy is to focus on our premium lubricants and growth markets while leveraging our strong brands, technology and customer relationships – all of which are sources of differentiation for our business. With 65% of profit generated from growth markets and 46% of our sales from premium grade lubricants, we have a strong base for further expansion and sustained profit growth. In 2018 we significantly strengthened our relationship with Renault through the continuation of our Renault Formula 1 sponsorship with Renault Sport Racing, and are exploring new opportunities to work globally with the Renault-Nissan-Mitsubishi Alliance. This includes collaborating in a number of areas including fuel and lubricants supply and the joint development of advanced mobility solutions and new technologies. We have a robust pipeline of technology development through which we seek to respond to engine developments and evolving consumer needs and preferences, including lower carbon options. We apply our expertise to create differentiated, premium lubricants and high- performance fluids for customers in on-road, off-road, sea and industrial applications. In 2018 we extended the roll out of Castrol EDGE BIO-SYNTHETIC into China, an engine oil that uses 25% plant-derived oil compounds while delivering a high level of performance. The lubricants business delivered an underlying RC profit before interest and tax that was lower than 2017. The 2018 results reflected continued premium brand growth, more than offset by the adverse lag impact of increasing base oil prices, as well as adverse foreign exchange rate movements. The 2017 results reflected growth in premium brands and growth markets, offset by the adverse lag impact of increasing base oil prices. Our petrochemicals business Our petrochemicals business manufactures and markets three main product lines: purified terephthalic acid (PTA), paraxylene (PX) and acetic acid. These have a large range of uses including polyester fibre, food packaging and building materials. We also produce a number of other specialty petrochemicals products. In addition, we manufacture olefins and derivatives at Gelsenkirchen and solvents at Mülheim in Germany, the income from which is reported in our fuels business. Along with 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. Our strategy is to grow our underlying earnings and ensure the business is resilient to margin volatility, positioning ourselves to capture growth and investment opportunities in an attractive and growing market. We do this through the execution of our business improvement programmes which include operational efficiency, deploying our industry-leading proprietary technology, commercial optimization and competitive feedstock sourcing. We also aim to grow our third-party technology licensing income to create additional value. We continue to work on reducing our carbon footprint through the application of our proprietary technologies, and are assessing further opportunities to advance the circular economy in the chemicals and plastics sector. In 2018 the petrochemicals business delivered an underlying RC profit before interest and tax that was higher compared with 2017 – which in turn was higher than 2016. The 2018 result reflected an improved margin environment, increased margin optimization and continued cost management focus, partially offset by a higher level of turnaround activity and the divestment of our 50% shareholding in the SECCO joint venture, which completed in the fourth quarter of 2017. Compared with 2016, the higher result in 2017 reflected an improved margin environment, higher margin optimization, the benefits from our efficiency programmes and a lower level of turnaround activity. This was partially offset by the impact of the divestment of our interest in the SECCO joint venture. Our petrochemicals production of 11.9 million tonnes in 2018 was lower than 2017 and 2016 (2017 15.3mmte, 2016 14.2mmte) due to higher levels of turnaround activity and the divestment of our interest in the SECCO joint venture in 2017. Our technology remains a significant source of competitive advantage. In 2018 we secured six new licensing agreements out of the 10 PTA and PX licences announced globally. In 2018 we also signed a heads of agreement with SOCAR to evaluate the creation of a joint venture to build and operate a world-scale petrochemicals complex in Turkey. This facility would be the largest and most competitive integrated PTA, PX and aromatics complex in the western hemisphere. See Glossary 33 Strategic report – performanceBP Annual Report and Form 20-F 2018Rosneft Rosneft is the largest oil company in Russia, with a strong portfolio of current and future opportunities. Russia has one of the largest and lowest-cost hydrocarbon resource bases in the world and its resources play an important role in long-term energy supply to the global economy. 19.75% BP’s shareholding in Rosneft 8,163 1.1 million barrels of oil equivalent – BP share of Rosneft proved reserves million barrels of oil equivalent per day – BP share of Rosneft hydrocarbon production (2017 7,864mmboe) (2017 1.1mmboe/d) 18 refineries – owned or hold a stake in 2.33 million barrels of oil refined per day >2,960 retail service stations, in Russia and abroad (2017 18) (2017 2.29mmb/d) (2017 >2,960) BP share of Rosneft dividend ($ million)* 2018 2017 2016 2015 2014 420 200 124 190 332 271 693 Interim Annual for previous year, less interim *Net of withholding taxes. New fuels 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 is the leading Russian refining company based on throughput. It owns and operates 13 refineries in Russia, and also holds stakes in three refineries in Germany, one in India and one in Belarus. Downstream operations include jet fuel, bunkering, bitumen and lubricants. Rosneft also owns and operates Rosneft-branded retail service stations, as well as BP-branded sites operating under a licensing agreement. Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is wholly owned by the Russian government. Rosneftegaz’s shareholding in Rosneft is 50% plus one share. 2018 summary • BP received $620 million, net of withholding taxes, (2017 $314 million, 2016 $332 million), representing its share of Rosneft’s dividends. • Rosneft implemented a new dividend policy in 2017, which provides for a target level of dividends of no less than 50% of IFRS net profit, and a target frequency of dividend payments of at least twice a year. • Rosneft and BP launched a new range of fuels featuring ACTIVE technology at all BP retail service stations in Russia. • BP remains committed to our strategic investment in Rosneft, while complying with all relevant sanctions. 34 BP Annual Report and Form 20-F 2018BP’s strategy in Russia Our strategy is to work in co-operation with Rosneft to increase total shareholder return. This comprises support for our shareholding and partnering with Rosneft in building a material business in addition to the shareholding. This strategy is implemented through our activities in the following areas. Rosneft Board of Directors Collaboration BP has a 19.75% shareholding and two directors on the 11-person board. Bob Dudley and Guillermo Quintero are currently elected to those roles. BP collaborates on the provision of technical, HSE and non-technical services on a contractual basis to improve functional asset performance. See Innovation in BP on page 41. Joint ventures BP partners with Rosneft to generate incremental value from joint ventures and associates that are separate from BP’s core 19.75% shareholding. • In December 2017 Rosneft and BP announced an agreement to develop resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets in northern Russia. In the second quarter of 2018 BP acquired a 49% stake in LLC Kharampurneftegaz and in December 2018 the licence transfer was completed. BP’s interest is reported through the Upstream segment. • BP holds a 20% interest in Taas-Yuryakh Neftegazodobycha (Taas), together with Rosneft (50.1%) and a consortium comprising Oil India Limited, Indian Oil Corporation Limited and Bharat PetroResources Limited (29.9%). Taas completed commissioning of the main project facilities for the Srednebotuobinskoye oil and gas condensate field. This was the second of six BP major projects started up in 2018. The project was delivered under budget and on schedule. In 2018 BP received the first dividends from Taas of $48 million, net of withholding taxes. BP’s interest in Taas is reported through the Upstream segment. • Rosneft (51%) and BP (49%) jointly own Yermak Neftegaz LLC (Yermak). This joint venture conducts onshore exploration in the West Siberian and Yenisei-Khatanga basins and currently holds seven exploration and production licences. The venture has also carried out further appraisal work on the Baikalovskoye field, an existing Rosneft discovery in the Yenisei-Khatanga area of mutual interest. In September Rosneft and BP also agreed to jointly explore two additional oil and gas licence areas located in Sakha (Yakutia) republic of the Russian Federation via Yermak. Completion of the deal, subject to external approvals, is expected in 2019. BP’s interest in Yermak is reported through the Upstream segment. Taas – one of BP’s 6 major project start-ups in 2018 See Glossary 35 Strategic report – performanceBP Annual Report and Form 20-F 2018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 17 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) 2018 2,288 (67) 2,221 95 2,316 $ million 2016 643 (53) 590 (23) 567 2017 923 (87) 836 – 836 $ per barrel 69.89 52.84 41.68 Balance sheet Investments in associates c (as at 31 December) 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) 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 $(5) million (2017 $(2) million, 2016 $3 million) of foreign exchange (gain)/losses arising on the dividend received. Crude oild Natural gas liquids Total liquidsf 2018 2017 $ million 2016 10,074 10,059 8,243 2018 2017 2016 919 4 923 1,285 1,144 900 4 904 1,308 1,129 836 4 840 1,279 1,060 5,539 154 5,693 5,330 5,402 65 131 5,533 5,395 14,325 13,522 11,900 7,447 7,864 8,163 Natural gas (billion cubic feet)g Total hydrocarbons (mmboe) c See Financial statements – Note 17 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 356 million barrels of liquids (338 million barrels at 31 December 2017 and 347 million barrels at 31 December 2016) in respect of the 6.32% non-controlling interest (6.31% at 31 December 2017 and 6.58% at 31 December 2016) in Rosneft held assets in Russia including 24 million barrels (6 million barrels at 31 December 2017 and 6 million barrels at 31 December 2016) held through BP’s interests in Russia other than Rosneft. g Includes 1,211 billion cubic feet of natural gas (306 billion cubic feet at 31 December 2017 and 300 billion cubic feet at 31 December 2016) in respect of the 8.60% non-controlling interest (2.30% at 31 December 2017 and 2.53% at 31 December 2016) in Rosneft held assets in Russia including 480 billion cubic feet (2 billion cubic feet at 31 December 2017 and 1 billion cubic feet at 31 December 2016) held through BP’s interests in Russia other than Rosneft. Market price The price of Urals delivered in North West Europe (Rotterdam) averaged $69.89/bbl in 2018. The discount to dated Brent was $1.42/bbl, similar to 2017 ($1.35/bbl). Financial results Replacement cost (RC) profit before interest and tax for the segment included a non-operating charge of $95 million for 2018 and a non- operating gain of $23 million for 2016, whereas the 2017 results did not include any non-operating items. After adjusting for non-operating items, the increase in the underlying RC profit before interest and tax compared with 2017 primarily reflected higher oil prices and favourable foreign exchange, partially offset by adverse duty lag effects. Compared with 2016, the 2017 result was affected by higher oil prices partially offset by adverse foreign exchange effects. The 2017 result also benefited from a $163-million gain representing the BP share of a voluntary out-of-court settlement between Sistema, Sistema-Invest and the Rosneft subsidiary, Bashneft. See also Financial statements – Notes 17 and 32 for other foreign exchange effects. 36 See Glossary BP Annual Report and Form 20-F 2018 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. Sales and other operating revenuesa RC profit (loss) before interest and tax Gulf of Mexico oil spill Other RC profit (loss) before interest and tax Net adverse 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 b a Includes sales to other segments. b A reconciliation to GAAP information at the group level is provided on page 275. The replacement cost (RC) loss before interest and tax for the year ended 31 December 2018 was $3,521 million (2017 $4,445 million, 2016 $8,157 million). The 2018 result included a net charge for non-operating items of $1,963 million, including Gulf of Mexico oil spill related costs of $714 million (non-operating items in 2017 $2,847 million, 2016 $6,919 million). For further information, see 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 2018 was $1,558 million, similar to prior year (2017 $1,598 million, 2016 $1,238 million). Outlook Other businesses and corporate annual charges, excluding non- operating items, are expected to be around $1.4 billion in 2019. 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 2018 BP had three time-chartered vessels to support operations in Alaska and 34 BP-operated and 22 time-chartered vessels for our international oil and gas shipping operations. In 2018 three new technically advanced LNG tankers were delivered into the BP-operated fleet, with a further three to be delivered in 2019. All vessels conducting BP shipping activities are required to meet BP approved health, safety, security and environmental standards. S t r a t e g c i r e p o r t – p e r f o r m a n c e 2018 1,678 (714) (2,807) (3,521) 714 1,249 1,963 (1,558) 332 2017 1,469 (2,687) (1,758) (4,445) 2,687 160 2,847 (1,598) 339 $ million 2016 1,667 (6,640) (1,517) (8,157) 6,640 279 6,919 (1,238) 229 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 holds foreign exchange and interest rate products in the financial markets to hedge group exposures. In addition, treasury generates incremental value through optimizing and managing cash flows and the short-term investment of operational cash balances. For further information, see Financial statements – Note 29. 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. BP Annual Report and Form 20-F 2018 See Glossary 37 BP Annual Report and Form 20-F 2018 Alternative energy 2.8 million tonnes of CO2 equivalent avoided in 2018. BP has been in the renewable energy business for more than 20 years. We remain one of the largest operators among our peers and we’re expanding in areas where we see opportunities for growth. Biofuels We believe that biofuels offer one of the best large-scale solutions to reduce emissions in the transportation system. Renewables are the fastest-growing energy source in the world today and we estimate that they could provide at least 15% of the global energy mix by 2040. As part of our approach to building our alternative energy business, we aim to grow our existing businesses and to develop new businesses and partnerships to deliver competitive value in the fastest-growing energy sector. Solar energy Solar could generate 12% of total global power by 2040, in a scenario based on recent trends. That could grow to 21% in a scenario consistent with the Paris climate goals. We have a 43% share in Lightsource BP and plan to invest $200 million over a three-year period. Lightsource BP aims to play a vital role in shaping the future of global energy delivery by developing substantial solar capacity around the world, and we are working with Lightsource BP to expand its global presence. Lightsource BP has doubled the number of countries where it has a presence since December 2017 – see Climate change on page 45. We produce ethanol from sugar cane in Brazil, which has life-cycle greenhouse gas emissions around 70% lower than conventional transport fuels. In 2018 our three sites produced 765 million litres of ethanol equivalent. Brazil is one of the world’s largest markets for ethanol fuel. In order to better connect our ethanol production with the country’s main fuels markets, we established a joint venture in 2018 with Copersucar – one of the world’s leading ethanol and sugar traders. This includes operating a major ethanol storage terminal in Brazil’s main fuels distribution hub. Our Tropical and Ituiutaba biofuels sites are certified to Bonsucro, an independent standard for sustainable sugar cane production. We are working towards certification for Itumbiara in 2019. Our strategy is enabled by: • Safe and reliable operations – continuing to drive improvements in safety performance. • Driving quality and improved efficiency in our feedstock – concentrating our efforts in Brazil, which has one of the most cost-competitive biofuel sources in the world. • Domestic and international markets – selling ethanol and sugar domestically in Brazil and to international markets such as the US. Renewable products Butamax®, our 50/50 joint venture with DuPont, has developed technology that converts sugars from corn into bio-isobutanol, an energy-rich bio product. Bio-isobutanol has a wide variety of applications. For example, it can be used in the production of paints, coatings and lubricant components. It can also be blended with gasoline at higher concentrations than ethanol, which can be transported through existing fuel pipelines and infrastructure. Butamax® has upgraded its ethanol facility in Kansas to produce bio-isobutanol. 38 See Glossary BP Annual Report and Form 20-F 2018Biopower We create biopower from bagasse, the fibre that remains after crushing sugar cane stalks. In 2018 our three biofuels manufacturing facilities produced around 892GWh of electricity – enough renewable energy to power all of these sites, with the remaining 70% exported to the local electricity grid. This is a low carbon power source, with part of the CO2 emitted from burning bagasse offset by the CO2 absorbed by sugar cane during its growth. Wind energy BP has significant interests in onshore wind energy in the US. We operate 10 sites in seven states and hold an interest in another facility in Hawaii. Together they have a net generating capacity of just over 1,000MW. At our Titan 1 wind energy site in South Dakota, we’ve partnered with Tesla to test how effectively wind energy can be stored – see Harnessing battery power on page 42. In 2018 we divested three wind energy operations in Texas, as part of a broader restructuring programme designed to optimize our US wind portfolio for long-term growth. More information Low carbon ambitions We have set targets and aims to reduce emissions in our operations, improve our products to help customers reduce their emissions and create low carbon businesses – see pages 46-48. 45,000km travelled a day Using technology in biofuels Our SmartLog programme is helping improve performance across our three biofuels sites in Brazil. SmartLog is designed to increase efficiency across sugar cane cutting, loading and transportation operations – and consequently reduces the costs involved. Every day across our sites we make around 800 trips covering 45,000 kilometres. This takes place in remote locations with poor network and communications coverage. Using a combination of mobile satellite technology, sensors and radios we can connect our people and their vehicles to a central control room. Here we receive 24-hour real-time information about what’s happening in the field to help manage activities remotely, as well as monitoring and analysing behaviours and giving advice or intervening about safety or efficiency. Automation guides workers on improvements such as how to prioritize harvest activities and indicates the optimum speed for harvesters to run at based on prevailing conditions. Since introducing SmartLog in 2018, we’ve reduced equipment needed by 20% and our remote monitoring is helping to reinforce our safety culture in the field. It has also helped to lower emissions as the reduction in equipment means we use less diesel. See Glossary 39 Strategic report – performanceBP Annual Report and Form 20-F 2018Innovation in BP Across the business we face the dual challenge of meeting society’s need for more energy, while at the same time working to reduce carbon emissions. Our industry is changing rapidly, and the energy mix is shifting towards lower carbon sources, driven by technological advances and growing environmental concerns. Technology is ever-present in all that we do – from safely discovering and recovering oil and gas, to renewable energy and lower carbon fuels and products. And digital, big data and advanced technologies, as well as an innovative mindset, are driving rapid development of new ways to tackle emissions and improve efficiency at BP. We also invest in high-tech companies to help accelerate and commercialize new technologies, products and business models. 8 major technology centres in the US, UK, Asia and Germany BPme available in >6,000 retail sites A new way to pay Customers in six countries now have the option to pay for fuel from their vehicle using BPme. And since its launch our smartphone app has been downloaded more than one million times. Using a phone’s GPS signal BPme locates the nearest BP site and provides details of opening times and facilities. Customers can use the app to activate their fuel pump and pay from inside their car. BPme is designed to appeal to people who don’t want to leave children, pets or valuables alone while they go to pay for fuel, and it saves time queuing at the checkout. Over the coming months we plan to roll it out to new markets and introduce the option to order coffee and receive offers and discounts from the app. Group highlights $429 million invested in research and development ~$200 million used to develop options for new lower carbon businesses Collaborations with innovative academic programmes >4,000 24 hours to 20 minutes with APEX granted and pending patent applications held by BP and its subsidiaries throughout the world 150 million+ data points a day with POA bp.com/technology 40 BP Annual Report and Form 20-F 2018 S t r a t e g i c r e p o r t – p e r f o r m a n c e A clearer view below the earth Below land and sea, in challenging terrains and conditions, BP’s developments in seismic technology are allowing us to see deeper into the earth with better accuracy than ever before. And the better we can see, the easier and safer it is to find oil and gas and unlock more of it from our existing assets. One of the big challenges for conventional seismic sources when surveying offshore in the Gulf of Mexico is the ability to look deep into the earth without the thick horizontal salt layers above distorting the images captured. To help tackle this we designed and built Wolfspar. The ultra-low-frequency system works with our other advanced recording technologies to help overcome the subsalt imaging challenge. We believe the clearer view will help reduce uncertainty about where the resources are, resulting in more drillable targets in the region. Having completed a series of successful proof-of-concept tests, BP plans to move to industrialize the technology with our strategic seismic partners, so that it can be used across our global subsurface portfolio. We also reached a major milestone in the development of an innovative land seismic recording system, in partnership with Rosneft 01010101 10 Wolfspar ~1,000km of data acquired in 143 hours and Schlumberger. The project aims to move beyond the existing limitations of bulky, heavy and expensive onshore seismic equipment, and at the same time provide better images of the reservoir. Following successful initial field trials in Norway and Abu Dhabi in 2017, the ‘nimble node‘ system was used to safely acquire 3D seismic data in the challenging climate of West Siberia in 2018. Early images show better data quality compared to conventional equipment, with fewer people and vehicles needed as well as a simplified derigging process – which is otherwise very time consuming and challenging. The new node is the lightest, smallest and lowest-cost system in the world, and the project is on course to help change how future seismic is acquired. Its development will be completed with a large-scale field trial in early 2019. Soon after this we plan to begin the first commercial survey. Intelligent operations New technologies are helping us build intelligent operations throughout our business. Across all our upstream-operated assets, we are creating ‘virtual copies’ of our production systems using APEX – our highly sophisticated simulation, surveillance and optimization toolkit. The technology recreates every element of a well network in digital ‘twin’ form, and works in near real time to gather data about every well across our business. It can pinpoint where efficiency can be improved and helps our production engineers run simulations in seconds. With APEX, a full-field optimization that used to take hours now takes a few minutes. Engineers from around the world are proactively sharing their know-how and expertise across our global operations, as they embed the use of APEX and start benefiting from it. And following our successful pilot in the Atlantis field, we are now using Plant Operations Advisor (POA), which was developed in partnership with BHGE, on all four BP-operated platforms in the US Gulf of Mexico. The cloud-based tool gives performance information on around 1,200 important pieces of process equipment – with more than 150 million data points analysed every day. If the system identifies an issue with any of the equipment, it sends an alert to our engineers so they can respond quickly. By pinpointing anomalies in operations and identifying the causes, problems that might once have taken hours for engineers to work through manually can be diagnosed in minutes. Following its success in the Gulf of Mexico, we now plan to use the tool at more than 30 upstream locations worldwide by the end of 2019. Robot inspections Inspection robots are helping us deliver against our strategic priority of modernizing and transforming BP. At our Cherry Point refinery in the US we’ve adapted a robotic solution that allows us to inspect equipment such as the hydrocracker reactor. The robot uses ultrasound technology to spot microscopic cracks in its walls by crawling along the reactor. This process would have previously taken more than 23 work hours, with engineers working inside the hydrocracker unit during a planned shutdown. Now they can gather the same information in just one hour with robots. 23 hours to 1 hour BP Annual Report and Form 20-F 2018 41 01010101010101010101 10101010101 01010101010101010101 01010101010101010101 01010101010101101 01010101010101010101 0101010101 0101010101 Venturing and low carbon across multiple fronts Harnessing battery power >6,500 UK charging points with BP Chargemaster in 2018 12 million electric vehicles projected on UK roads by 2040 in the BP Energy Outlook . As we support the transition to a lower carbon future and to help meet our customers’ changing needs, we’re making investments in electric vehicle technology and infrastructure. Our work aims to support electric vehicle adoption by tackling issues such as poor battery life and slow charging times. To allow us to respond rapidly to demand for charging facilities at our forecourts, we invested $5 million in FreeWire. The US-based company manufactures mobile rapid charging systems, which we successfully piloted at a BP retail site in the UK, and are now exploring options to offer FreeWire’s innovative charging services across the retail networks. We also invested $20 million in StoreDot, a company that develops ultra-fast charging battery technology for mobile and industrial markets. We anticipate the technology will be used in mobile devices by 2020 and BP will be working with them to help transfer this technology to electric vehicles. StoreDot aims to bring recharging times down to five minutes, making the time it takes to charge an electric vehicle similar to that of filling a tank. BP now has more than 6,500 charging points in the UK, through BP Chargemaster. The business combines the complementary expertise, experience and assets of BP and Chargemaster and is an important step towards offering widened access to fast and ultra-fast charging at BP sites across the UK. The chargers will start to become available across our UK forecourts throughout 2019. Storing wind energy We’ve partnered with Tesla to test how effectively wind energy can be stored at our Titan 1 wind energy site in South Dakota. The electricity captured is then available for the site to use whenever we need it – even when the wind isn’t blowing. The pilot will help develop valuable insights for energy storage applications across our diverse portfolio. StoreDot – aim to reduce electric vehicle recharging time to five minutes. 42 BP Annual Report and Form 20-F 2018 BP Annual Report and Form 20-F 2018 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. BP Sustainability Report 2018 publishes April S t r a t e g c i r e p o r t – p e r f o r m a n c e Our 2018 sustainability focus areas These sustainability issues are the ones that could impact our business the most and that are of greatest interest to our stakeholders. > Safety and security > Climate change > Managing our impacts > Value to society > Ethical conduct > Our people Process safety events (number of incidents) 150 100 50 2014 2015 2016 2017 2018 Tier 1 Tier 2 Recordable injury frequency (workforce incidents per 200,000 hours worked) 0.8 0.6 0.4 0.2 Workforce Employees Contractors 2014 0.31 0.27 0.34 2015 0.24 0.20 0.28 2016 0.21 0.19 0.22 2017 0.22 0.20 0.23 2018 0.20 0.15 0.23 American Petroleum Institute US benchmarka International Association of Oil & Gas Producers benchmarka a API and IOGP 2018 data reports are not available until May 2019. Safety and security Safety is our number one priority and a core value. Our aim is to have no accidents, no harm to people and no damage to the environment. We are working to continuously embed and improve personal and process safety and operational risk management across BP and to strengthen our safety management. Our approach builds on our experience, including learning from incidents, operations audits, annual risk reviews and sharing lessons learned with our industry peers. Managing safety BP-operated businesses are responsible for identifying and managing operating risks and bringing together people with the right skills and competencies to address them. Our safety and operational risk team works alongside BP-operated businesses to provide oversight and technical guidance, while our group audit team visits sites on a risk-prioritized basis to check how they are managing risks. Our operating management system Our operating management system (OMS) is a group-wide framework designed to help us manage risks in our operating activities and drive performance improvements. It brings together BP requirements on health, safety, security, the environment, social responsibility and operational reliability, as well as related issues, such as maintenance, contractor relations and organizational learning, into a common management system. Our OMS also helps us improve the quality of our activities by setting a common framework that our operations must work to. We review and amend these requirements from time to time to reflect our priorities. Any variations in the application of OMS, in order to meet local regulations or circumstances, are subject to a governance process. Recently acquired operations need to transition to our OMS. See page 44 for information about contractors and joint arrangements . Preventing incidents We carefully plan our operations, with the aim of identifying potential hazards and having rigorous operating and maintenance practices applied by capable people to manage risks at every stage. We design our new facilities in line with process safety – the application of good design and engineering principles. We track our safety performance using industry metrics such as the American Petroleum Institute recommended practice 754 and the International Association of Oil & Gas Producers recommended practice 456. BP Annual Report and Form 20-F 2018 See Glossary 43 Tier 1 process safety events a Tier 2 process safety eventsb Oil spills – numberc Oil spills contained Oil spills reaching land and water Oil spilled – volume (thousand litres) Oil unrecovered (thousand litres) 2018 16 56 124 63 57 538 131 2017 18 61 139 81 58 886 265 2016 16 84 149 91 58 677 311 a Tier 1 process safety events 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. b Tier 2 events are those of lesser consequence. c Number of spills greater than or equal to one barrel (159 litres, 42 US gallons). In 2018 we saw a reduction in the number of tier 1 and tier 2 process safety events. We investigate incidents including near misses. And we use leading indicators, such as inspections and equipment tests, to monitor the strength of controls to prevent incidents. We also use techniques that help teams to analyse and redesign tasks to reduce the chance of mistakes occurring. Keeping people safe All our employees and contractors have the responsibility and the authority to stop unsafe work. Our safety rules guide our workers on staying safe while performing tasks with the potential to cause most harm. The rules are aligned with our OMS and focus on areas such as working at heights, lifting operations and driving safety. We monitor and report on key workforce personal safety metrics in line with industry standards. We include both employees and contractors in our data. Tragically we suffered one fatality in 2018. In our lubricants business a heavy goods driver working for one of our contractors in the US was struck by a passing vehicle while checking a tyre. We are deeply saddened by this loss and are working closely with our contractors to continue to improve safety and to seek to prevent injuries in our work together. Recordable injury frequencyd Day away from work case frequencye Severe vehicle accident rate 2018 0.20 0.048 0.04 2017 0.22 0.055 0.03 2016 0.21 0.051 0.05 d Incidents that result in a fatality or injury per 200,000 hours worked. e Incidents that result in an injury where a person is unable to work for a day (shift) or more per 200,000 hours worked. We saw an overall decrease in our recordable injury frequency and day away from work case frequency. Our goals stay the same – to have no accidents, no harm to people and no damage to the environment. There is always more we can do and we remain focused on achieving better results today and in the future. 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, our Brazilian biofuels business is spread across geographically remote locations, so we introduced a digital platform to connect our people and vehicles to a central control room. This provides 24-hour, real-time information about what’s happening, helps us monitor and analyse behaviour and aids improvements around learning and safety. We also use in-vehicle monitoring systems and cameras to improve transportation safety. Emergency preparedness The scale and spread of BP’s operations means we must be prepared to respond to a range of possible disruptions and emergency events. 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. 44 See Glossary Cyber threats Cyber attacks are on the rise and our industry is subject to evolving risks from a variety of cyber threat actors, including nation states, criminals, terrorists, hacktivists and insiders. We have experienced threats to the security of our digital infrastructure, but none of these had a significant impact on our business in 2018. We have a range of measures to manage this risk, including the use of cyber security policies and procedures, security protection tools, ongoing detection and monitoring of threats, and testing of response and recovery procedures. To encourage vigilance among our employees, our cyber security training programme covers topics such as email phishing and the correct classification and handling of our information. We collaborate closely with governments, law enforcement and industry peers to understand and respond to new and emerging threats. Security and response We monitor for hostile actions that could harm our people or disrupt our operations, focusing on areas affected by political and social unrest, terrorism, armed conflict or criminal activity. We take steps to help people stay safe when they are travelling on business. Our 24-hour response information centre monitors global events and related developments which means we can assess the safety of our people and provide timely advice if there is an emergency. We run exercises and drills to test our procedures to help ensure our people are prepared in the event of an emergency. We conducted a two-day oil spill response drill in the UK North Sea involving more than 200 people, including regulators. This was designed to test plans as part of our annual crisis and continuity management programme. We also held a number of large-scale exercises in the US. Working with contractors and partners More than half of the hours worked by BP are carried out by contractors. Through bridging and other documents, we define the way our safety management system co-exists with those of our contractors to manage risk on a site. For our contractors facing the most serious risks, we conduct quality, technical, health, safety and security audits before awarding contracts. Once they start work, we continue to monitor their safety performance. Our OMS includes requirements and practices for working with contractors. Our standard model contracts include health, safety and security requirements. We expect and encourage our contractors and their employees to act in a way that is consistent with our code of conduct and take appropriate action if those expectations, or their contractual obligations, are not met. Our partners in joint arrangements In joint arrangements where we are the operator, our OMS, code of conduct and other policies apply. We aim to report on aspects of our business where we are the operator – as we directly manage the performance of these operations. We monitor performance and how risk is managed in our joint arrangements, whether we are the operator or not. Where we are not the operator, our OMS is available as a reference point for BP businesses when engaging with operators and co-venturers. We have a group framework to assess and manage BP’s exposure related to safety, operational and bribery and corruption risk from our participation in these types of arrangements. Where appropriate, we may seek to influence how risk is managed in arrangements where we are not the operator. BP Annual Report and Form 20-F 2018 Climate change The world needs more energy but with fewer carbon emissions. BP is playing an active role in meeting this dual challenge. The Taskforce for Climate-related Financial Disclosures (TCFD) was established by the Financial Stability Board with the aim of improving the reporting of climate-related risks and opportunities. We support this aim. Our reporting provides information supporting the principles of the TCFD recommended disclosures. See bp.com/tcfd. Strategy Our strategy is designed to grow shareholder value while also helping to meet the dual challenge. We believe it is consistent with the climate goals of the Paris Agreement, which calls for the world to rapidly reduce greenhouse gas emissions in the context of sustainable development and eradicating poverty. A key element of our strategy is our ‘reduce, improve, create’ framework, where we have set measurable, near-term targets for reducing greenhouse gas emissions in our own operations and ambitions for improving products to help our customers and consumers lower their emissions, and creating low carbon businesses. See page 46. In 2019 we are supporting a resolution from a group of institutional investors to describe in our corporate reporting how our strategy is Climate governance BP’s governance framework applies equally to the management of the various aspects of climate change and the transition to a lower carbon economy. In addition to the oversight provided by the executive team, the board and relevant committees, various groups consistent with the Paris goals. Subject to shareholder approval at our annual general meeting, we will provide more information on this in future reports. Risk management We recognize the significance of the energy transition and the risks and opportunities it presents. As part of their review of BP’s strategy, the board and executive team considered risks and opportunities associated with climate change and the energy transition, in the context of different paths expressed in the BP Energy Outlook – which looks at long-term trends and develops projections for world energy markets over the next two decades. Under BP’s risk management policy and the associated risk management procedures, our operating businesses are responsible for identifying and managing their risks. Risks which may be identified include potential effects on operations at the asset level, performance at the business level and developments at the regional level from extreme weather or the transition to a lower carbon economy. As part of our annual planning process we review the group’s principal risks and uncertainties. Climate change and the transition to a lower carbon economy has been identified as a principal risk (see page 55). This covers various aspects of how risks associated with the energy transition could manifest such as in the policy, legal and regulatory environment, technological developments and market changes. Similarly, physical climate-related risks such as extreme weather are covered in our principal risks related to safety and operations. See page 53 for more information on how we manage risk. and committees in BP bring together cross-segment and cross-functional expertise of relevance to this area, including those set out below. BP governance framework See page 69 Renewal committee Reviews strategic, commercial and investment decisions outside of core activity and related to new lines of business. Chaired by our deputy chief executive. New energy frontiers steering committee Oversees strategy and development of growth opportunities in low carbon business models that can be scaled up to create new businesses for BP. Chaired by our deputy chief executive. Carbon steering group Focuses on strategy, policy, performance oversight and collaboration relating to carbon management activities across the group. Chaired by our vice president of carbon management. Upstream carbon steering committee Focuses on the delivery of lower carbon plans in the Upstream. Chaired by our chief operating officer of production, transformation and carbon, Upstream. Downstream advancing the energy transition committee Develops and drives the implementation of advancing the energy transition in the Downstream. Chaired by our head of technology, Downstream and BP chief scientist. Key: Executive-level committee Cross-functional committee Business and segment committee 45 Strategic report – performanceBP Annual Report and Form 20-F 2018 Our low carbon ambitions We aim to advance a low carbon future through what we call our ‘reduce, improve, create’ framework. We have set targets and aims to reduce emissions in our operations, improve our products to help customers reduce their emissions and create low carbon businesses. We are already in action and have made good progress in 2018 against these ambitions. See bp.com/sustainability for more information on the actions we are taking and bp.com/targets for specifics on our goals. Reducing emissions in our operations Improving our products We are targeting zero net growth in our operational emissions out to 2025. We aim to deliver this through sustainable greenhouse gas (GHG) emissions reductions totalling 3.5Mte by 2025, by targeting a methane intensity of 0.2% and, as necessary, with offsets to keep net emissions growth to zero. We are continuing to innovate with fuels, lubricants and chemicals that can help our customers and consumers lower their emissions. 2018 progress 2018 progress • Zero net growth in operational emissions. • 2.5Mte of sustainable GHG emissions reductions since the beginning of 2016. This includes actions to improve energy efficiency and reduce methane emissions and flaring. • Methane intensity of 0.2%. • Collaborated with Neste to explore opportunities to increase supply of sustainable aviation fuel. • Launched Castrol GTX ECO, made using a base oil blend of at least 50% re-refined base oil, in the US. • Gave UK drivers the option to offset the CO2 emissions from the fuel they buy from us, through our BPme fuel payment app. From waste to fuel We’ve invested in Fulcrum BioEnergy®, which is constructing the first commercial scale waste-to-fuels plant in the US. The facility aims to use technology, developed by BP and Johnson Matthey, to help convert household rubbish that would otherwise be sent to landfill, into fuel for transport. Fulcrum, in which BP owns an 8% interest, estimates that when it begins commercial operations, the plant will be able to convert around 175,000 tons of waste into about 11 million gallons of fuel each year. 175,000 tons of waste to 11 million gallons of fuel Detecting methane As a colourless and odourless gas – detecting leaks of methane can be challenging. For several years we’ve used hand-held infrared cameras to detect small leaks before they become larger ones. Improvements in technology now make it possible to quantify the emissions that these cameras detect, helping us to better target and prioritize our responses. We piloted this technology in Azerbaijan and the US in 2018 and plan to deploy the cameras more widely in 2019. 46 BP Annual Report and Form 20-F 2018Creating low carbon businesses We are building up our renewable energy portfolio – focusing on biofuels, biopower, wind and solar. And together with our dynamic venturing arm we are working on multiple fronts – through joint ventures, creative collaborations and new business models. 2018 progress • Invested $500 million in low carbon activities, such as FreeWire – which supports development of rapid mobile electric vehicle charging. • Worked with OGCI to help progress the Clean Gas Project, see page 48. Advancing solar Lightsource BP has doubled the number of countries where it has a presence since December 2017. Lightsource BP sites As at 31 December 2018 Belfast Wales Bath London UK Completed the UK’s biggest- ever unsubsidized solar power deal to supply AB InBev, the Budweiser brewer, with 100MW of solar power at its UK operations in South Wales and Lancashire. Australia Awarded the project to provide 105MW of solar power to Snowy Hydro, the country’s fourth-largest national energy retailer, through a 15-year power purchase agreement. US Agreed to bring 25MW of locally generated solar power to western US, through new collaborations in California and New Mexico over 20+ year terms. Brazil Announced plans to develop solar and smart energy storage solutions for Brazil’s domestic, commercial and industrial sectors. San Francisco Philadelphia Dublin and Limerick Amsterdam Milan Madrid Cairo Mumbai Chennai São Paulo Melbourne Sydney 5 new countries in 2018 Europe Extended operations into the Italian and Iberian renewable energy sectors. Egypt Formed a joint venture with Hassan Allam Utilities to develop and operate utility scale solar projects in Egypt. India Established EverSource Capital with Everstone to manage the Green Growth Equity Fund aiming to raise up to $700 million of investment in low carbon energy infrastructure projects across India. 47 Strategic report – performanceBP Annual Report and Form 20-F 2018Metrics We report direct and indirect greenhouse gas (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 and steam we import into our operations. There was a decrease in our direct GHG emissions in 2018. The primary reasons for this include actions taken by our businesses to reduce emissions in areas such as flaring, methane and energy efficiency as well as operational changes, such as increased gas being captured and exported to the liquefied natural gas facility in Angola. Greenhouse gas emissions (MteCO2e)a Operational controlb Direct emissions Indirect emissions BP equity sharec Direct emissions Indirect emissions 2018 2017 2016 48.8 5.4 46.5 5.7 50.5 6.1 49.4 6.8 51.4 6.2 50.1 6.2 a Our approach to reporting GHG emissions broadly follows the IPIECA/API/IOGP Petroleum Industry Guidelines for Reporting GHG Emissions. We calculate CO2 emissions based on the fuel consumption and fuel properties for major sources. We report CO2 and methane. We do not include nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur hexafluoride as they are not material to our operations and it is not practical to collect this data. b 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. c BP equity share data comprises 100% of emissions from subsidiaries and the percentage of emissions equivalent to our share of joint arrangements and associates , other than BP’s share of Rosneft. The ratio of our total GHG emissions reported on an operational control basis to gross production was 0.22teCO2e/te production in 2018 (2017 0.24teCO2e/te, 2016 0.24teCO2e/te). Gross production comprises upstream production, refining throughput and petrochemicals produced. part of the project. This is currently $40 per tonne of CO2 equivalent, with a stress test at a carbon price of $80 per tonne. Until late January 2019 we used these specific prices in industrialized countries, but have now expanded this to apply globally. Working with others We work with peers, non-governmental organizations and academic institutions to address the climate challenge. The Oil and Gas Climate Initiative (OGCI) – currently chaired by our group chief executive Bob Dudley – brings together 13 oil and gas companies to increase the ambition, speed and scale of the initiatives undertaken by its individual companies to help reduce manmade GHG emissions. OGCI announced a collective methane intensity target for member companies in 2018. The target aims to reduce the collective average methane intensity of the group’s aggregated upstream oil and gas operations to below 0.25% by 2025, compared with the baseline of 0.32% in 2017. See page 46 for information on BP’s methane intensity. BP is working with OGCI Climate Investments to help progress the UK’s first commercial full-chain carbon capture, use and storage project. The Clean Gas Project plans to capture CO2 from new efficient gas-fired power generation and transport it by pipeline to be stored in a formation under the southern North Sea. The infrastructure would also allow other industries in Teesside to store CO2 captured from their processes. The project, which is currently undergoing a feasibility study, could be in operation by the mid-2020s. Managing our impacts We work hard to avoid, mitigate and manage our environmental and social impacts over the life of our operations. Accrediting our lower carbon activities To reinforce our ambitions, we implemented our Advancing Low Carbon accreditation programme, which aims to inspire every part of BP to identify lower carbon opportunities. The way our businesses around the world understand and manage their environmental and social impacts is set out in our operating management system. This includes requirements on engaging with stakeholders who may be affected by our activities. To gain accreditation by BP, each activity must meet certain criteria, including delivering what we call a better carbon outcome. This means either reducing GHG emissions, producing less carbon than competitor or industry benchmarks, providing renewable energy, offsetting carbon produced, furthering research and technology to advance low carbon or enabling BP or others to meet their low carbon objectives. Deloitte conducts independent assurance on the Advancing Low Carbon activities, including assessing the application of BP’s process and criteria for accrediting activities, and GHG emissions offset and saved within the programme. A total of 52 activities met the criteria for accreditation or reaccreditation in 2019, up from 33 in 2018. These include emission reductions in our operations, carbon neutral products, more efficient ships, investments in electrification and support for low carbon technologies. See bp.com/advancinglowcarbon for details on the programme and Deloitte’s assurance statement. Calling for a price on carbon BP believes that well-designed carbon pricing by governments provides the right incentives for everyone – energy producers and consumers alike – to play their part in reducing emissions. It makes energy efficiency more attractive and makes lower carbon solutions, such as renewables and carbon capture, use and storage, more cost competitive. We use a carbon price when evaluating our plans for certain large new projects and also those for which emissions costs would be a material 48 See Glossary In planning our projects, we identify potential impacts from our activities in areas such as land rights, water use and protected areas. We use the results of this analysis to identify actions and mitigation measures and implement these in project design, construction and operations. For example, as part of our exploration activities in São Tomé and Príncipe, we are using underwater sound recorders and an autonomous vehicle to help understand the distribution and movement of marine mammals. The outcomes of this will inform our approach to planning for potential future activities. Every year our major operating sites review their performance and set local improvement targets. These can include measures on flaring, greenhouse gas emissions and the use of water. See page 44 for information on our oil spill performance. Water We review risks related to management of water in our portfolio each year, considering the local availability, quantity, quality and regulatory requirements. In our gas operations in Oman – an area where the availability of fresh water is extremely scarce – we withdraw brackish water under permit from a local underground aquifer that is only used for industrial purposes. We desalinate the water and use it for drilling and hydraulic fracturing. We completed a modelling study in 2018 to assess the sustainability of this water supply. The results of the study have been incorporated into a long-term water management plan to reduce water demand. Air quality We put measures in place to manage our air emissions, in line with regulations and industry guidelines designed to protect the health BP Annual Report and Form 20-F 2018 of local communities and the environment. In our shipping business, we introduced three new liquefied natural gas carriers to our fleet in 2018. The carriers are designed to use approximately 25% less fuel and emit less nitrogen oxides than our older ships. Hydraulic fracturing We aim to apply responsible practices to the design of our wells to mitigate potential risks associated with hydraulic fracturing. For example, we install multiple layers of steel into each well and cement above and below any freshwater aquifers. We then test the integrity of each well before we begin the fracturing process and again at completion. Hydraulic fracturing creates very small earth tremors that are rarely felt at the surface. Before we start work we assess the likelihood of our operations causing such activity. For example, we work to identify natural faults in the rock. This analysis informs our development plans for drilling and hydraulic fracturing activity, and we seek to mitigate this risk through the design of our operations. See bp.com/environment for more information. We disclose information on payments to governments for our upstream activities on a country-by-country and project basis under national reporting regulations such as those in effect in the UK. 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. We support transparency in the flow of revenue from oil and gas activities to governments. This helps citizens hold public authorities to account for the way they use funds received through taxes and other agreements. We are a founding member of the Extractive Industries Transparency Initiative (EITI), which requires disclosure of payments made to and received by governments in relation to oil, gas and mining activity. As part of the EITI, we work with governments, non-governmental organizations and international agencies to improve the transparency of payments to governments. In 2018 we continued to support EITI implementation in a number of countries where we operate, including Iraq and Trinidad & Tobago. See bp.com/tax for our approach to tax and our payments to governments report. Value to society We aim to have a positive and enduring impact on the communities in which we operate. In supplying energy, we contribute to economies around the world by employing local staff, helping to develop national and local suppliers, and through the funds we pay to governments from taxes and other agreements. Additionally, our social investments support community efforts to increase incomes and improve standards of living. We contributed $114.2 million in social investment in 2018 (2017 $89.5 million, 2016 $61.1 million). In India we developed a training programme to help motorcycle mechanics working in small enterprises develop additional skills in business management and customer service. Since it began in 2009, the programme has trained more than 200,000 mechanics. We aim to recruit our workforce from the community or country in which we operate. We also run programmes to build the skills of businesses and develop the local supply chain in a number of locations. For example, in 2018 we launched an initiative with oil and gas peers in Senegal to support local company efforts to achieve international standards and improve their ability to bid for work with companies like BP. Human rights We are committed to respecting the rights and dignity of all people when conducting our business. 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. These include the rights of our workforce and those living in communities potentially affected by our activities. We set out our commitments in our human rights policy and our code of conduct. Our operating management system contains guidance on respecting the rights of workers and community members. We are incorporating the UN Guiding Principles on Business and Human Rights, which set out how companies should prevent, address and remedy human rights impacts, into our business processes. Our focus areas include the ethical recruitment and working conditions of contracted workforces at our sites, responsible security, community health and livelihoods, and mechanisms for workers and communities to raise their concerns. Nationals employed In 2018 our actions included: Trinidad & Tobago 96% Egypt 78% Azerbaijan 91% Oman 77% Indonesia 96% Angola 87% See bp.com/society for more information on how we generate value to society. Tax and transparency We are committed to complying with tax laws in a responsible manner and having open and constructive relationships with tax authorities. We paid $7.5 billion in income and production taxes to governments in 2018 (2017 $5.8 billion, 2016 $2.2 billion). • Reviewing the risk of modern slavery in prioritized locations, including on-site assessments in some cases and addressing findings. • Working with a number of our peers to create an oil and gas industry framework for human rights supplier assessments with a particular focus on labour rights. • Developing clear expectations on labour rights and a systematic approach to modern slavery risk management to build into business systems and processes. • Continuing to develop capability on modern slavery and labour rights for our employees and selected contractors, as well as taking steps to raise worker awareness of their rights. • Assessing the practices of private security contractors and the way we work with public security forces in our operations in Georgia, in line with our continued implementation of the Voluntary Principles on Security and Human Rights. See bp.com/humanrights for more information about our approach to human rights. 49 Strategic report – performanceBP Annual Report and Form 20-F 2018 Ethical conduct We are committed to conducting our business in an ethical, transparent way, using our values and code of conduct to guide us. Our values Our values represent the qualities and actions we wish to see in BP. They inform the way we do business and the decisions we make. We use these values as part of our recruitment, promotion and individual performance management processes. See bp.com/values for more information. The BP code of conduct Our code of conduct is based on our values and sets clear expectations for how we work at BP. It applies to all BP employees and members of the board. Employees, contractors or other third parties who have a question about our code of conduct or see something that they feel is unethical or unsafe can discuss these with their managers, supporting teams, works councils (where relevant) or through OpenTalk, a confidential helpline operated by an independent company. A total of 1,712 concerns or enquiries were recorded in 2018 (2017 1,612, 2016 1,701) through these channels. The most commonly raised concerns were about fair treatment of people, workplace harassment and protecting BP’s assets. We take steps to identify and correct areas of non-conformance and take disciplinary action where appropriate. In 2018 our businesses dismissed 50 employees for non-conformance with our code of conduct or unethical behaviour (2017 70, 2016 109). This excludes dismissals of staff employed at our retail service stations. See bp.com/codeofconduct for more information. Gulf of Mexico oil spill The term of appointment of the ethics monitor, who was appointed under the administrative agreement with the US Environmental Protection Agency, came to an end in March 2019. In his final report the ethics monitor confirmed that BP had successfully completed the recommendations he had made. Anti-bribery and corruption BP operates in parts of the world where bribery and corruption present a high risk. 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 and procedures include measures and guidance to assess risks, understand relevant laws and report concerns. They apply to all BP-operated businesses. We provide training to employees appropriate to the nature or location of their role. A total of 10,957 employees completed anti-bribery and corruption training in 2018 (2017 12,500, 2016 13,000). We assess any exposure to bribery and corruption risk when working with suppliers and business partners. Where appropriate, we put in place a risk mitigation plan or we reject them if we conclude that risks are too high. We also conduct anti-bribery compliance audits on selected suppliers when contracts are in place. For example, our upstream business conducts audits for a number of suppliers in higher-risk regions to assess their conformance with our anti-bribery and corruption contractual requirements. Potential areas for improvement are shared with our suppliers and where necessary, this enables us to work with them to find ways to strengthen their procedures. We issued a total of 27 audit reports in 2018 (2017 36, 2016 25). We take corrective action with suppliers and business partners who fail to meet our expectations, which may include terminating contracts. 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 and these rights are governed by the applicable laws in the countries in which we operate. For example, in the US we provide administrative support for the BP employee political action committee (PAC), which is a non-partisan committee that encourages voluntary employee participation in the political process. All BP employee PAC contributions are reviewed for compliance with federal and state law and are publicly reported in accordance with US election laws. We work with governments on a range of issues that are relevant to our business, from regulatory compliance, to understanding our tax liabilities, to collaborating on community initiatives. The way in which we interact with those governments depends on the legal and regulatory framework in each country. We are members of multiple industry associations that offer opportunities to share good practices and collaborate on issues of importance to our sector. We aim for alignment between our policies and those of trade associations, but understand that associations’ positions reflect a compromise of the assorted views of the membership. 50 BP Annual Report and Form 20-F 2018 Our people BP’s success depends on the wholehearted contribution of a talented and diverse workforce. 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 2018 16,900 42,700 13,400 73,000 17,400 2017 17,700 42,100 14,200 74,000 16,800 2016 18,700 41,800 14,000 74,500 16,200 3,400 4,300 4,600 52,200 52,900 53,700 a Reported to the nearest 100. For more information see Financial statements – Note 35. Our industry relies on creative and scientific thinking to solve some of the world’s biggest energy problems. We focus on attracting and developing innovative and capable individuals, while also maintaining safe and reliable operations. The group people committee helps facilitate the group chief executive’s oversight of policies relating to employees. In 2018 the committee discussed remuneration policy, progress in our diversity and inclusion programme, modernizing and strengthening our attractiveness as an employer, our talent and learning programmes and long-term people priorities. Attraction and retention A total of 296 graduates joined BP in 2018 (2017 314, 2016 231). We were named the UK’s highest-ranking recruiter in the oil and gas sector in The Times newspaper’s Top 100 Graduate Employer rankings in 2018. We invest in employee development – with an average spend of around $3,200 per person. This includes online and classroom-based courses and resources, supported by a wide range of on-the-job learning and mentoring programmes. Diversity We are committed to making our workplaces reflect the communities in which we are based. The gender balance across BP as a whole is steadily improving, with women representing 35% of BP’s total population (2017 34%, 2016 33%). We are working to improve these numbers further by, for example, developing mentoring, sponsorship and coaching programmes to help more women advance. But we still have work to do at the executive and senior levels. See bp.com/ukgenderpaygap for data and more information on our gender pay gap in the UK. At the end of 2018 we had five female directors (2017 3, 2016 3) 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 58. Workforce by gender Members as at 31 December Board directors Executive team Group leaders Subsidiary directors All employees Male 9 11 286 1,161 47,171 Female 5 2 89 233 25,824 Female % 36 15 24 17 35 A total of 24% of our group leaders came from countries other than the UK and the US in 2018 (2017 24%, 2016 23%). Inclusion BP is committed to creating a positive and empowering workplace in which all employees feel valued for the work they do and the impact they make. Our goal is to create an environment of inclusion and acceptance, where everyone is treated equally and without discrimination. To promote an inclusive culture we provide leadership training and support employee-run advocacy groups in areas such as gender, ethnicity, sexual orientation and disability. As well as bringing employees together, these groups support our recruitment programmes and provide feedback on the potential impact of policy changes. Each group is sponsored by a senior executive. We made progress in a number of important areas in 2018. For example, we worked with MyPlus, a disability consultancy, to increase our understanding of the needs of disabled candidates in our application and hiring processes. And we launched our gender transition guidelines to support employees who are transitioning, or helping someone who is. 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 BP’s performance, and seek to maintain constructive relationships with labour unions formally representing our employees. To better understand how employees feel about BP, we conduct an annual survey. The overall employee engagement score in 2018 was 66%. Pride in working for BP was at the highest level in a decade at 76% in 2018. The area where our employees scored us as needing attention was in the efficiency of our processes and ways of working. We know we still have work to do to streamline our processes and drive the benefits of digitization throughout BP. Share ownership We encourage employee share ownership and have a number of employee share plans in place. For example, we operate a ShareMatch plan in more than 50 countries, matching BP shares purchased by our employees. We also operate a group-wide discretionary share plan, which allows employee participation at different levels globally and is linked to the company’s performance. See Glossary 51 Strategic report – performanceBP Annual Report and Form 20-F 2018Modernizing the whole group Using wearable technologies New technologies are helping to modernize our operations and improve safety, performance and efficiency right across our business. And we are testing a range of wearable technologies to understand how they can support our people in a variety of roles. Smart glasses used across BPX Energy We are using augmented reality (AR) devices such as ‘smart glasses’ across BPX Energy. Technicians can use the glasses to transmit real-time video to experts anywhere in the business and they can then return AR-enabled instruction back to the technician – all while keeping their hands free. We are now using the mobile platform to troubleshoot equipment, conduct safety verifications and deliver remote training. This is helping increase productivity and contributing to improvements in the safety and efficiency of our operations. Digital vests In Oman, where temperatures can reach 55°C, we are testing technologies such as biometric vests to protect our people working in high temperatures. Working in extreme heat can trigger fatigue, dehydration and stress – and this can affect safety and effective performance. The lightweight vest is designed to prevent this by monitoring location and core body temperature and transmitting data about heart and respiratory rates. It sends an alert if there is a potential concern or a real emergency. As technologies like these evolve, we will continue to trial them in our operations, so that we can roll out those that are the best fit. Temperatures in Oman can reach 55°C 52 BP Annual Report and Form 20-F 2018 How we manage risk BP manages, monitors and reports on the principal risks and uncertainties that can impact our ability to deliver our strategy. These risks are described in the Risk factors on page 55. Our management systems, organizational structures, processes, standards, code of conduct and behaviours together form a system of internal control that governs how we conduct the business of BP and manage associated risks. BP’s risk management system BP’s risk management system and policy is designed to be a consistent and clear framework for managing and reporting risks from the group’s operations to management and to the board. The system seeks to avoid incidents and maximize business outcomes by allowing us to: • Understand the risk environment, identify the specific risks and assess the 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 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 oversight and governance Key risk oversight and governance 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. of these risks and intervene for improvement where necessary. • Group ethics and compliance committee – for legal and regulatory • 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 compliance and ethics risks. • Resource commitment meeting – for investment decision risks. • Renewal committee – for strategic, commercial and investment decision risks related to new lines of business. Board and its committees • BP board. • Audit committee. • Safety, ethics and environment assurance committee. • Geopolitical committee. Facilities, assets and operations Business segments and functions Executive and corporate functions Board See BP governance framework on page 69, Board activity in 2018 on page 70, committee reports on pages 75-86 and Risk management and internal control on page 110. 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 safe, compliant and reliable operations as well as greater efficiency and sustainable financial results. 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 in connection with planning new activities. Oversight and governance – throughout the year functional leadership, the executive team, the board and relevant committees provide oversight of how significant risks to BP are identified, assessed and managed. They help to ensure that risks are governed by relevant policies and are managed appropriately. Risk management processes We aim for a consistent basis of measuring risk to: • Establish a common understanding of risks on a like-for-like basis, taking into account potential impact and likelihood. • Report risks and their management to the appropriate levels of the organization. • Inform prioritization of specific risk management activities and resource allocation. Businesses and functions review significant risks and associated risk management activities in alignment with key business processes to help enable key decisions to be risk informed. As part of BP’s annual planning process, the executive team and board review the group’s principal risks and uncertainties. These may be updated during the year in response to changes in internal and external circumstances. Our risk profile The nature of our business operations is long term, resulting in many of our risks being enduring in nature. Nonetheless, risks can develop and evolve over time and their potential impact or likelihood may vary in response to internal and external events. 53 Strategic report – performanceBP Annual Report and Form 20-F 2018 We identify high priority risks for particular oversight by the board and its various committees in the coming year. Those identified for 2019 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, for example technological change or the transition to a lower carbon economy, is undertaken in the normal course of business and in the executive team, the board and relevant 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 55. Risks for particular oversight by the board and its committees in 2019 The risks for particular oversight by the board and its committees in 2019 have been reviewed. These risks remain the same as for 2018. Strategic and commercial risks Financial liquidity External market conditions can impact our financial performance. Supply and demand and the prices achieved for our products can be affected by a wide range of factors including political developments, global economic conditions and the influence of OPEC. We seek to manage this risk through BP’s diversified portfolio, our financial framework, liquidity stress testing, maintaining a significant cash buffer, regular reviews of market conditions and our planning and investment processes. Geopolitical The diverse locations of our operations around the world expose us to a wide range of political developments and consequent changes to the economic and operating environment. Geopolitical risk is inherent to many regions in which we operate, and heightened political or social tensions or changes in key relationships could adversely affect the group. We seek to manage this risk through development and maintenance of relationships with governments and stakeholders and by becoming trusted partners in each country and region. In addition, we closely monitor events and implement risk mitigation plans where appropriate. The impact of the UK’s exit from the EU Following the referendum in 2016, we have been assessing the potential impact of Brexit on BP. We have been preparing for different scenarios for the UK’s exit from the EU but do not believe any of these scenarios will pose a significant risk to our business. The board’s geopolitical committee discussed this, most recently in January 2019. We continue to monitor developments in this area in line with our risk management processes and procedures. Cyber security The targeted and indiscriminate threats to the security of our digital infrastructure continue to evolve rapidly and are increasingly prevalent across industries worldwide. The oil and gas industry is subject to evolving risks from a variety of cyber threat actors, including nation states, criminals, terrorists, hacktivists and insiders. A cyber security breach could disrupt our business, injure people, harm the environment or our assets, or result in legal or regulatory breaches. We seek to manage this risk through a range of measures, which include cyber security standards, security protection tools, ongoing detection and monitoring of threats and testing of cyber response and recovery procedures. We collaborate closely with governments, law enforcement agencies and industry peers to understand and respond to new and emerging cyber threats. We build awareness with our staff, share information on incidents with leadership for continuous learning and conduct regular exercises including with the executive team to test response and recovery procedures. Safety and operational risks Process safety, personal safety and environmental risks The nature of the group’s operating activities exposes us to a wide range of significant health, safety and environmental risks such as incidents associated with releases of hydrocarbons when drilling wells, operating facilities and transporting hydrocarbons. Our operating management system helps us manage these risks and drive performance improvements. It sets out the 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 activities with respect to the management of security risks affecting our people and operations. We continue to monitor threats globally and maintain disaster recovery, crisis and business continuity management plans. Compliance and control risks Ethical misconduct and legal or regulatory non-compliance Ethical misconduct or breaches of applicable laws or regulations could damage our reputation, 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. Trading non-compliance In the normal course of business, we are subject to risks around our trading activities which could arise from shortcomings or failures in our systems, risk management methodology, internal control processes or employee conduct. We have specific operating standards and control processes to manage these risks, including guidelines specific to trading, and seek to monitor compliance through our dedicated compliance teams. We also seek to maintain a positive and collaborative relationship with regulators and the industry at large. 54 See Glossary BP Annual Report and Form 20-F 2018Risk factors The risks discussed below, separately or in combination, could have a material adverse effect on the implementation of our strategy, our business, financial performance, results of operations, cash flows, liquidity, prospects, shareholder value and returns and reputation. Strategic and commercial risks Prices and markets – our financial performance is impacted by fluctuating prices of oil, gas and refined products, technological change, exchange rate fluctuations, and the general macroeconomic outlook. Oil, gas and product prices are subject to international supply and demand and margins can be volatile. Political developments, increased supply from new oil and gas 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 – 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, unsuccessful exploration activity 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. Poor investment choice, efficiency or delivery, or operational challenges at any major project that underpins production or production growth could adversely affect our financial performance. Geopolitical – exposure to a range of political developments and consequent changes to the operating and regulatory environment could cause business disruption. We operate and may seek new opportunities in countries 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 trade restrictions and other sanctions, could adversely impact our income and investment in or relating to Russia. Our ability to pursue business objectives and to recognize production and reserves relating to these investments could also be adversely impacted. Liquidity, financial capacity and financial, including credit, exposure – failure to work within our financial framework could impact our ability to operate and result in financial loss. Failure to accurately forecast or work within our financial framework could impact our ability to operate and result in financial loss. Trade and other receivables, including overdue receivables, may not be recovered 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 also trigger a requirement for the company to review its funding arrangements with the BP pension trustees and may cause other impacts on financial performance. In the event of extended constraints on our ability to obtain financing, we could be required to reduce capital expenditure or increase asset disposals in order to provide additional liquidity. See Liquidity and capital resources on page 277 and Financial statements – Note 29. Joint arrangements and contractors – varying levels of control over the standards, operations and compliance of our partners, contractors and sub-contractors could result in legal liability and reputational damage. We conduct many of our activities through joint arrangements , associates or with contractors and sub-contractors where we may have limited influence and control over the performance of such operations. Our partners and contractors are responsible for the adequacy of the resources and capabilities they bring to a project. If these are found to be lacking, there may be financial, operational or safety 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 cyber security – breach of our digital security or failure of our digital infrastructure including loss or misuse of sensitive information could damage our operations, increase costs and damage our reputation. The oil and gas industry is subject to fast-evolving risks from cyber threat actors, including nation states, criminals, terrorists, hacktivists and insiders. A breach or failure of our digital infrastructure – including control systems – due to breaches of our cyber defences, or those of third parties, negligence, intentional misconduct or other reasons, could seriously disrupt our operations. This could result in the loss or misuse of data or sensitive information, injury to people, disruption to our business, harm to the environment or our assets, legal or regulatory breaches and legal liability. Furthermore, the rapid detection of attempts to gain unauthorized access to our digital infrastructure, often through the use of sophisticated and co-ordinated means, is a challenge and any delay or failure to detect could compound these potential harms. These could result in significant costs including the cost of remediation or reputational consequences. Climate change and the transition to a lower carbon economy – policy, legal, regulatory, technology and market change related to the issue of climate change could increase costs, reduce demand for our products, reduce revenue and limit certain growth opportunities. Changes in laws, regulations, policies, obligations, social attitudes and customer preferences relating to the transition to a lower carbon economy could have a cost impact on our business, including increasing compliance and litigation costs, and could impact our strategy. Such changes could lead to constraints on production and supply and access to new reserves. Technological improvements or innovations that support the transition to a lower carbon economy, and customer preferences or regulatory incentives related to such changes that alter fuel or power choices, such as towards low emission energy sources, could impact demand for oil and gas. Depending on the nature and speed of any such changes and our response, this could adversely affect See Glossary 55 Strategic report – performanceBP Annual Report and Form 20-F 2018 the demand for our products, investor sentiment, our financial performance and our competitiveness. See Climate change on page 45. Security – hostile acts against our staff and activities could cause harm to people and disrupt our operations. Competition – inability to remain efficient, maintain a high quality portfolio of assets, innovate and retain an appropriately skilled workforce could negatively impact delivery of our strategy in a highly competitive market. Our strategic progress and performance could be impeded if we are unable to control our development and operating costs and margins, 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, manufacturing, renewable energy or new technologies 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 diverse, 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 – failure to address an incident effectively could potentially disrupt our business. Our business activities could be disrupted if we do not respond, or are perceived not to respond, in an appropriate manner to any major crisis or if we are not able to restore or replace critical operational capacity. Insurance – our insurance strategy could expose the group to material uninsured losses. BP generally purchases insurance only in situations where this is legally and contractually required. Some risks are insured with third parties and reinsured by group insurance companies. Uninsured losses could have a material adverse effect on our financial position, particularly if they arise at a time when we are facing material costs as a result of a significant operational event which could put pressure on our liquidity and cash flows. Safety and operational risks Process safety, personal safety, and environmental risks – exposure to a wide range of health, safety, security and environmental risks could cause harm to people, the environment and our assets and result in regulatory action, legal liability, business interruption, increased costs, damage to our reputation and potentially denial of our licence to operate. Technical integrity failure, natural disasters, extreme weather or a change in its frequency or severity, human error and other adverse events or conditions could lead to loss of containment of hydrocarbons or other hazardous materials or constrained availability of resources used in our operating activities, as well as fires, explosions or other personal and process safety incidents, including when drilling wells, operating facilities and those associated with transportation by road, sea or pipeline. There can be no certainty that our operating management 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 and security on page 43. Such events or conditions, including a marine incident, or inability to provide safe environments for our workforce and the public while at our facilities, premises or during transportation, could lead to injuries, loss of life or environmental damage. As a result we could face regulatory action and legal liability, including penalties and remediation obligations, increased costs and potentially denial of our licence to operate. Our activities are sometimes conducted in hazardous, remote or environmentally sensitive locations, where the consequences of such events or conditions could be greater than in other locations. Drilling and production – challenging operational environments and other uncertainties could impact drilling and production activities. Our activities require high levels of investment and are sometimes conducted in challenging environments such as those prone to natural disasters and extreme weather, which heightens the risks of technical integrity failure. The physical characteristics of an oil or natural gas field, and cost of drilling, completing or operating wells is often uncertain. We may be required to curtail, delay or cancel drilling operations or stop production because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions and compliance with governmental requirements. 56 See Glossary Acts of terrorism, piracy, sabotage and similar activities directed against our operations and facilities, pipelines, transportation or digital infrastructure could cause harm to people and severely disrupt operations. Our activities could also be severely affected by conflict, civil strife or political unrest. Product quality – supplying customers with off-specification products could damage our reputation, lead to regulatory action and legal liability, and impact our financial performance. Failure to meet product quality 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 Regulation – changes in the regulatory and legislative environment could increase the cost of compliance, affect our provisions and limit our access to new growth 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, we may be subjected to a higher level of fines or penalties imposed in relation to any alleged breaches of laws or regulations, which could result in increased costs. Ethical misconduct and non-compliance – ethical misconduct or breaches of applicable laws by our businesses or our employees could be damaging to our reputation, and could result in litigation, regulatory action and penalties. Incidents of ethical misconduct or non-compliance with applicable laws and regulations, including anti-bribery and corruption and anti-fraud laws, trade restrictions or other sanctions, could damage our reputation, 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, fines and potentially damaging our reputation. See Financial statements – Note 29. Reporting – failure to accurately report our data could lead to regulatory action, legal liability and reputational damage. External reporting of financial and non-financial data, including reserves estimates, relies on the integrity of 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 Jens Bertelsen, company secretary on 29 March 2019. BP Annual Report and Form 20-F 2018Corporate governance 58 Board of directors 63 Executive team 66 Executive management teams 68 Introduction from the chairman 69 Governance framework 69 Board and committee attendance 70 Board activity in 2018 70 Role of the board 71 Skills and expertise 71 Diversity 71 71 Appointment and time commitment 72 Training and induction 72 Board evaluation 73 Site visits Independence 74 Shareholder engagement Institutional investors 74 74 Retail investors 74 AGM 74 UK Corporate Governance Code compliance 74 International advisory board 75 Committee reports 75 Audit committee 81 83 Remuneration committee 84 Geopolitical committee 85 Chairman’s committee 86 Nomination and governance committee Safety, ethics and environment assurance committee 87 Directors’ remuneration report 90 2018 performance and pay outcomes 91 2018 annual bonus outcome 92 2016-18 performance share plan outcome 94 Alignment with strategy 95 Executive directors’ pay for 2018 97 Wider workforce in 2018 100 Stewardship and executive director interests 102 Non-executive director outcomes and interests 104 Other disclosures 105 Executive director remuneration policy and implementation for 2019 109 Non-executive director remuneration policy for 2019 110 Directors’ statements 110 Statement of directors’ responsibilities 110 Risk management and internal control 111 Longer-term viability 111 Going concern 111 Fair, balanced and understandable BP Annual Report and Form 20-F 2018 57 Corporate governance Board of directors As at 29 March 2019 See BP’s board governance principles relating to director independence on page 300. Helge Lund Bob Dudley Brian Gilvary Nils Andersen Alan Boeckmann Admiral Frank Bowman Dame Alison Carnwath Pamela Daley Ian Davis Professor Dame Ann Dowling Melody Meyer Brendan Nelson Paula Rosput Reynolds Sir John Sawers Jens Bertelsen He has a degree in business economics from the Norwegian School of Economics and Business Administration in Bergen and a Master of Business Administration from INSEAD business school in France. Relevant skills and experience Helge Lund was appointed chair of the BP board following a detailed process involving all members of the board. Helge has an impressive track record of leadership in the oil and gas industry. His open-minded and forward-looking approach will be vital as the industry focuses on the transition to a lower carbon world. He has deep industry knowledge and global business experience – not only in the oil and gas industry but also in pharmaceuticals, healthcare and construction. Prior to Statoil, he was president and chief executive officer of Aker Kvaerner, an industrial conglomerate with operations in oil and gas, engineering and construction, pulp and paper and shipbuilding. He has also held executive positions in Aker RGI, a Norwegian industrial holding company, and Hafslund Nycomed, an industrial group with business activities in pharmaceuticals and energy. He has worked as a consultant with McKinsey & Company and has served as a political adviser for the parliamentary group of the Conservative party in Norway. Helge is chairman of the board of Novo Nordisk AS, a global healthcare company. Prior to joining BP, he was a non-executive director of the oil service group Schlumberger from 2016 to 2018, and Nokia from 2011 to 2014. He is an operating adviser to Clayton Dubilier & Rice, a US investment firm. He is a member of the Board of Trustees of the International Crisis Group and served as a member on the United Nations Secretary-General’s Advisory Group on Sustainable Energy from 2011 to 2014. Helge Lund Chairman Tenure Appointed 26 July 2018 Board and committee activities Chair of the chairman’s committee and nomination and governance committee, regularly attends the safety, ethics and environment assurance, audit, remuneration and geopolitical committees Outside interests • Chairman of Novo Nordisk AS • Operating Advisor to Clayton Dubilier & Rice • Member of the Board of Trustees of the International Crisis Group Age 56 Nationality Norwegian Career Helge Lund became a board director on 26 July 2018 and chairman of the BP board on 1 January 2019. Helge served as chief executive of BG Group from 2015 to 2016, when the company merged with Shell. He joined BG Group from Statoil where he served as president and chief executive officer for 10 years from 2004. 58 BP Annual Report and Form 20-F 2018Bob Dudley Group chief executive Tenure Appointed to the board 6 April 2009 Outside interests • Fellow of the Royal Academy of Engineering • 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 Oil and Gas Climate Initiative (OGCI) Age 63 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. During 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. Since 2016, he has chaired the Oil and Gas Community of the World Economic Forum and is chair of the Oil and Gas Climate Initiative (OGCI). Relevant skills and experience Bob Dudley has spent his whole career in the oil and gas industry. As group chief executive, the board believes Bob has demonstrated outstanding leadership and vision and has transformed BP into a safer, stronger and simpler business. Over the past eight years, Bob has based this transformation on a consistent set of values and behaviours. BP is now more resilient and is able to continue delivering results in an uncertain economic environment. Bob continues to lead the development of the group’s strategy, as BP adapts to the challenges of the advancing transition to a lower carbon economy. Under his leadership, BP successfully acquired the lower 48 assets of BHP in 2018 and delivered six major projects as planned. Bob Dudley’s performance has been considered and evaluated by the chairman’s committee. Brian Gilvary Chief financial officer Tenure Appointed to the board 1 January 2012 Outside interests • Non-executive director of Air Liquide • Non-executive director of (Royal) Navy Board • Non-executive director of The Francis Crick Institute • Chairman of The 100 Group • Member of Trilateral Commission • Honorary professor at Manchester University • Great Britain Age Group Triathlete Age 57 Nationality British Career Brian Gilvary was appointed chief financial officer on 1 January 2012. The role includes responsibility for finance, tax, treasury, mergers and acquisitions, investor relations, audit, global business services, information technology and procurement. He also has accountability for both integrated supply and trading, and the shipping division responsible for BP’s tanker fleet. Brian joined BP in 1986 after obtaining a PhD in mathematics from the University of Manchester. Following a broad range of roles in upstream, downstream and trading in Europe and the US, he became downstream’s 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 BP’s acquisition of Rosneft equity in 2013. He served on the HM Treasury Financial Management Review Board from 2014 to 2017. Relevant skills and experience Brian Gilvary has spent his entire career with BP, with broad experience of working across all facets of the group. This has provided him with deep insight into BP’s assets and businesses. Brian has been a key player as BP has implemented its strategy to transform into a ‘value over volume’ based business where trading is a key creator of value throughout the integrated business. In addition to underpinning his role as chief financial officer, his deep 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. He played a major role in overseeing the financial consequences of the 2010 oil spill in the Gulf of Mexico, and leading the 2015 settlement negotiations with the US government and states to resolve the outstanding federal and state claims. Brian also played a lead role in the negotiations around the exit of TNK-BP and investment into Rosneft and led the recent acquisition of the BHP onshore Lower 48 assets. Brian has also been at the centre of the group’s work on addressing cyber security risk. 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 safety, ethics and environment assurance, geopolitical and chairman’s committees Outside interests • Non-executive director of Unilever Plc and Unilever NV • Chairman of Salling Group A/S • Chairman of Færch Plast A/S • Chairman of Akzo Nobel N.V. • Chairman of WWF Denmark Age 60 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 was elected as a member and chairman of the supervisory board of Akzo Nobel N.V. in April 2018 and was recently appointed as chairman of WWF Denmark. 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, having led global corporations with integrated operations worldwide. He has substantial skill, knowledge and experience in marketing, brand and reputation issues. He has broad shipping and upstream energy industry experience which aligns with BP’s shipping business. His leadership earlier in his career focused on the transformation of businesses, leaner organizations and increasing competitiveness, as well as increasing transparency and communication with stakeholders. Nils has recently moved from the audit committee to the safety, ethics and environment assurance 59 Corporate governanceBP Annual Report and Form 20-F 2018committee where he will shortly take the chair. His broad business experience and his knowledge of safe operations in our industry makes him very well qualified for that role. 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 governance and chairman’s committees Outside interests • Non-executive director of Sempra Energy • Non-executive director of Archer Daniels Midland Age 70 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 the energy sector. He has been involved in delivering very large projects particularly in the energy industry. 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 through the ‘Partnering Against Corruption’ initiative. 60 Admiral Frank Bowman Independent non-executive director Dame Alison Carnwath Independent non-executive director Tenure Appointed 8 November 2010 Tenure Appointed 21 May 2018 Board and committee activities Member of the audit and chairman’s committees Outside interests • Member of Supervisory Board and Audit Committee chair of BASF SE • Director and Audit Committee chair of Zurich Insurance Group • Independent director of PACCAR Inc • Member of UK Panel on Takeovers and Mergers • Trustee of The Economist Group Age 66 Nationality British Career Dame Alison Carnwath qualified as a chartered accountant before going on to hold a number of senior financial advisory roles in London and New York. For more than 15 years, Dame Alison’s career, in her capacities as senior adviser, director and chairman, has enabled her to demonstrate her expertise on financial, strategic and good governance matters both in and outside of the board room. Her current roles include independent director of PACCAR Inc, director and audit committee chair of Zurich Insurance Group and supervisory board member and audit committee chair BASF SE. Previous roles of note include chairmanship of Land Securities Group plc as well as non-executive directorships of Barclays plc and Man Group plc. Dame Alison is a chartered accountant, holds an undergraduate degree, has two honorary degrees and in 2014 was appointed to the order of Dame Commander of the Most Excellent Order of the British Empire for her services to business and diversity. Relevant skills and experience Dame Alison has extensive financial experience both as an executive and non- executive director. Dame Alison has chaired significant boards and has deep experience of the workings of investors and the finance industry in the City of London. She has worked with global organizations and brings this broad range of skills to the BP board and to the audit committee. 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 74 Nationality American Career Frank 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. 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 holds two masters degrees in engineering from the Massachusetts Institute of Technology. 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. Frank makes a substantial contribution to the safety culture within BP. 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 an important perspective to the board and the safety, ethics and environment assurance committee. He has led the oversight of BP’s compliance with the agreements with the US government stemming from the Deepwater Horizon oil spill. BP Annual Report and Form 20-F 2018 Pamela Daley Independent non-executive director Tenure Appointed 26 July 2018 Board and committee activities Member of the audit, remuneration and chairman’s committees Outside interests • Director of BlackRock, Inc • Director of SecureWorks, Inc Age 66 Nationality American Career Pamela Daley spent most of her career with the General Electric Company. She joined GE in 1989 as tax counsel and held a number of senior executive roles in the company, serving most recently as senior vice president and senior advisor to the chairman from April to December 2013, when she retired from GE. Between 2004 and 2013 she was senior vice president of corporate business development at GE, where she was responsible for GE’s mergers, acquisitions and divestiture activities worldwide, and prior to that, from 1991 to 2004, served as vice president and senior counsel for transactions. Pamela Daley has served as a director of BlackRock since 2014 and of SecureWorks since 2016. She was a director of BG Group plc from 2014 to 2016 until its acquisition by Shell, a director of Patheon N.V. from 2016 to 2017 until its acquisition by Thermo Fisher, and was previously a partner at Morgan, Lewis & Bockius, a major US law firm, where she specialized in domestic and cross-border tax-oriented financings and commercial transactions. Pamela Daley is a qualified lawyer, she worked in highly regulated industries, holding senior roles on other boards including chair of the governance and nominating committee at SecureWorks and chair of the audit committee at BlackRock. Relevant skills and experience Pamela Daley has deep experience of global business through her executive role at GE. She has also served on a UK board in the oil and gas industry which gave her further insight into that sector. Pamela has joined the audit committee to which she brings deep financial experience and expertise. She has also joined the remuneration committee, where her understanding of employee and investor points of view will provide important input. Ian Davis Senior independent director Tenure Appointed 2 April 2010 Board and committee activities Member of the remuneration, geopolitical, nomination and governance 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 68 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 global 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. He is able to draw on knowledge of diverse issues and outcomes to assist the board and its committees. Ian led the board’s oversight of the response in the Gulf of Mexico and chaired the Gulf of Mexico committee from its formation in 2010 until it was stood down in 2016. He was previously a non-executive director in the Cabinet Office, giving him an important perspective on government affairs which is an asset to both the board and the geopolitical committee. In his role as the senior independent director, Ian is responsible for the annual evaluation of the chairman’s performance and led the search for a successor to Carl-Henric Svanberg as chairman, resulting in the appointment of Helge Lund. Professor Dame Ann Dowling Independent non-executive director Tenure Appointed 3 February 2012 Board and committee activities Member of the safety, ethics and environment assurance 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 Smiths Group plc Age 66 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 council. Dame Ann is a fellow of the Royal Society and the Royal Academy of Engineering and a foreign associate of the US National Academy of Engineering, the Chinese Academy of Engineering and the French Academy of Sciences. She has honorary degrees from 18 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 safety, ethics and environment assurance committee, particularly as developments in technology accelerate. Her work in this area is supplemented by her chairing the company’s technology advisory council. Dame Ann was chair of the remuneration committee from 2015 and stood down from that committee after the 2018 AGM. Melody Meyer Independent non-executive director Tenure Appointed 17 May 2017 Board and committee activities Member of the safety, ethics and environment assurance, geopolitical and chairman’s committees. Outside interests • President of Melody Meyer Energy LLC • Director of the National Bureau of Asian Research • Trustee of Trinity University • Non-executive director of AbbVie Inc. • Senior Advisor to Cairn India Limited • Director of National Oilwell Varco, Inc. Age 61 Nationality American Career Melody Meyer started her career with Gulf Oil in Houston. Gulf Oil later merged with Chevron where Melody remained until her retirement in 2016. During her career with Chevron, Melody had key leadership roles in global exploration and production, working on international projects and operational assignments. In 2004 Melody became vice president for the Gulf of Mexico business unit, and in 2008 became president of the Chevron Energy Technology Company. From 2011 Melody was president of Asia Pacific Exploration and Production, responsible for the financial and operating performance of the upstream assets in nine countries in Chevron’s Asia Pacific region. Melody was the executive sponsor of the Chevron Women’s Network and continues as a mentor and advocate for the advancement of women in the industry. She 61 Corporate governanceBP Annual Report and Form 20-F 2018insight into the challenges faced by global businesses by regulatory frameworks. He recently joined the remuneration committee. Paula Rosput Reynolds Independent non-executive director Tenure Appointed 14 May 2015 Board and committee activities Chair of the remuneration committee; member of the audit, nomination and governance and chairman’s committees Outside interests • Non-executive director of BAE Systems plc • Non-executive director of TransCanada Corporation (until May 2019) 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 governance 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 • Trustee of the Bilderberg Association, UK • Non-executive director of CBRE Group (until Age 63 Nationality British May 2019) • Non-executive director of General Electric Company Age 62 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 and deep experience of trading 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. Paula currently serves as the chair of the remuneration committee of BAE Systems plc. Her experience there and her wider business experience and understanding of the views of investors are well suited to her being the chair of the BP remuneration committee. Career Sir John Sawers spent 36 years in public service in the UK, working on foreign policy, international security and intelligence. Sir 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 from 2007 to 2009, political director and main board member of the Foreign Office from 2003 to 2007, special representative in Iraq during 2003, ambassador to Egypt from 2001 to 2003 and foreign policy adviser to the Prime Minister from 1999 to 2001. Earlier in his career, he was posted to Washington, South Africa, Syria and Yemen. Sir 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’s deep experience of international political and commercial matters is an asset to the board in navigating the geopolitical issues faced by a modern global company. Sir John brings a unique perspective and broad experience which makes him ideal to lead the geopolitical committee. His knowledge and skills gained in government, diplomacy and policy analysis and advice are invaluable to both the board and the safety, ethics and environment assurance committee. Jens Bertelsen Company secretary Tenure Appointed 1 January 2019 Jens Bertelsen is a solicitor and formerly deputy secretary. was recognized as a 2009 Trinity Distinguished Alumni, with the BioHouston Women in Science Award, was the ASME Rhodes Petroleum Industry Leadership Award recipient and in 2018 as an Influential Woman in Energy. Relevant skills and experience Melody Meyer has spent her entire career in the oil and gas industry. The breadth, variety and geographic scope of her experience is distinctive. Her career has been marked by a focus on excellence, safety and performance improvement. She has expertise in the execution of major capital projects, creation of businesses in new countries, strategic and business planning, merger integration and safe and reliable operations. Melody brings a world-class operational perspective to the board, with a deep understanding of the factors influencing safe, efficient and commercially high-performing projects in a global organization. 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, nomination and governance and remuneration committees 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 69 Nationality British Career Brendan Nelson is a chartered accountant. He was made a partner of KPMG in 1984. He served as a member of the UK board of KPMG from 2000 to 2006, subsequently being appointed vice chairman until his retirement in 2010. At KPMG International he held a number of senior positions including global chairman, banking and global chairman, financial services. He served for six years as a member of the Financial Services Practitioner Panel and in 2013 was the president of the Institute of Chartered Accountants of Scotland. Relevant skills and experience Brendan Nelson has completed a wide variety of audit, regulatory and due-diligence engagements over the course of his career. He played a significant role in the development of the profession’s approach to the audit of banks in the UK, with particular emphasis on establishing auditing standards. 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. 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 62 BP Annual Report and Form 20-F 2018Executive team As at 29 March 2019 The executive team represents the principal executive leadership of the BP group. Its members include BP’s executive directors (Bob Dudley and Brian Gilvary whose biographies appear on pages 58-62) and the senior management listed on these pages. Susan Dio Tufan Erginbilgic David Eyton Bob Fryar Andy Hopwood Bernard Looney Lamar McKay Eric Nitcher Dev Sanyal Helmut Schuster Dame Angela Strank David Eyton Group head of technology Executive team tenure Appointed 1 September 2018 Outside interests • Fellow of the UK Royal Academy of Engineering • Fellow of the Institute of Materials, Minerals and Mining • Fellow of the Institute of Directors • Trustee of the John Lyons Foundation Age 58 Nationality British Career As group head of technology, David Eyton is accountable for technology strategy and its implementation across BP. This includes corporate venture capital investments and conducting research and development in areas of corporate renewal. In this role, David sits on the Oil & Gas Climate Initiative Climate Investments Board. David joined BP in 1982 from Cambridge University with an engineering degree. Susan Dio Chairman and president of BP America Executive team tenure Appointed 1 September 2018 Outside interests • Member of the American Petroleum Institute Board and Executive Committee • Member of the Greater Houston Partnership Executive Committee • Member of the Ford’s Theatre Board of Trustees Executive Committee Age 58 Nationality American Career Susan Dio is chairman and president of BP America, providing leadership and oversight to BP’s US businesses, which employ around 14,000 people. These businesses include oil and gas exploration and production, refining, petrochemicals, supply and trading, pipeline operations, shipping, retail, and alternative energy. Since joining the company in 1984, she has held key operational and executive positions in the US, UK, and Australia. Before assuming her current role, Susan served as chief executive officer of BP shipping, where she managed the fleet of BP-operated and chartered vessels that move more than 200 million tonnes of products across the globe each year. She also previously served as head of audit for BP’s downstream segment, as business unit leader of the Bulwer Island refinery, and as plant manager of Texas City chemicals. Outside BP, Susan is a member of the American Petroleum Institute Board and Executive Committee, the Greater Houston Partnership Executive Committee, and the Ford’s Theatre Board of Trustees Executive Committee. Tufan Erginbilgic Chief executive, Downstream Executive team tenure Appointed 1 October 2014 Outside interests • Member of the Turkish-British Chamber of Commerce & Industry Board of Directors • Member of the Strategic Advisory Board of the University of Surrey Age 59 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. He became head of the European fuels business in 2004 and 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. 63 Corporate governanceBP Annual Report and Form 20-F 2018 Bob Fryar Executive vice president, safety and operational risk Executive team tenure Appointed 1 October 2010 Outside interests No external appointments Age 55 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. 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. Andy Hopwood Executive vice-president, chief operating officer, upstream strategy Executive team tenure Appointed 1 November 2010 Outside interests No external appointments Age 61 Nationality British Career Andy Hopwood is responsible for BP’s upstream strategy. 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. 64 Most recently, Andy was appointed chief operating officer, upstream strategy in April 2018. Bernard Looney Chief executive, Upstream Executive team tenure Appointed 1 November 2010 Outside interests • Fellow of the Royal Academy of Engineering • Fellow of the Energy Institute Age 48 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. 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. Lamar McKay Deputy group chief executive Executive team tenure Appointed 16 June 2008 Outside interests No external appointments Age 60 Nationality American Career Lamar McKay is accountable for group strategy and long-term planning, group economics, safety and operational risk, group technology and the legal function. 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 56 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 US government claims and resolution of many of the remaining private claims. 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, Tufts University • Member, International Advisory Board of the Ministry of Petroleum and Natural Gas, Government of India • Member of the Advisory Board of the Centre for European Reform Age 53 Nationality British and Indian Career Dev Sanyal is responsible for alternative energy globally and for the group’s interests in the Europe and Asia regions. 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 BP Annual Report and Form 20-F 2018 Mediterranean in 1999. In November 2003 he was appointed chief executive, Air BP International and in June 2006 was appointed head of the group chief executive’s office. In 2007, he assumed the role of group vice president and group treasurer. During this period he was also chairman of BP investment management 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 director Executive team tenure Appointed 1 March 2011 Outside interests • Non-executive director of Ivoclar Vivadent AG, Germany Age 58 Nationality Austrian and British 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. Outside of his role, Helmut is a non-executive director of Ivoclar Vivadent. Additionally, he is an alumni and advocate of AFS, which is an NGO that promotes intercultural learning. Dame Angela Strank BP chief scientist and head of technology, downstream Executive team tenure Appointed 1 September 2018 Outside interests • Non-executive director of Severn Trent plc • Fellow of the Royal Society • Fellow of the Royal Academy of Engineering • Honorary Fellow of the Energy Institute • Honorary Professor of Earth Sciences, University of Manchester Age 66 Nationality British Career Dame Angela Strank is responsible for technology across BP’s petrochemicals, refining, fuels and lubricants businesses. As BP’s chief scientist she is accountable for developing strategic insights from advances in science and managing technology capability in BP. Dame Angela joined BP in 1982 as a geologist in exploration and has held various technical and commercial leadership roles across upstream and downstream including: chief financial officer lubricants (Americas), BP/ Statoil alliance manager Nigeria, business development manager Angola, technology vice president, and head of the BP group chief executive’s office. In 2010 Dame Angela won the UK First Women’s Award in Science and Technology, and in 2018 was the first woman to receive the UK Energy Institute’s Cadman Award. In 2017 Dame Angela was awarded a Dame Commander of the Order of the British Empire in Her Majesty the Queen’s Birthday Honours List for services to the oil industry and women in science, technology, engineering and mathematics (STEM). Dame Angela holds honorary degrees from Royal Holloway University, London (DSc) and the University of Bradford. 65 Corporate governanceBP Annual Report and Form 20-F 2018Executive management teams Upstream 1. David Campbell President, BP Russia 2. William Lin Chief operating officer, upstream regions 3. Murray Auchincloss Chief financial officer 4. Gordon Birrell Chief operating officer, production, transformation and carbon 5. Kerry Dryburgh Head of human resources 6. Nigel Jones Associate general counsel 7. Andy Hopwood Chief operating officer, upstream strategy 8. Bernard Looney Chief executive 9. Tony Brock Head of safety and operational risk 10. James Dupree Chief operating officer, developments and technology 1 3 6 5 8 10 4 2 7 9 Other business and functions leaders 1. Steve Fortune Chief information officer, information technology and services 4. Geoff Morrell Group head of communications and external affairs 2. Craig Marshall Group head of investor relations 3. Camille Drummond Vice president of global business services 5. David Anderson Chief financial officer, alternative energy 6. Trudi Charles Associate general counsel, integrated supply and trading and BP shipping 7. Nick Wayth Chief development officer, alternative energy 8. David Jardine Group head of audit 10. Joan Wales Head of safety and operational risk, other businesses and corporate 11. Jan Lyons Group head of tax 9. David Bucknall Group controller and chief financial officer, other businesses and corporate 3 2 4 1 7 6 9 8 11 66 5 10 BP Annual Report and Form 20-F 2018Our diverse and talented leaders have a wide range of skills and disciplines that support our executive team’s work. These include experts in fields such as renewable energy, finance, trading, technology and digital, and tax and treasury. Job titles correct as at 1 January 2019. 3. Tufan Erginbilgic Chief executive 4. Evelyn Gardiner Head of human resources 5. Doug Sparkman Chief operating officer, fuels, North America 6. Rita Griffin Chief operating officer, petrochemicals 7. Michael Sosso Associate general counsel, downstream and BP shipping 8. Mike O’Sullivan Chief financial officer 9. Andy Holmes Chief operating officer, fuels ASPAC and Air BP 10. Angela Strank Head of technology and BP chief scientist 2 3 7 5 8 10 Downstream 1. Mandhir Singh Chief operating officer, lubricants 2. Guy Moeyens Chief operating officer, fuels, Europe and Southern Africa 1 4 6 9 Other business and functions leaders 12. David Windle Head of solar and renewable products, alternative energy 15. Dominic Emery Vice president, group strategic planning 18. Alan Haywood Chief executive officer, integrated supply and trading 13. Carol Howle Chief executive officer, BP shipping and chief operating officer, global oil, integrated supply and trading 14. Ashok Pillai Vice president, group reward 16. Mario Lindenhayn Chief executive officer, biofuels, alternative energy 17. Lucy Knight Human resources vice president, corporate business activities and functions 19. Robert Lawson Global head of mergers and acquisitions 20. Laura Folse Chief executive officer, wind, alternative energy 21. Spencer Dale Group chief economist 22. Rahul Saxena Group ethics and compliance officer 23. Kate Thomson Group treasurer 12 14 15 16 19 17 20 21 23 13 18 22 67 Corporate governanceBP Annual Report and Form 20-F 2018Introduction from the chairman BP’s culture is well grounded with the right values and behaviours embedded by the board and the senior leadership. It is now nine months since I joined BP, initially as a non-executive director. In that time, my experience has confirmed the very positive impression of BP’s culture and values I arrived with. Based on my time spent in the business, the values of safety, respect, excellence, courage and one team are clearly embedded and genuinely lived. I see a culture that is grounded, responsible and humble – by which I mean one where people have confidence in their capabilities and the strategy, but not complacency or arrogance, and with a strong desire to learn and develop. I firmly believe that is the right combination for maintaining safe operations, earning the trust of stakeholders and embracing the challenges and opportunities the energy transition presents. A priority for my chairmanship is to see that the board continues to help sustain and evolve this positive culture by having the right capability around the table and the right engagement with stakeholders outside the boardroom. Board capability BP’s board has evolved considerably during Carl-Henric Svanberg’s tenure. Together we will look to continue its development and find the right balance of continuity and renewal. In my letter on page 6, I mentioned Dame Alison Carnwath and Pamela Daley joining the board in 2018, and that this year we are losing the distinguished services of Admiral Frank Bowman and Alan Boeckmann. Ian Davis is now in his 10th year as a director and continues as our senior independent director, having held this role since 2017. I have huge respect and regard for Ian’s skills and experience and, to provide the continuity that I believe is critical I have asked him to extend his service to at least the AGM in 2020. Ian continues to demonstrate constructive challenge and engagement both in the board and with executive management. The board therefore retains complete confidence in Ian’s independence and supports his re-election in this capacity. Governance and remuneration processes We have spent considerable time evaluating the work of the board and its committees, for which we also brought in external expertise to facilitate our discussions. This was a very valuable exercise and resulted in a number of recommendations that I am considering with the board, and certain changes to our ways of working have already been made. Details of these changes will be included in a revised set of board governance principles to be published later this year. engagement it has with both our people and with our wider community of stakeholders. As a board, we fully support this – it builds on the work we already do, and we will continue to evolve and enhance this engagement and provide more detail next year. Our oversight of the significant risks (such as operational, compliance and cyber security) facing BP continues. Both the audit committee and the safety, ethics and environmental assurance committee (SEEAC) continue to review these in depth and receive assurance from manage- ment as to how they are understood and mitigated to the level of risk acceptable to the board. In this regard, I want to once again pay tribute to the exceptional service over many years of Alan Boeckmann and Admiral Frank Bowman on the SEEAC and welcome Nils Andersen to the role of SEEAC chair. Brendan Nelson continues to chair the audit committee and brings enormous financial and regulatory experience and expertise to the role. I also want to thank Sir John Sawers for all his work chairing the geopolitical committee. John brings unique insight and experience to his role and the committee does important work overseeing significant political and related risks in key geographies where BP operates. The nomination and governance committee continues to review the skills that we need while always considering diversity and the need for independent thinking and challenge. The committee will also continue to review the size of the board to confirm that it is appropriate with a good mix of skills, experience and knowledge and the ability to maintain appropriate oversight of the executive team and provide constructive challenge and support. Executive remuneration remains a significant issue and we appreciated the strong support that was given to our remuneration report at last year’s AGM. This was the second year in which our three-year policy, developed following extensive engagement with shareholders, was in effect. Paula Reynolds is working with the remuneration committee in implementing that policy this year and to develop the new three-year policy for which shareholder approval will be sought in 2020. Paula is currently in the process of reducing her directorship commitments with other companies during 2019 to ensure that she can retain her strong focus on chairing the remuneration committee. You will see from Paula’s report on page 83 that the committee continues to exercise appropriate discretion in relation to executive remuneration. From 2019 we are linking BP’s progress towards one of our emissions reduction targets to the remuneration of a significant number of our employees, including executive directors. Engaging with stakeholders Remuneration is just one issue where I believe dialogue is invaluable, and I will continue to encourage the board to meet with a range of stakeholders, including investors, partners, and our people, and gain first-hand experience of BP’s businesses and operations around the world. Over the past year, board members visited BP operations in the US, UK and Oman and individual members also took opportunities to visit BP sites when travelling and pursuing their other interests and business activities. Personally, I have already visited our operations in several countries including in the UK, the US, China, Oman and the Netherlands. I look forward to making many more visits this year and sharing my observations and reflections in due course. Finally, I am grateful to Bob, the executive team, our employees and my colleagues on the board for all of their hard work, their commitment to BP and for the way that they have so warmly welcomed me into the company. I am excited for our future. Looking outwards, there were changes to UK legislation and governance requirements during 2018 that have now come into effect. In particular, the board is required to understand more deeply the Helge Lund Chairman 68 BP Annual Report and Form 20-F 2018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. More information See bp.com/governance for the board governance principles. D e l e g a t i o n Owners/shareholders BP board Nomination and governance committee See page 86 Remuneration committee See page 87 Chairman’s committee See page 85 Geopolitical committee See page 84 Audit committee See page 75 Safety, ethics and environment assurance committee See page 81 Strategy/group risks/annual plan Group chief executive Group chief executive’s delegations Executive management Group operations risk committee (GORC) Group financial risk committee (GFRC) Group disclosure committee (GDC) Group people committee (GPC) Group ethics and compliance committee (GECC) Resource commitments meeting (RCM) Group renewal committee Board and committee attendance 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 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 (if relevant) • Independent advice (if requested) • Independent assurance (as needed) y t i l i b a t n u o c c A Board Audit committee SEEAC Joint audit/ SEEAC Remuneration committee Geopolitical committee Nomination and governance committee Chairman’s committee Non-executive directors Carl-Heneric Svanberg Nils Andersen Paul Anderson Alan Boeckmann+ Frank Bowman Alison Carnwath Pamela Daley Ian Davis Ann Dowling Helge Lund+ Melody Meyer Brendan Nelson+ Paula Reynolds+ John Sawers+ Executive directors Bob Dudley Brian Gilvary A 9 9 4 9 9 5 4 9 9 4 9 9 9 9 A 9 9 A 7 5 2 9 9 B 9 8 4 7 9 5 3 9 9 4 8 9 8 8 B 9 9 B A B A B A B A 6 4 2 9 8 1 2 6 6 6 6 6 1 2 4 6 6 6 6 4 1 4 4 3 1 4 4 4 4 4 4 1 2 3 2 1 4 4 4 3 4 7 7 3 7 7 2 1 4 4 4 4 5 7 3 7 7 B 2 1 4 4 4 4 A 3 3 3 3 2 3 3 B 3 3 3 3 2 1 3 A 6 6 4 6 6 2 1 6 6 1 6 6 6 6 A = Total number of meetings the director was eligible to attend. B = Total number of meetings the director did attend. + Committee chair. Nils Andersen missed a board meeting due to a pre-existing external commitment. Alan Boeckmann missed meetings of the board due to unforeseen personal circumstances. Pamela Daley missed a board meeting due to a pre-existing external commitment. Melody Meyer missed a board meeting due to other commitments. Paula Reynolds missed a board meeting due to a pre-existing external commitment. John Sawers missed a board meeting due to other commitments. B 6 4 4 4 6 2 1 6 6 1 6 6 6 6 69 Corporate governanceBP Annual Report and Form 20-F 2018Board activity in 2018 Role of the board The board is responsible for the overall conduct of the group’s business. Directors have duties under both UK company law and BP’s Articles of Association. The primary tasks of the board in 2018 included: 1Active consideration and direction Active consideration and direction 1 of long-term strategy and approval of long-term strategy and approval of the annual plan of the annual plan Monitoring of BP’s Monitoring of BP’s performance against the performance against the strategy and plan strategy and plan Ensuring that the principal risks and Ensuring that the principal risks and uncertainties to BP are identified and that uncertainties to BP are identified and that systems of risk management and control systems of risk management and control are in place are in place Board and executive Board and executive management management succession succession Strategy During the year the board provided input on the group’s strategy to senior management. This included a two-day strategy session in September where it examined developments in the wider environment and debated strategic themes relating to BP’s segments, key functions and the impact of the lower carbon transition on the group’s business model. The board discussed the transition to a lower carbon world frequently during the year. The board also held several long-term strategy sessions covering upstream, downstream and the future plans for the integrated supply and trading function that supports them. Risk The board, either directly or through its monitoring 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 as part of the review of the BP Annual Report and Form 20-F 2017. • Identification and subsequent allocation of risks to the board and monitoring committees (the audit, SEEA and geopolitical committees) for 2018, and confirmation of the schedule for oversight. It received regular reports on the progress and implementation of the strategy – through updates from management and by means of a strategic performance scorecard which is discussed at each board meeting. The board monitored the company’s performance against the annual plan for 2018 and approved the forward framework for the annual plan for 2019. The board reviewed the BP Energy Outlook, updated in February 2018, which looks at long-term energy trends and projections for world energy markets. The board reviewed the group risk of cyber security in 2017 – with the audit committee and SEEAC assessing elements of cyber security risk in their work programme for the year. The allocation of the group cyber security risk to the board (with additional monitoring by the audit and SEEA committees) remains unchanged for 2019. The group risks allocated to the committees for review over the year are outlined in the reports of the committees on pages 75-86. Further information on BP’s system of risk management is outlined in How we manage risk on page 53. Information about BP’s system of internal control is on page 110. 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 governance 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 leaving unexpectedly. The board employs executive search firms when it concludes that this is an effective way of finding suitable candidates. In 2018 Egon Zehnder assisted in the search for non-executive directors. Egon Zehnder has no other connection with the company or individual directors. • Quarterly and full-year results. • Shareholder distributions. The board reviews the quarterly and full-year results, including the shareholder distribution policy. The 2018 annual report was 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 culture around our global operations. • Paul Anderson stood down from the board at the 2018 AGM. • Alison Carnwath was elected as a director at the 2018 AGM. • Helge Lund and Pamela Daley joined the board in July 2018 as non-executive director and chairman designate, and non-executive director, respectively. • Carl-Henric Svanberg stepped down as non-executive director and chairman of the board effective 31 December 2018, succeeded by Helge Lund with effect from 1 January 2019. • Alan Boeckmann and Frank Bowman will stand down from the board at the 2019 AGM. 70 BP Annual Report and Form 20-F 2018Skills and expertise In order to carry out its duties on behalf of 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 Non-executive director Background Oil and gas/ extractives/ energy Engineering/ technology Financial expertise Safety Brand/ marketing/ reputation Regulatory/ government affairs Diversity Female Non UK/US Tenure (years) Nils Andersen Alan Boeckmann Frank Bowman Alison Carnwath Pamela Daley Ian Davis Ann Dowling Helge Lund Melody Meyer Brendan Nelson Paula Reynolds John Sawers 3 5 8 1 1 9 6 1 2 8 4 4 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 social 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. At the end of 2018, there were five female directors (2017 3, 2016 3) on our board of 14. Our nomination and governance committee actively considers diversity in seeking potential candidates for appointment to the board. The board looked at gender and wider diversity across the group as part of its annual review of HR, capability and talent management. BP continues to take action to address the broader issue of diversity within the group. 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 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 and governance committee keeps the other interests of the NEDs under review to ensure that the effectiveness of the board is not compromised. Ian Davis is proposed for re-election notwithstanding he will be in his tenth year as a non-executive director. Following careful consideration, the board believes that Ian continues to provide constructive challenge and robust scrutiny of matters that come before the board. Accordingly, the board is satisfied that Ian continues to demonstrate the qualities of independence in carrying out his role as senior independent director. 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. While the chairman’s letter of appointment sets out the time commitment expected of him, those 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. The board believes that, notwithstanding the NEDs’ other appointments, they have sufficient time to fulfil their BP duties. Executive directors are permitted to take up one board appointment at an external listed company, subject to the agreement of the chairman. 71 Corporate governanceBP Annual Report and Form 20-F 2018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. Activity following prior year evaluation Actions arising from the 2017 evaluation and how these were addressed included: • Ongoing focus on capital allocation: the board continued to develop and deepen its understanding of the capital allocation process and the way in which investment decisions were taken. • Longer term vision and strategy: the board held three ‘deep dive’ discussions to explore the group’s longer-term vision and strategy, including challenges in BP’s core businesses as well as the transition to a lower carbon economy. • Employee views on safety and culture: the board developed a greater understanding of employee views within the group, particularly through review of more detailed data from the annual Pulse Survey, by using the Technology Advisory Council (TAC) reports and through site visits, town halls and employee engagement forums. • International advisory board: the board reviewed the relationship between the board, the geopolitical committee and the international advisory board (IAB). Directors were invited to IAB dinners to hear the debate on broader issues. 2018 evaluation The evaluation was undertaken through a questionnaire facilitated by an external consultant (Independent Audit) and individual interviews between the consultant and the chairman and each director and other executives. The results of the evaluation and feedback from the interviews were collectively discussed by the board and will be incorporated into a revised version of the board governance principles that will be published later this year. Fees received for an external appointment may be retained by the executive director and are reported in the directors’ remuneration report (see page 87). Neither the chairman nor the senior independent director are employed as an executive of the group. Training and induction To help develop an understanding of BP’s business, the board continues to build its knowledge through briefings and site visits. In 2018, the board continued to receive training on ethics and compliance. NEDs are expected to visit at least one business a year as part of their learning programme. In 2018, the board as a whole visited operations at the Khazzan gas field in Oman. Members of the SEEAC and other directors also visited the Cooper River petrochemicals plant in the US and the Thunder Horse platform in the Gulf of Mexico. Newly appointed NEDs follow a structured induction process. In 2018, Helge Lund, Alison Carnwath and Pamela Daley all participated in the induction programme, which includes one-to-one meetings with management and the external auditors and other management who support the board and committees. Pamela Daley’s induction is set out below as an example. Director induction programme I deeply appreciate the quality of the BP induction programme and the BP team’s dedication to educating me. Pamela Daley Non-executive director Pamela Daley, appointed in 2018, followed a tailored induction process. The programme of topics included: Board and governance • BP’s board governance model, directors’ duties, interests and potential conflicts. Business introduction • Alternative energy • BP’s business • BP’s performance relative to competitors • Downstream (refining, marketing and lubricants) • Integrated supply and trading (IST) • Lower carbon transition • Strategy • Financial planning • Upstream (exploration, development, production, overview of our operations) Functional input • Communications and corporate reporting • Ethics and compliance • External audit • Finance • Human resources, including capability and reward • Legal, including litigation • Safety • Treasury • Tax Audit committee specific • Reporting and disclosure • Business ‘deep dives’ including IST risks and compliance and procurement • Cyber security and trading regulations. 72 BP Annual Report and Form 20-F 2018Site visits NEDs visit at least one business every year to help deepen their operational understanding. In 2018, the board visited the Khazzan gas field in Oman and the International Centre for Advanced Materials (ICAM), of which BP is a significant sponsor, at the University of Manchester. Members of the SEEAC and other directors visited upstream and downstream operations in the Gulf of Mexico and South Carolina respectively. The board met local management and were briefed at each visit and subsequently provided their feedback to the appropriate committee and to the board. A number of non-executives took the opportunity to engage directly with the local workforce as described below. Khazzan, Oman The board visited the Khazzan gas field in Oman, touring the facility and meeting with local staff. They experienced the scale of the field first hand following start-up of the project. They also visited the new residential camp offices and accommodation, and spent time in the central processing facility control room. They met site staff over lunch and concluded their visit by meeting a local tribal leader who had been instrumental in securing community support for the Khazzan development. Manchester, UK In May the board attended the ICAM, where they met with leading academics to better understand how investment in research is helping advance fundamental understanding and use of materials across a variety of energy and industrial applications. Thunder Horse, US SEEAC and the audit committee chair visited Thunder Horse in July. Their trip included a half-day session with the Gulf of Mexico upstream leadership team followed by a day offshore. The regional president led the site visit and facilitated thorough discussion of working practices, the risks and challenges faced on site and management of those risks. The visit demonstrated the safety culture on board the rig. Cooper River, US In September members of the SEEAC and other directors visited Cooper River, BP’s petrochemicals plant in South Carolina. Board members met with site leaders and discussed business emergency continuity planning, safety, risk and operating culture at the plant. They also heard about new sustainability-related technologies. Workforce engagement Melody Meyer visited the Muscat office in March to meet with women from BP Oman, as part of an empowering women in business event. She advocated helping and supporting women saying, “we all have a part to play in this, we can help ensure our female colleagues’ voices are heard.” Melody highlighted the need to focus on driving value, creating advantage from change, showing respect and valuing contribution. Melody also conducted a town hall at our Houston office in July and Paula Reynolds led a BP woman’s international network event at BP’s London head office in December. Houston, US Alongside the SEEAC visit in July, members of the board also spent time in the Houston office, following the damage caused by Hurricane Harvey in 2017. They spent time with BP’s US-based integrated supply and trading team and learned about the execution of business continuity planning following Harvey. They visited key group monitoring, communication and response centres across multiple businesses. 73 Corporate governanceBP Annual Report and Form 20-F 2018Shareholder engagement Institutional investors The company operates an active investor relations programme. 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 2018 the chair of the remuneration committee undertook extensive engagement on the application of the remuneration policy prior to the AGM in May (see the remuneration committee report on page 83). Helge Lund also held one-to-one meetings with 14 major institutional investors during the last quarter of the year prior to him becoming the chairman. Senior management regularly meets with institutional investors through road shows, group and one-to-one meetings, events for socially responsible investors (SRIs) and oil and gas sector conferences throughout the year. In April, 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 investors to share their views directly with NEDs. More information 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. Shareholder engagement cycle 2018 • Fourth quarter and full year 2017 results and strategy update • Investor roadshows with executive management – fourth quarter and full year 2017 results • BP Energy Outlook presentation • US SRI meetings on remuneration • Investor meetings on remuneration, continuing into Q2 • BP Annual Report 2017 launch • BP Sustainability Report 2017 launch • BP Technology Outlook launch • Chairman and board committee chairs meetings • UKSA (retail shareholders’) meeting with the chairman • First quarter 2018 results presentation • Annual general meeting • Advancing the Energy Transition launch • BP Statistical Review of World Energy launch • Second quarter 2018 results presentation • Investor roadshows with executive management following 2Q results • Third quarter 2018 results presentation • Upstream investor day in Oman Q1 Q2 Q3 Q4 74 Retail investors BP held a further event for retail investors in conjunction with the UK Shareholders’ Association (UKSA) in 2018. The chairman and head of investor relations gave presentations on BP’s annual results, strategy and the work of the board. Shareholders’ questions were focused on BP’s activities and performance. AGM Voting levels increased in 2018 to 67.3% (of issued share capital, including votes cast as withheld), compared to 50.8% in 2017 and 64.3% in 2016. All resolutions were passed at the meeting. 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 them on any issues arising. UK Corporate Governance Code compliance BP complied throughout 2018 with the provisions of the 2016 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 of 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 and governance 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. BP remains cognizant of the new UK Corporate Governance Code and will report accordingly in our 2019 Annual Report and Form 20-F. A copy of the UK Corporate Governance Code is available at frc.org.uk. 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. Membership of the IAB in 2018 comprised Lord Patten of Barnes, Josh Bolten, President Romano Prodi, Dr Ernesto Zedillo, John Key and Dr Javier Solana. The chairman, chief executive and Sir John Sawers attend meetings of the IAB. Issues discussed in 2018 included the global economy, developments in the Middle East, political events in Latin America and the political and economic outlook in the US. The IAB discussed the UK’s potential exit from the European Union at both of its meetings during 2018. BP Annual Report and Form 20-F 2018Committee reports Audit committee The committee continued to monitor the group’s system of internal control, risk management and work of key functions as well as reviewing and challenging as appropriate the disclosures and key judgements made by management. Chairman’s introduction As in previous years, the committee has continued to review the integrity of the group’s financial reporting by challenging and debating the judgements made by management, including the estimates which are made. We receive reports from management and the external auditor each quarter highlighting significant accounting issues and judgements and have used these to inform our debate on whether BP’s financial reporting is ‘fair, balanced and understandable’. In 2018 the committee focused on the effectiveness of a number of group functions including integrated supply and trading, procurement, tax, information technology and security, and shipping. We also received presentations regarding, and reviewed performance of, the Upstream segment and the lubricants business. These reviews were valuable in not only informing the committee of the work and future plans of those functions and businesses but also examining the key risks (and associated mitigations) faced by each of them. In addition, the committee carried out reviews into the group risks of financial liquidity, cyber security and compliance with business regulations. The transition to Deloitte from EY was completed in 2018. We met with both EY and Deloitte during 2018 as the transition occurred and oversaw and monitored Deloitte’s work as they settled into their role. We meet regularly with the lead audit partner. Nils Andersen retired from the committee in September 2018 as he joined the SEEAC. I would like to thank Nils for his service to the committee, and for the challenge and perspective he provided as a member. We were very pleased to welcome Dame Alison Carnwath to the committee in May 2018 with Pamela Daley also joining in October 2018. Each of them bring excellent financial and other relevant skills to the committee. 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. Members Brendan Nelson Nils Andersen Member since November 2010 and chair since April 2011 Member since October 2016; resigned September 2018 Alison Carnwath Member since May 2018 Pamela Daley Member since October 2018 Paula Reynolds Member since May 2015 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 he is the audit committee member with recent and relevant financial experience as outlined in the UK Corporate Governance Code and competence in accounting and auditing as required by the FCA’s Corporate Governance Rules in DTR7. It considers that the committee as a whole has an appropriate and experienced blend of commercial, financial and audit expertise to assess the issues it is required to address, as well as competence in the oil and gas sector. The board also determined that the audit committee meets the independence criteria provisions of Rule 10A-3 of the US Securities Exchange Act of 1934 and that Brendan may be regarded as an audit committee financial expert as defined in Item 16A of Form 20-F. Meetings and attendance There were nine committee meetings in 2018, of which three were by teleconference. All directors attended every meeting during the period in which they were committee members, except for Nils Andersen, Alison Carnwath and Paula Reynolds who all missed a meeting each due to pre-existing external commitments. Regular attendees at the meetings include the chief financial officer, group controller, chief accounting officer, group head of audit, group general counsel and external auditor. 75 Corporate governanceBP Annual Report and Form 20-F 2018Activities during the year Financial disclosure The committee reviewed the quarterly, half-year and annual financial statements with management, focusing on the: • Integrity of the group’s financial reporting process. • Clarity of disclosure. • Compliance with relevant legal and financial reporting standards. • Application of accounting policies and judgements. As part of its review, the committee received quarterly updates from management and the external auditor in relation to accounting judgements and estimates including those relating to the Gulf of Mexico oil spill, recoverability of asset carrying values and other matters. The committee keeps under review the frequency of results reporting during the year. The committee reviewed the assessment and reporting of longer-term viability, risk management and the system of internal control, including the reporting and categorization of risk across the group and the examination of what might constitute a significant failing or weakness in the system of internal control. It also examined the group’s modelling for stress testing different financial and operational events, and Risk reviews The principal risks allocated to the audit committee for monitoring in 2018 included those associated with: Trading activities: including risks arising from shortcomings or failures in systems, risk management methodology, internal control processes or employees. In reviewing this risk, the committee focused on external market developments and how BP’s trading function had responded – including new areas of activity, such as emissions trading and impacts on the control environment. The committee further considered updates in the 76 See Glossary considered whether the period covered by the company’s viability statement was appropriate. The committee considered the BP Annual Report and Form 20-F 2017 and assessed whether the report was fair, balanced and understandable and provided the information necessary for shareholders to assess the group’s position and performance, business model and strategy. In making this assessment, the committee examined disclosures during the year, discussed the requirement with senior management, confirmed that representations to the external auditors had been evidenced and reviewed reports relating to internal control over financial reporting. The committee made a recommendation to the board, who in turn reviewed the report as a whole, confirmed the assessment and approved the report’s publication. Other disclosures reviewed included: and compliance functions, development of the anti-bribery and corruption elements of the programme, enhanced policies, tools and training and strengthening of counter-party risk measures, including due diligence. The committee also reviewed key areas of BP’s legal function that advise on compliance matters. Cyber security risk: including inappropriate access to or misuse of information and systems and disruption of business activity. The committee reviewed ongoing developments in the cyber security landscape, including events in the oil and gas industry and within BP itself. The review focused on the improvements made in managing cyber risk, including the application of the three lines of defence model and examining the indicators associated with risk management and barrier performance. Financial liquidity: including the risk associated with external market conditions, supply and demand and prices achieved for BP’s products which could impact financial performance. The committee reviewed the key price assumptions used by the group for investment appraisal and the judgements underlying those 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 . These assumptions also impacted financial reporting (see page 79). BP’s principal risks are listed on page 55. For 2019, the board has agreed that the committee will continue to monitor the same four group risks as for 2018. Other reviews • Oil and gas reserves. • Pensions and post-retirement Other reviews undertaken in 2018 by the committee included: benefits assumptions. • Risk factors. • Legal liabilities. • Tax strategy. • Going concern. • IFRS 16 (lease accounting). integrated supply and trading function’s risk management programme, including compliance with regulatory developments and activities in response to cyber threats. 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 the group’s ethics and compliance programme, including the work of the business integrity and ethics • Lubricants: including strategy and strategic progress, financial performance, risk management and controls, audit findings, key litigation and ethics and compliance findings. • Upstream: including vision and priorities, structure and portfolio, financial controls and the balance sheet, an overview of tangible and intangible assets and a review of the segment’s finance organization. • Shipping: including an overview of BP shipping’s role and operating model, financial performance, strategy, risk management and controls and the impact of IFRS 16 (lease accounting standard). • Tax: including strategy and strategic progress, key drivers of the group’s effective tax rate, the global indirect tax environment and the tax modernization programme. • Procurement: including strategy and strategic progress, financial performance, risk management and controls, audit findings, key litigation and ethics and compliance findings. • Capability and succession in BP’s finance function, including the group’s finance modernization programme. • Assessment of financial metrics for executive remuneration: consideration of financial performance for the group’s 2018 annual cash bonus scorecard and performance share plan, including adjustments to plan conditions and NOIs. • Auditor transition: regular reports from the external auditor regarding its transition into the role including detailed updates on issues identified by the external auditor. • Internal controls: assessments of management’s plans to remediate the external auditors findings in relation to IT access risks. BP Annual Report and Form 20-F 2018 Inte rnal control and risk management The committee received quarterly reports on the findings of group audit in 2018. The committee met privately with the group head of audit and key members of his leadership team. The committee reviewed the effectiveness of internal audit. The audit committee also held private meetings with the group ethics and compliance officer during the year. Training The committee held a review on reserves and pensions. It received technical updates from the chief accounting officer on developments in financial reporting and accounting policy, in particular regarding the introduction of IFRS 16 ‘Leases’ accounting from the start of 2019. Integrated supply and trading visit In October, the committee held its meeting at BP’s integrated supply and trading (IST) business in London and conducted its annual tour of the business which covered oil and gas market fundamentals, finance and risk, IST’s strategy, and presentations on oil products and LNG trading. Accounting judgements and estimates Areas of significant judgement considered by the committee in 2018 and how these were addressed included: Key judgements and estimates in financial reporting Gulf of Mexico oil spill BP uses judgement in relation to the recognition of provisions relating to the Gulf of Mexico oil spill. The timing and amounts of the remaining cash flows are subject to uncertainty and estimation is required to determine the amounts provided for. Audit committee activity Conclusions/outcomes A review of the provisioning for and disclosure of uncertainties relating to the Gulf of Mexico oil spill was undertaken each quarter as part of the review of the stock exchange announcement. Particular focus was given to updates to the provision related to business economic loss (BEL) and other claims related to the Gulf of Mexico oil spill, including the continuing effect of the Fifth Circuit May 2017 opinion on the matching of revenues with expenses when evaluating BEL claims. The group income statement includes a pre-tax charge of $1.2 billion in relation to the Gulf of Mexico oil spill. Disclosure includes information on remaining uncertainties. The audit committee noted that following the significant number of BEL claim settlements in the year, the degree of judgement necessary to determine the year-end provision had reduced significantly. Oil and natural gas accounting, including reserves BP uses technical and commercial judgements when accounting for oil and gas exploration, appraisal and development expenditure and in determining the group’s estimated oil and gas reserves. Held an in-depth review of BP’s policy and guidelines for compliance with oil and gas reserves disclosure regulation, including the group’s reserves governance framework and controls. Reserves estimates based on management’s assumptions for future commodity prices have a direct impact on the assessment of the recoverability of asset carrying values reported in the financial statements. Judgement is required to determine whether it is appropriate to continue to carry intangible assets related to exploration costs on the balance sheet. Reviewed exploration write-offs as part of the group’s quarterly due diligence process. Received briefings on the status of upstream intangible assets, including the status of items on the intangibles assets ‘watch-list’, including certain Gulf of Mexico licences which expired in 2013 and 2014. Received the output of management’s annual intangible asset certification process used to ensure accounting criteria to continue to carry the exploration intangible balance are met. Exploration write-offs totalling $1.1 billion were recognized during the year. BP remains committed to developing the Gulf of Mexico licences and believes it is appropriate to continue to capitalize the costs. Exploration intangibles totalled $16.0 billion at 31 December 2018. 77 Corporate governanceBP Annual Report and Form 20-F 2018Key judgements and estimates in financial reporting Recoverability of asset carrying values Determination as to whether and how much an asset, cash generating unit (CGU) or group of CGUs containing goodwill is impaired involves management judgement and estimates on uncertain matters such as future commodity pricing, discount rates, production profiles, reserves and the impact of inflation on operating expenses. Investment in Rosneft Audit committee activity Conclusions/outcomes Reviewed the group’s oil and gas price assumptions. Reviewed the group’s discount rates for impairment testing purposes. Upstream impairment charges, reversals and ‘watch-list’ items were reviewed as part of the quarterly due diligence process. The group’s long-term price assumptions for Brent oil, and Henry Hub gas were unchanged from 2017. The group’s discount rates used for impairment testing were also unchanged. Impairments of $0.1 billion were recorded in the year, net of impairment reversals. Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. Reviewed the judgement on whether the group continues to have significant influence over Rosneft. BP has retained significant influence over Rosneft throughout 2018 as defined by IFRS. BP uses the equity method of accounting for its investment in Rosneft and BP’s share of Rosneft’s oil and natural gas reserves is included in the group’s estimated net proved reserves of equity-accounted entities. The equity-accounting treatment of BP’s 19.75% interest in Rosneft continues to be dependent on the judgement that BP has significant influence over Rosneft. Derivative financial instruments For its level 3 derivative financial instruments, BP estimates their fair value using internal models due to the absence of quoted market pricing or other observable, market- corroborated data. Judgement may also be required to determine whether contracts to buy or sell commodities meet the definition of a derivative. Considered IFRS guidance on evidence participation in policy-making processes. Received reports from management which assessed the extent of significant influence, including BP’s participation in decision making. Received a briefing on the group’s trading risks and reviewed the system of risk management and controls in place, including those covering the valuation of level 3 derivative financial instruments, using models where observable market pricing is not available. The committee annually reviews the control process and risks relating to the trading business. BP has assets and liabilities of $3.6 billion and $3.1 billion respectively recognized on the balance sheet for level 3 derivative financial instruments at 31 December 2018, mainly relating to the activities of the integrated supply and trading function (IST). BP’s use of internal models to value certain of these contracts has been disclosed in Note 30 in the financial statements. 78 See Glossary BP Annual Report and Form 20-F 2018 Audit committee activity Conclusions/outcomes Received briefings on decommissioning, environmental, asbestos and litigation provisions, including the requirements, governance and controls for the development and approval of cost estimates and provisions in the financial statements. Reviewed the group’s discount rates for calculating provisions, including the change to use the nominal discount rate (i.e. taking account of expected inflation) from the second quarter of 2018. Decommissioning provisions of $13.6 billion were recognized on the balance sheet at 31 December 2018. The discount rate used by BP to determine the balance sheet obligation at the end of 2018 was a nominal rate of 3% – based on long-dated US government bonds. The impact of this revised rate has been disclosed. Key judgements and estimates in financial reporting Provisions BP’s most significant provisions relate to decommissioning, environmental remediation and litigation. 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 many years in the future and the exact requirements that will have to be met when a removal event occurs are uncertain. Assumptions are made by BP in relation to settlement dates, technology, legal requirements and discount rates. The timing and amounts of future cash flows are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognized. Following a regular review of decommissioning cost estimates, from 30 June 2018 the present value of the decommissioning provision was determined by discounting the estimated cash flows expressed in expected future prices, i.e. taking account of expected inflation. Prior to 30 June 2018, the group estimated future cash flows in real terms. Pensions and other post-retirement benefits Accounting for pensions and other post- retirement benefits involves making estimates when measuring the group’s pension plan surpluses and deficits. These estimates require assumptions to be made about uncertain events, including discount rates, inflation and life expectancy. Reviewed the group’s assumptions used to determine the projected benefit obligation at the year end, including the discount rate, rate of inflation, salary growth and mortality levels. The method for determining the group’s assumptions remained largely unchanged from 2017. The values of these assumptions and a sensitivity analysis of the impact of possible changes on the benefit expense and obligation are provided in Note 24. At 31 December 2018, surpluses of $6.0 billion and deficits of $8.4 billion were recognized on the balance sheet in relation to pensions and other post-retirement benefits. External audit Audit risk The external auditor set out its audit strategy for 2018, identifying significant audit risks to be addressed during the course of the audit. These included: • The risk of impairment in certain cash-generating units which are particularly sensitive to changes in the key assumptions, in particular the long-term oil and gas price assumptions. • The carrying value of certain exploration and appraisal assets where there could be potential indicators of impairment through licence expiry and/or partner withdrawal. • Accounting for structured commodity transactions in the integrated supply and trading function. • Level 3 of derivative financial instruments valuations within the integrated supply and trading function which involve using bespoke valuation models and/or unobservable inputs. • Management override of controls. The committee received updates during the year on the audit process, including how the auditor had challenged the group’s assumptions on these issues. Audit fees The audit committee reviews the fee structure, resourcing and terms of engagement for the external auditor annually; in addition it reviews the non-audit services that the auditor provides to the group on a quarterly basis. Fees paid to the external auditor for the year were $42 million (2017 $47 million), of which 5% was for non-audit assurance work (see Financial statements – Note 36). The audit committee is satisfied that this level of fee is appropriate in respect of the audit services provided and that an effective audit can be conducted for this fee. Non-audit or non-audit related assurance fees were $2 million (2017 $3 million). Non-audit or non-audit related services consisted of other assurance services. 79 Corporate governanceBP Annual Report and Form 20-F 2018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. 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 prohibition of non-audit tax services and the limitation of audit-related work which falls within defined categories. BP’s policy on non-audit services states that the auditor may not perform non-audit services that are prohibited by the SEC, Public Company Accounting Oversight Board (PCAOB), 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 considered for permitted non-audit services only when its expertise and experience of the company is important. Approvals for individual engagements of pre-approved permitted services below certain thresholds are delegated to the group controller or the chief financial officer. Any proposed service not included in the permitted services categories must be approved in advance either by the audit committee 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 accountant’s fees and services on page 301. The committee’s policies were updated in 2018 to clarify the engagement of the incoming auditor, Deloitte, and the outgoing auditor (and auditor of Rosneft) EY. Committee evaluation The audit committee undertakes an annual evaluation of its performance and effectiveness. 2018 evaluation For 2018, an external assessment was used to evaluate the work of the committee as part of a wider review of the operation of the board as a whole. The review concluded that it had performed effectively. Areas of focus for 2019 include succession planning for membership of the committee, a site visit to global business services Kuala Lumpur and integrated supply and trading Singapore and a further review of capital spending. Audit effectiveness The effectiveness, performance and integrity of the external audit process was evaluated through separate surveys completed by 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 survey sent to management comprised questions across five main criteria to measure the auditor’s performance: • Robustness of the audit process. • Independence and objectivity. • Quality of delivery. • Quality of people and service. • Value added advice. The 2018 evaluation was the last of EY as the outgoing auditor. It also included certain questions about the effectiveness of the transition to the incoming auditor, Deloitte. The results of the survey indicated that the external auditor’s performance had remained largely consistent in key areas compared with the previous year. Areas with high scores and favourable comments included quality of accounting and auditing judgement and the working relationship with management. Areas for improvement were identified but none impacted on the effectiveness of the audit. The results of the questions regarding auditor transition indicated that management were confident that Deloitte would be effective in their role. The results of the survey were discussed with Deloitte for consideration in their 2018 audit 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 at least quarterly. The effectiveness of the external auditor is evaluated by the audit committee. The committee assessed the new auditor’s approach to providing audit services as the team undertook its first audit. On the basis of such assessment, the committee concluded that the audit team was providing the required quality in relation to the provision of the services. The audit team had shown the necessary commitment and ability to provide the services together with a demonstrable depth of knowledge, robustness, independence and objectivity as well as an appreciation of complex issues. The team had posed constructive challenge to management where appropriate. Audit transition Deloitte was appointed for the statutory audit, with effect from 2018 following a tender process in 2016. The committee monitored the transition of BP’s statutory auditor from EY to Deloitte. This included: • Receiving reports from the audit transition team, including an overview of operational activities and the termination of non-audit services being provided by Deloitte to BP – which would be prohibited when Deloitte became the group’s statutory auditor. This included Deloitte stepping down as independent adviser to BP’s remuneration committee. • Requiring management to report to the committee on any services undertaken by the statutory auditor in line with the group’s policies relating to non-audit services. • Requiring confirmation of Deloitte’s compliance with BP’s independence and ethics and compliance rules. Deloitte confirmed its independence to the committee in October 2017. EY resigned on 29 March 2018 following completion of the 2017 audit. The committee also received reports from the external auditor’s transition team in April, May and July 2018 and an update to their plan in December 2018. 80 BP Annual Report and Form 20-F 2018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 their 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. Safety, ethics and environment assurance committee (SEEAC) At every site visit, we engage with the local leadership who help to embed a culture focused on operational risk mitigation. Members Alan Boeckmann Member since September 2014 and chair since May 2016 Nils Andersen Member since December 2018 Paul Anderson Member since February 2010; resigned May 2018 Frank Bowman Member since November 2010 Ann Dowling Member since February 2012 Melody Meyer Member since May 2017 John Sawers Member since July 2015 Meetings and attendance There were six committee meetings in 2018. All directors attended every meeting for which they were eligible, apart from Alan Boeckmann who missed two meetings due to unforeseen personal circumstances. 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 has access to the chair and secretary to the committee as required. 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. The group chief executive receives invitations to join the private meetings on an ad hoc basis and at least once a year the head of group audit and at least twice a year the group ethics and compliance officer are invited to a private meeting with the committee. Chairman’s introduction The committee’s focus continued to be on working with executive management to drive safe, ethical and reliable operations. It continued to provide constructive challenge as part of its review of the executives’ management of the highest priority non-financial group risks assigned to SEEAC. The risks under our remit remained the same as for 2017: marine, wells, pipelines, explosion or release at facilities, major security incidents and cyber security in the process control network. The committee receives reports on each of these risks and monitors their management and mitigation. Following publication of the company’s second Modern Slavery Act (MSA) statement in 2018, the committee again reviewed related work practices in BP and will continue to review progress in developing and embedding those practices. In 2018 it also reviewed the BP Sustainability Report 2017. The committee made two site visits in the year (see page 73). In July members of the committee visited the Thunder Horse platform in the Gulf of Mexico, and in September members visited Cooper River petrochemicals plant in South Carolina. The level of access into the operations on such visits gives the directors first hand and direct insight. This framework provides an opportunity for meaningful and open dialogue with the local site teams, allowing the committee to better fulfil its obligations. In May 2018, Paul Anderson retired from the board and the committee. In preparation for my stepping down from the BP board at the annual general meeting in May 2019, Nils Andersen, who was appointed to the committee in December 2018, will assume the role of the chair of SEEAC from April 2019. Alan Boeckmann Committee chair 81 Corporate governanceBP Annual Report and Form 20-F 2018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 quarterly reports on their assurance work and their annual review of the system of internal control and risk management. The committee also received regular reports from the group chief executive and vice president for S&OR on operational risk, including regular reports prepared on the group’s health, safety and environmental performance and operational integrity. These included meeting-by-meeting measures of personal and process safety, environmental and regulatory compliance, security and cyber risk analysis, as well as quarterly reports from group audit. In addition, the group ethics and Site visits In July members of the committee, and other directors, visited the Houston office and went offshore to Thunder Horse in the Gulf of Mexico. The Houston visit included time with various teams understanding the effects of Hurricane Harvey, how central office-based functions support the offshore community and other group monitoring teams. In preparation for the offshore visit to Thunder Horse the directors met with the Gulf of Mexico leadership. Offshore, there was a full tour of the asset including control room, topsides and drilling rig and plenty of opportunity was provided to converse with employees on the rig. In September, committee members, and other directors, Corporate reporting compliance officer and the group auditor 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 relating to: • Marine. • Wells. • Pipelines. • Explosion or release at our facilities. • Major security incidents. • Cyber security (process control networks). The committee reviewed these risks and their management and mitigation in depth with relevant executive management. visited the petrochemicals plant, Cooper River, in South Carolina. During the visit, directors were able to discuss business continuity planning and emergency response which had been in effect just prior to the visit as a result of Hurricane Florence. For all visits, committee members and other directors received briefings on operations, the status of conformance with BP’s operating management system, key business and operational risks and risk management and mitigation. Committee members reported back in detail about each visit to the committee and subsequently to the board. See page 73 for further details. The committee was responsible for the overview of the BP Sustainability Report 2017. The committee reviewed content and worked with the external auditor with respect to their assurance of the report. 82 Committee evaluation In 2018, the committee examined its performance and effectiveness through an externally facilitated evaluation which included individual interviews. Discussion focused on the responsibilities of the committee, 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 to both inform and drive discussion. The evaluation results continued to be 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. The committee agreed to review its remit in 2019. Site visits remained an important element of the committee’s work, acknowledged through the responses in the evaluation process. These gave members the opportunity to examine and witness risk management processes embedded in businesses and facilities, including the right management culture. Joint meetings between the SEEAC 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 The audit committee and SEEAC hold joint meetings on a quarterly basis to simplify reporting of key issues that are within the remit of both committees and to make more effective use of the committees’ time. Each committee retains full discretion to require a full presentation and discussion on any joint meeting topic at their respective meeting if deemed appropriate. The committees jointly met four times in 2018, with the chairmanship of the meetings alternating between the chairman of the audit committee and chairman of the SEEAC. Topics discussed at the joint meetings were the quarterly ethics and compliance reports (including significant investigations and allegations) and the 2019 forward programmes for the group audit and ethics and compliance functions. BP Annual Report and Form 20-F 2018Remuneration committee Chair’s introduction As the new committee chair, I took the opportunity in the autumn to engage with some of our institutional shareholders. In a changing governance landscape, it has been important to ensure our stakeholders continue to be heard. We have reviewed the responsibilities of the committee and have extended the scope to include oversight of remuneration below board level. We have continued to operate under the policy approved by shareholders in 2017. Our focus for 2019 will of course be the preparation of a new policy for approval by shareholders at the 2020 AGM. Pamela Daley has joined the remuneration committee from 1 January 2019. We welcome Pamela to the committee and look forward to her valuable contribution. PricewaterhouseCoopers LLP has continued as our independent adviser following their appointment in 2017. PwC has other engagements with the company to provide certain services none of which are deemed material in this context. Paula Rosput Reynolds 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 to business performance. The committee recognizes the remuneration principles applicable to all employees below board level. Key responsibilities • Recommend to the board the remuneration principles and policy for the chairman and the executive directors while considering policies for employees below the board. • Determine the terms of engagement, remuneration, benefits and termination of employment for the chairman and the executive directors, executive team and the company secretary in accordance with the policy. • Review the relevant remuneration principles and policies for employees below the executive team. • Prepare the annual remuneration report to shareholders to show how the policy has been implemented. • Approve the principles of any equity plan that requires shareholder approval. • Ensure termination terms and payments to executive directors and the executive team are fair. • Approve changes to the design of remuneration for BP group leaders, as proposed by the group chief executive. • Receive, and take into account as appropriate, regular updates on workforce views and engagement initiatives related to remuneration. • Ensure insight from data sources on pay ratio, gender pay gap and other workforce remuneration outcomes are considered as appropriate. • Maintain appropriate dialogue with shareholders on remuneration matters. • Monitor the alignment of incentives and remuneration for all employees below the executive team with the expected values and behaviours. • Engage independent consultants or other advisers as the committee may from time to time deem necessary, at the expense of the company. Members Paula Reynolds Member since September 2017 and chair since May 2018 Alan Boeckmann Member since May 2015 Pamela Daley Member since January 2019 Ian Davis Member since July 2010 Ann Dowling Member since July 2012 and chair since May 2015; resigned May 2018 Brendan Nelson Member since May 2017 83 Corporate governanceBP Annual Report and Form 20-F 2018Meetings and attendance The chairman and the group chief executive attend meetings of the committee except for matters relating to their own remuneration. The group chief executive is consulted on the remuneration of the chief financial officer, the executive team and more broadly on remuneration across the wider employee population. Both the group chief executive and chief financial officer are consulted on matters relating to the group’s performance. The group human resources director 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. The committee met seven times during the year. All directors attended each meeting that they were eligible to attend, either in person or by telephone, except Alan Boeckmann who was not able to attend two meetings due to unforeseen personal circumstances. Activities during the year In the period before the 2018 AGM, the committee focused on the outcomes for 2017. This involved reviewing directors’ salaries and the group’s performance outcome which in turn determined the annual bonus and the performance share plan. PwC has continued as independent adviser during 2018. The committee continued to monitor developments in potential regulation and legislation and resulting implications. It also considered the company’s disclosure on the UK gender pay gap. In each of its meetings, the committee focused on the overall quantum of executive director remuneration and its alignment to the broader group of employees in BP. It has sought to reflect the views of shareholders and the broader societal context in its decisions. Shareholder engagement There was engagement with shareholders and proxy voting agencies ahead of the 2018 AGM, carried out by the chair of the committee, the chairman and company secretary as required. The new committee chair continued engagement throughout the year, primarily with larger shareholders and representative bodies, in light of evolving regulation and related remuneration issues. Committee evaluation An externally facilitated evaluation was undertaken to examine the committee’s performance in 2018. The evaluation concluded that the committee had worked well and had responded to the previous evaluation by increasing its remit to take on oversight of remuneration below board level. Focus areas for 2019 include responding to regulation and governance reform and planning for the new remuneration policy to be brought to shareholders for approval in 2020. The commitment to stay focused on external developments and emerging ‘best practice’ and improving remuneration reporting remained. See page 87 for the Directors’ remuneration report. 84 Geopolitical committee Chairman’s introduction I am pleased to report on the work of the geopolitical committee in 2018, which continued to develop and evolve during the year. During 2018 I also joined discussions of the international advisory board. Paul Anderson stood down in May 2018. I want to thank Paul for his valuable contribution. We welcomed Nils Andersen to the committee in August 2018 and his experience is invaluable given he was CEO of major companies, such as Carlsberg and Mærsk, which had operations in many jurisdictions with significant political risk considerations. Other board members joined our meetings from time to time. 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. – 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 BP’s activities in the context of political and economic developments on a regional basis and advise the board on these elements in its consideration of BP’s strategy and the annual plan. BP Annual Report and Form 20-F 2018Members John Sawers Member since September 2015 and chair since April 2016 Nils Andersen Member since August 2018 Paul Anderson Member since September 2015; resigned May 2018 Frank Bowman Member since September 2015 Ian Davis Member since September 2016 Melody Meyer Member since May 2017 Meetings and attendance The chairman and group chief executive regularly attend committee meetings. The executive vice president, regions and the vice president, government and political affairs attend meetings as required. The committee met four times during the year. All directors attended each meeting that they were eligible to attend. Chairman’s and nomination and governance committees Activities during the year The committee developed and broadened its work over the year. It discussed BP’s involvement in the key countries where it has existing investments or is considering investment in detail. These included the US, Russia, Mexico, Brazil, India and China. It considered broader policy issues such as the US domestic and foreign policy and the political and economic impact of a low oil price on producing countries. We reviewed the geopolitical background to BP’s global investments and the politics around climate change. Chairman’s introduction The chairman’s and the nomination and governance committees were actively involved in the evolution of the board in 2018. In October, Carl-Henric Svanberg stood down as chairman of both committees and I pay tribute to his exceptional service since 2010. The board expanded the nomination committee’s remit in September 2018 to help fulfil requirements provided in the new UK Corporate Governance Code and it was re-named the nomination and governance committee. It also continues to focus on board renewal and diversity as well as the talent in the senior levels of executive management and development of future leaders. Committee evaluation The committee reviewed its performance through feedback from the external evaluation of its work and of the work of the board as a whole. The evaluation concluded that the committee was working well and considering the right issues. The committee currently meets four times a year and is considering additional meetings. The committee and board felt that there should be greater integration between the work of the board, the committee and the international advisory board. This is being further considered during 2019. Helge Lund Chair of the committees Chairman’s committee Role of the committee To provide a forum for matters to be discussed by 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 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. 85 Corporate governanceBP Annual Report and Form 20-F 2018Meetings and attendance The committee met six times in 2018. All directors attended all the meetings for which they were eligible, except that Nils Andersen was excused from two meetings due to a potential conflict of interest and Alan Boeckmann missed two meetings due to unforeseen personal circumstances. Bob Dudley and Brian Gilvary joined meetings where the chairman’s succession was discussed. Matters relating to the business of the nomination and governance committee were also discussed at some meetings. Activities during the year • Evaluated the performance of the chairman and the group chief executive. Nomination and governance committee Role of the committee The committee ensures an orderly succession of candidates for directors and the company secretary and oversees corporate governance matters for the group. Key responsibilities • Identify, evaluate and recommend candidates for appointment or reappointment as directors. • Review the outside directorships/commitments of the NEDs. • Review the mix of knowledge, skills experience and diversity of the board to ensure the orderly succession of directors. • Identify, evaluate and recommend candidates for appointment as • Considered the composition of and the succession plans for the company secretary. executive team. • Discussed the strategy options for the company, including the transition to a lower carbon future. • Review developments in law, regulation and best practice relating to corporate governance and make recommendations to the board on appropriate actions to allow compliance. Committee evaluation The committee continues to work well. The balance of skills and experience amongst its non-executive director membership ensures it is best able to support and challenge the company as it implements its strategy. Members Helge Lund Carl-Henric Svanberg Member since July 2018 and chair since September 2018 Member since September 2009 and chair since January 2010; resigned as chair September 2018 and from committee December 2018 Alan Boeckmann Member since April 2016 Ian Davis Member since August 2010 Ann Dowling Member since May 2015 and resigned May 2018 Brendan Nelson Member since September 2018 Paula Reynolds Member since May 2018 John Sawers Member since April 2016 Meetings and attendance The committee met three times in 2018. During the second half of the year, matters relating to the appointment of new directors were considered jointly with the chairman’s committee. All directors attended each meeting that they were eligible to attend, except Paula Reynolds due to pre-existing external commitments. Activities during the year The committee continued to monitor the composition and skills of the board. The committee will continue to focus on ensuring that the board’s composition is strong and diverse. During the year, it was agreed that the committee would assume oversight of governance. Committee evaluation Following the board evaluation, it was agreed that the committee would also focus on governance requirements arising from the new UK Corporate Governance Code. 86 BP Annual Report and Form 20-F 2018Directors’ remuneration report Contents 90 2018 performance and pay outcomes 91 2018 annual bonus outcome 92 2016-18 performance share plan outcome 94 Alignment with strategy 95 Executive directors’ pay for 2018 97 Wider workforce in 2018 100 Stewardship and executive director interests 102 Non-executive director outcomes and interests 104 Other disclosures 105 Executive director remuneration policy and implementation for 2019 109 Non-executive director remuneration policy for 2019 Targets are strongly aligned with the company’s strategic priorities, they are ambitious and require material effort to achieve outcomes. Paula Rosput Reynolds Chair of the remuneration committee Dear shareholder, Following extensive shareholder consultation led by my board colleague Professor Dame Ann Dowling, BP introduced our current remuneration policy in 2017. Thus 2018 was our second year using this policy. The remuneration committee believes the structure remains fit for purpose, the targets are strongly aligned with the company’s strategic priorities, they are ambitious and require material effort to achieve outcomes, and the rewards conferred to date align with our financial results and strategic progress. Please refer to the ‘Remuneration at a glance’ table for an overview. The policy delivers remuneration in three parts: a market-aligned foundation of base salary, benefits and retirement provision; annual incentives based on measures that reflect our strategy, assessed against targets that require progressive improvement year-on-year; and a material opportunity to earn shares at the end of a three-year performance period, which is accompanied by a shareholding requirement to ensure our executive directors’ interests align with your own. Of course it is not enough to rely on a purely formulaic application of policy. Therefore the committee engages in a dialogue with Bob Dudley, Brian Gilvary and our board colleagues, particularly those on the safety, ethics and environment assurance committee (SEEAC) and the main board audit committee (MBAC) to test the reasonableness of the outcomes. This dialogue ensures we are well equipped to apply and explain discretion and judgement as needed. Results and progress in 2018 BP delivered another year of disciplined execution in 2018, alongside further progress against our five-year strategy to 2021. Strong operating performance across all our businesses has more than doubled our underlying replacement cost profit to $12.7 billion, with operating cash flow excluding Gulf of Mexico oil spill payments of $26.1 billion. BP distributed $8.1 billion in dividends in 2018, and continued the share buyback programme started in 2017 to offset the dilutive effects of the scrip shares. BP continues to play an active role in relation to the energy transition. We are carefully considering our mix of natural gas and oil, while investing in new technology and businesses that have the potential to contribute to a lower carbon world through our ‘reduce, improve, create’ framework. Our acquisition of Chargemaster, the UK’s largest electric vehicle charging company (see page 42), and further expansion of the solar company Lightsource BP (see page 47), are among the most promising investments consistent with our commitment to advancing a lower carbon future. At the same time we continue to sustain our traditional business. Our organic reserves replacement ratio for the year was 100%, and our acquisition of BHP assets provides us with significant new reserves and opportunities for growth. We delivered a further six major projects in 2018, bringing the total to 19 over the 2016-18 cycle. 87 Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018Remuneration at a glance Key features Purpose and link to strategy Outcomes for 2018 Implementation in 2019 d n a y r a l a S s t fi e n e b • Salary is reviewed annually and, if appropriate, increased following the AGM. • Relates to market and our wider workforce. • Fixed remuneration reflecting • Bob Dudley’s salary unchanged • Bob Dudley’s salary the scale and complexity of our business, enabling us to attract and keep the highest calibre global talent. at $1,854,000. to remain at $1,854,000. • Brian Gilvary’s salary increased • Brian Gilvary’s salary increased by 2% to £775,000. by 2% to £790,500. • Benefits remain unchanged. • Benefits remain unchanged. • To recognize competitive practice in home country. • Bob is a member of both US pension (defined benefit) and retirement savings (defined contribution) plans. • Brian is a member of a UK final salary defined benefit pension plan, and receives a cash allowance in lieu of further service accrual. • Bob’s defined benefit pension did not increase in 2018. His actual and notional company contributions were more than offset by investment losses within his retirement savings plans, hence he received no net benefit in 2018. • Brian’s accrued defined benefit pension increase was below inflation. He received a cash allowance at 35% of salary, which is included in the single figure table. • Arrangements for Bob will continue unchanged. • Brian has offered to accelerate the scheduled reductions in his cash allowance. These will now reduce by 5% of salary at each of 1 June 2019, 2020 and 2021, and a further 5% of salary at 1 June 2023, taking his cash allowance to 15% of salary. • These proposed changes reduce Brian’s cash supplement sooner than the transition for other members of the BP UK defined benefits plan. He will not receive any form of compensation related to the reductions. • 112.5% of salary at target, and 225% at maximum. • To incentivize delivery of our annual and strategic goals. • 50% of the bonus is paid in cash and 50% is mandatorily deferred and held in BP shares for three years. • The 50% deferral reinforces the long-term nature of our business and the importance of sustainability. • Against our scorecard of safety • We will include an and operational risk (20%), reliable operations (30%) and financial performance (50%), our performance score is 81% of target (40.5% of maximum). environmental target, weighted at 10%, in our performance scorecard for 2019. • Annual grant of performance • To link the largest part of shares, representing the maximum outcome. – 500% of salary for group chief executive. – 450% of salary for chief financial officer. • Shares only vest to the extent performance conditions are met. remuneration opportunity with the long-term performance of the business. The outcome varies with performance against measures linked directly to financial returns and strategic priorities. • Against our balanced scorecard of financial measures (67%), and strategic imperatives (33%), our 2016-18 performance score is 90.5% of maximum. • The committee has exercised discretion to reduce the actual vesting outcome to 80%. t n e m e r i t e R s t fi e n e b l a u n n A s u n o b e c n a m r o f r e P s e r a h s • Awards granted in 2017 at 500% (group chief executive) and 450% (chief financial officer) of salary will vest in proportion to success against the measures of our 2017-19 scorecard. • Awards granted in 2019 will be granted at 500% (group chief executive) and 450% (chief financial officer) of salary. • For awards granted in 2019, strategic priorities will be weighted at 30% (previously 20%) with return on average capital employed reducing to 20%. • In 2019 we will engage with stakeholders to review and revise, as appropriate, our post employment shareholding policy for 2020 onwards. • Executive directors are required • To provide alignment between • Both executive directors t n e m e r i u q e r to maintain a shareholding equivalent to at least five times their salary. • Additionally, they are expected to maintain shareholdings of at least two and a half times salary for two years post employment. the interests of executive directors and our shareholders. materially exceed the share ownership requirements. • The executive directors maintain their commitment to retain shareholdings of at least two and a half times salary for two years post employment. i l g n d o h e r a h S 88 Directors’ remuneration report BP Annual Report and Form 20-F 2018 Performance and remuneration outcomes in 2018 As we seek to incentivize year-on-year improvement, the committee set stretching targets for the 2018 annual bonus scorecard. Therefore, despite the strong business results for the year, we assessed 2018 performance as below plan, at 81% of target (40.5% of maximum). Following our discussions with SEEAC and MBAC, we found no reason to adjust this formulaic scorecard outcome. Half of the bonus for the executive directors will be delivered as shares and held for three years. 2018 was the final year of the 2016-18 performance share award, the last grant under our 2014 policy, with financial and strategic measures as shown in the table on page 93. BP again ranked first place on relative TSR, delivered robust operating cash flow, and exceeded maximum expectations for major project delivery. These strong results across the range of measures led to a formulaic vesting outcome of 90.5% of maximum. The foregoing results, including TSR, cash flow, and project execution, were delivered alongside an almost 50% return to shareholders over the same three-year period. Thus, there is directional alignment between executives and shareholders. However, the formula from which the outcome was calculated originated in the 2014 plan which we substantially revised in 2017. The committee recognized that merely applying a dated formula might not best serve the interests of the stakeholders. Therefore, despite the clear value delivered to shareholders and the relatively muted annual bonus outcome, we concluded we should apply downward discretion on the executive directors’ long term award outcomes. We will vest the 2016-18 performance shares at 80% rather than at the 90.5% formulaic scorecard outcome. In exercising our judgement we have opted to apply the more challenging scales of our 2017 policy in measuring performance outcomes relating to operating cash flow, major project delivery and safety and operational risk. This adjustment brings the 2016 vintage EDIP outcome into harmony with the policy that was approved by shareholders in 2017. This adjustment reduced 2018 incentive pay by $1.45 million for Bob and £0.54 million for Brian. In addition, the committee has again acted on Bob’s request to re-base his 2016-18 award from its original 550% grant level to the 500% of salary grant level established in the 2017 policy. This adjustment reduces Bob’s vesting outcome by a further $1.10 million, thus reducing his incentive pay by $2.70 million overall. The single figures of total remuneration for Bob and Brian are $14.67 million and £7.98 million respectively, as reported on page 95. This represents a 3% decrease for Bob, reflecting significant reductions in both his annual bonus and the investment return on his retirement savings, partly offset by an increase attributable to share price growth. For Brian, this represents a 12% increase, largely due to vesting of deferred awards from his 2015 bonus, and the increase attributable to share price growth. In our committee deliberations, we considered these outcomes and believe they are appropriate given the operational and financial performance of BP this year and the tremendous recovery that BP has made over the past three years. Looking ahead to 2019 We recently announced our support for a shareholder resolution at the 2019 annual general meeting that would broaden our corporate reporting to describe how our strategy is consistent with the goals of the Paris Agreement. We welcome this resolution as an opportunity to provide further detail on our strategy and on our attractiveness as an investment proposition in the energy transition, and for continued investor engagement. We believe that all constituencies will be well served by our increasing the target financial rewards relating to how we navigate the low-carbon transition. To this end, we have introduced a greenhouse gas emissions reduction measure for our 2019 bonus scorecard. This means that 10% of the outcome will now reflect our progress in emissions reduction (consequently reducing slightly the relative weighting of other customary measures in our bonus plan). The 2019-21 performance share plan scorecard will continue to focus on relative total shareholder return, absolute returns on average capital employed over the three years, and a focused suite of strategic progress measures. To better reflect the importance of strategic progress, which includes BP’s role in the energy transition, we are increasing the weighting of this measure from 20% to 30%, while reducing the returns measure from 30% to 20%. Following our review of their total remuneration, we have decided to keep Bob’s salary unchanged, and propose to increase Brian’s salary by 2% from the date of the AGM. We have also agreed to accelerate the reductions to the cash supplement Brian receives in lieu of further defined benefit pension service accrual, which will now start from 1 June 2019. More broadly, our committee activity in 2019 has included a review of the committee charter, approving remuneration decisions in respect of the executive team, deepening our understanding of wider workforce remuneration and adopting other measures as appropriate under the revised UK Corporate Governance Code, including an examination of the implications of pay and benefits differences across the workforce. We will be reviewing BP’s strategic progress in the context of share programmes approved under the 2017 policy, in particular progress related to the challenges of a lower carbon world. These evaluations will take time and thoughtful discussion and will lead in to the important business of engaging with our major shareholders and representative bodies ahead of our new policy approval in 2020. In that regard, we will be consulting widely on the ways in which we reflect the strategic imperatives of the company within a competitive global remuneration structure. Paula Rosput Reynolds Chair of the remuneration committee 29 March 2019 In this Directors’ remuneration report RC profit (loss), underlying RC profit, return on average capital employed, operating cash flow excluding Gulf of Mexico oil spill payments are non-GAAP measures. These measures and upstream plant reliability, refining availability, major projects and underlying production and reserves replacement ratio are defined in the Glossary on page 315. 89 Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018Business performance A year of exceptional operational performance, with record plant reliability in the Upstream and refining throughput in the Downstream. Improvement across virtually all safety measures, growth in our retail business and delivery of six major projects. Profits have more than doubled, with an 11.2% return on capital, and strong foundations for continuing returns over the near and long term. Key strategic highlights • $12.7 billion underlying replacement cost profit. • Transformation of our US onshore business. • Six new major projects delivered. 1st Among peers for total shareholder return for 2016-18. $26.1bn Operating cash flow excluding Gulf of Mexico oil spill payments. $8.1bn Dividends paid, including scrip. Performance outcomes Robust results for the year fell short of our stretching targets, particularly on cash flow. On a three-year basis, 2018 concluded a remarkable period of delivery and preparation for the future. Annual bonus 40.5% Formulaic outcome (% of maximum) Performance shares 0% Committee judgement, no adjustment 40.5% Final outcome (% of maximum) 90.5% Formulaic outcome (% of maximum) -10.5% Committee judgement to reduce vesting 80% Expected outcome after committee discretiona (% of maximum) Performance measures (% weighting) Nil Maximum Performance measures (% weighting) Nil Maximum Safety Tier 1 process safety events (10%) Recordable injury frequency (10%) Reliability Downstream refining availability (15%) BP-operated upstream plant reliability (15%) Financial Operating cash flow (excluding Gulf of Mexico oil spill payments) (20%) Underlying replacement cost profit (20%) Upstream unit production costs (10%) KPI KPI KPI KPI KPI KPI KPI Financial Relative TSR (33.3%) Cumulative operating cash flow (33.3%) Strategic imperatives Reserves replacement ratioa (11.1%) Major project delivery (11.1%) Safety and operational risk – Tier 1 process safety events – Recordable injury frequency (11.1%) KPI KPI KPI KPI KPI KPI a The final outcome for part of this award is based on BP’s relative RRR ranking. This is forecast at second place but cannot be confirmed until after publication of our peers’ reports. This final outcome will be reported in our 2019 report. KPI This symbol denotes remuneration measures that directly relate to the key performance indicators of our investor proposition – see page 16. Remuneration outcomes Reduced annual bonus and pension, partly offset by increases in performance share vesting, lead to a reduction for Bob. The increase for Brian reflects increases in the values of performance and deferred share vesting. Bob Dudley, group chief executive Total remuneration Brian Gilvary, chief financial officer Total remuneration 2018 2017 2016 2015 2014 $14.7m $15.1m $11.9m $19.4m $16.4m 2018 2017 2016 2015 2014 £8.0m £7.1m £4.2m £5.1m £3.6m Salary and benefits Retirement benefits Annual bonus Performance shares Discontinued plans (see page 96 for descriptions) Share ownership This is a key means by which the interests of executive directors are aligned with those of shareholders. Both directors have holdings in BP which significantly exceeded our shareholding policy requirement of five times salary. Bob Dudley, group chief executive Brian Gilvary, chief financial officer Policy requirements (5x) Actual 90 14.66 times salary, 3,718,074 sharesa, as at 15 March 2019 15.80 times salary, 2,248,905 shares, as at 15 March 2019 aHeld as ADSs Directors’ remuneration report 2018 performance and pay outcomes2018BP Annual Report and Form 20-F 2018 For 2018 the committee established a bonus scorecard of seven measures across three areas of focus: safety and operational risk, reliable operations and financial performance. These measures align with our strategy and, in particular, reflect the annual plan. Six of the seven measures are identical to our 2017 scorecard. The seventh measure, ‘BP-operated upstream plant reliability’, replaces ‘Upstream operating efficiency’ from 2017, bringing unplanned downtime into account which provides a closer comparison with the equivalent measure for the Downstream. To avoid windfall outcomes in our financial measures, and drive genuine year-on-year improvement, we adjust our financial targets to reflect any pricing impacts, i.e. the stronger oil price environment of 2018 led to a proportional increase in our profit and cash flow targets. This is the fourth occasion in the last seven years in which we have adjusted our performance measurement to strip out positive price environments and better reflect financial improvement in underlying terms. Unadjusted, the scores would all have been significantly higher, leading to remuneration outcomes greater than we would have intended. In order to build on the strong results of 2017, the committee set notably stretching targets for each of these measures. For instance, our 2018 threshold outcomes for safety performance were set at the level of our 2017 outcomes, meaning we had to exceed 2017 results to achieve even a minimum contribution to the 2018 bonus. Consequently, and despite another strong year of results and delivery for shareholders, our bonus outcome for 2018 is 81% of target, or 40.5% of maximum, compared with 143% of target, or 71.5% of maximum, in 2017. Annual bonus Scorecard 2018 annual bonus REM Measures used for the 2017 remuneration policy. Safety 0.21 Reliable operations 0.21 Financial performance 0.40 KPI See key performance indicators on page 16. Formulaic score 0.81a out of 2.0 Measures Weighting Threshold (0) Target (1) Maximum (2) Outcome Safety (20% weight) Tier 1 process safety events (defined by API) KPI Recordable injury frequency KPI Safety outcome Reliable operations (30% weight) Downstream refining availability (Solomon Associates’ operational availability) KPI BP-operated upstream plant reliability KPI Reliable operations outcome 15% 15% Financial performance (50% weight) Operating cash flow (excluding Gulf of Mexico oil spill payments) KPI Underlying replacement cost profit KPI Upstream unit production costs KPI Financial performance outcome Formulaic score 20% 20% 10% 10% 10% 19 events 0 16 events 0.1 12 events 0.2 16 events 0.10 0.219/200k hrs 0 0.200/200k hrs 0.1 0.164/200k hrs 0.2 0.198/200k hrs 0.11 94.8% 0 93.3% 0 $26.4bn 0 $11.4bn 0 $7.41/bbl 0 95.3% 0.15 95.3% 0.15 95.8% 0.3 97.3% 0.3 $28.9bn 0.2 $31.4bn 0.4 $12.2bn 0.2 $7.01/bbl 0.1 $13.0bn 0.4 $6.61/bbl 0.2 0.21 94.9% 0.03 95.7% 0.18 0.21 $26.1bn 0 0.00 $12.7bn 0.33 $7.15/bbl 0.07 0.40 Formulaic scorecard outcome 0.81a out of 2.0 SEEAC discretion MBAC discretion No adjustment No adjustment Final scorecard outcome 0.81a out of 2.0 a Due to rounding, the total does not agree exactly with the sum of its component parts. 0.81a out of 2.0 Outcome 40.5% of maximum bonus 91 Corporate governanceDirectors’ remuneration report 2018 annual bonus outcomeBP Annual Report and Form 20-F 2018 Shareholders will note that the most significant divergence from our 2018 targets is in operating cash flow. Even though the 2018 outcome of $26.1 billion is 8% higher than 2017, it fell marginally short of the threshold level of $26.4 billion on an adjusted basis. This meant a score of zero on an element that contributes 20% of the overall bonus target. We feel this is a reflection of the rigor in our policy and target-setting process, delivering a nil outcome even in a year which saw underlying profit more than double, and returns almost double. As in previous years, in order to confirm the final bonus score we have discussed the formulaic score with the chairs of the safety, ethics and environment assurance committee (SEEAC) and the main board audit committee (MBAC). This year, neither of these committees raised issues for which we felt any need to adjust. On this basis, and in view of the demanding target levels we had set for 2018 performance, we believe that the formulaic score, and the annual bonuses that result, fairly reflect and reward 2018 performance for the executive directors and senior leadership of BP. Accordingly we have made no discretionary adjustments to the formulaic scorecard outcome, which applies to the executive directors and BP’s senior leadership (approximately 4,400 employees). Notwithstanding this outcome, we discussed and agreed Bob’s decision to adjust the group performance element of annual bonus for the wider workforce (employees below senior leadership level) and consequently these 32,600 employees received 2018 annual bonus based on an adjusted group performance score of 100%, rather than 81%, of target. The annual bonus outcome is unrelated to the BP share price, and therefore no part of the bonus is attributable to share price appreciation. As shown below, half of the bonus is paid in cash after year end, and half is deferred into shares that will vest in three years, according to 2017 policy terms. The full value of the 2018 bonus, including the deferred shares, is included in the 2018 single figure table. This differs from reporting in respect of the 2014 policy, under which deferred shares are included in the single figure for the year in which they vest. Name Bob Dudley Brian Gilvary Adjusted outcome $1,689,458 £706,219a Paid in cash $844,729 £353,109 Deferred into BP shares $844,729 £353,109 a Due to rounding, the total does not agree exactly with the sum of its component parts. Vesting levels for the 2016-18 performance share awards we granted in 2016 are determined under the terms of the 2014 policy, in line with the performance measures and outcomes shown on the scorecard on page 93. Assessed against these scorecard measures, the group’s performance for the three years from 2016 to 2018 is strong. Notably, we placed first on relative total shareholder return (with 49.3%) which measures us against our super-major peers, Chevron, ExxonMobil, Shell and Total. We also placed first in the 2015-17 performance cycle. Total shareholder return represents the change in value of a shareholding over a three-year period, assuming that dividends are re-invested to purchase additional shares. ratio over the period, which yields vesting at 80% of maximum for this element. We will confirm our final outcome for this measure once competitor data is published in full later in the year. As before, we have assessed performance against the safety and operational risk measure by looking back at tier 1 process safety incidents and recordable injury frequency over the three-year period. This is a detailed assessment looking at year-on-year performance for which we sought input from the SEEAC. Based on continuing reductions in tier 1 events and in recordable injury frequency, and the SEEAC overview, we assessed a score of 88% of maximum for this element of the performance shares scorecard. BP’s standard practice is to calculate this change in value based on the average US market prices over the fourth quarter immediately before, and at the end of, the three-year performance cycle. Using a three-month period average helps to counter the impact of share price volatility. The choice of basis period for calculating share price growth can be a material factor in the ranking result. This generally explains why our peers who use relative TSR in their remuneration plans can arrive at a different result. For example, in the three year scorecard period just ended, BP and Shell showed different relative TSR rankings because unlike BP’s average of the calendar quarter approach, Shell’s standard basis is to use a 90-day averaging period around the start and end of the performance period. We have again made strong progress in major project delivery, exceeding the top of the measurement scale (13) with 19 major projects delivered over the three-year period, allowing maximum vesting for this element. Our $68 billion cumulative operating cash flow excluding the Gulf of Mexico oil spill payments for the period exceeds the threshold performance level of $61.2 billion, following adjustments for oil price in line with the 2014 policy. For the purposes of this report, we have forecast a second place outcome for our relative reserves replacement While the scorecard provides a balanced view of longer-term results, as a committee we wish to take a broader view of performance in order to ensure reward outcomes are proportional and appropriate. Our first concern is to ensure outcomes align with shareholders’ own experience of both returns, and of the company’s positioning to generate value into the future. In this regard we believe the scorecard has worked well. Clearly there are also broader societal views to consider, together with the general experience of the wider workforce as a key stakeholder group. These broader considerations create a compelling case for restraint on quantum, even as they emphasize the need to align to performance. Therefore while we believe that 2016-18 performance has been exemplary, and that the business is both operationally and strategically well positioned for the future, the committee has nonetheless decided to reduce vesting of the performance share award from the formulaic 90.5% to a discretionary 80% of maximum. In applying this judgement and making this reduction the committee decided to apply the more challenging measurement scales of our 2017 policy. The committee studied the impact of share price appreciation on pay outcomes and is satisfied that the gains arising are an appropriate and necessary design feature of a long-term incentive. We believe there should be no routine adjustment, either for gains that in part reflect low grant prices, or for shortfalls that reflect the opposite. 92 Directors’ remuneration report 2016-18 performance share plan outcomeBP Annual Report and Form 20-F 2018In addition, and in line with treatment last year, the committee has agreed to Bob’s request to re-base his original grant from 550% of salary to 500% of salary, recognizing the change from the 2014 policy to the 2017 policy. The impact these decisions have on pay outcomes for Bob and Brian are detailed below. Shares awarded Shares vesting including dividends 1,809,582b 1,597,374 765,998 786,559 Value of vested shares $11,043,179 £4,082,769 Reduction in value due to discretion and re-basing $2,698,677 £535,863 Name Bob Dudleya Brian Gilvary The value of vested shares reflects the share price appreciation all shareholders experienced over the three-year period. For this 2016-18 award cycle, the original grant was calculated based on ordinary share and American depositary share (ADS) prices of £3.72 and $33.81 respectively, while the 2018 fourth-quarter average prices are £5.33 and $41.48. Consequently, share price appreciation accounts for $2.04 million (18.5%) of the value of Bob’s vested shares, and for £1.23 million (30.2%) of the value of Brian’s vested shares. The committee did not regard this as a direct reason to exercise discretion, although overall pay outcomes have been a part of our consideration of downward discretion. a Bob Dudley’s award is granted in respect of American depositary shares (ADSs). The numbers in this table reflect calculated equivalents in ordinary shares. One ADS equates to six ordinary shares. b This original award was based on 550% of salary, according to the terms of the 2014 policy. Performance shares Scorecard 2016-18 performance shares REM Measures used for the 2014 remuneration policy. KPI See key performance indicators on page 16. Financial 60.7% Measures Financial Strategic imperatives 29.8% Formulaic vesting 90.5% Weightinga Threshold performance Maximum performance Outcome Relative total shareholder return KPI 33.3% Third First Cumulative operating cash flow KPI 33.3% $61.2bn $73.2bn Strategic imperatives Relative reserves replacement ratio KPI 11.1% Major project delivery KPI 11.1% Third 9 First 13 11.1% Assessment of improvement over the three years First 33.3% $67.8bn 27.3% 60.7%b Secondc 8.9% 19 11.1% 5.0% 4.8% 29.8% 90.5% Committee review of stakeholder context and experience over three-year period of plan 80% final vesting after committee discretion Safety and operational risk: – Process safety tier 1 events KPI – Recordable injury frequency KPI Total formulaic vesting Formulaic vesting 90.5% a Due to rounding, the sum of the weightings does not agree with the actual total, which is 100%. b Due to rounding, the total does not agree exactly with the sum of its component parts. c Forecast position, to be confirmed after external data becomes available later in 2019. 93 Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018 Alignment with strategy The strategy we set in 2017 commits us to a balance of short-term goals and long-term ambitions, encompassing both conventional and emerging sources of energy. To help the board and executive management assess delivery against this strategy, we track progress against a number of key performance indicators (KPIs) – see page 16. This strategy and these KPIs represent the foundation of our investor proposition. Importantly the majority of our KPIs translate directly into the measures we use to assess our annual bonus and performance share awards. This helps us align the focus of our board and executive management with the interests of our shareholders. To maintain this alignment over time, we will adjust our bonus and performance share measures as and when BP’s strategy evolves or finds new areas of focus. The annual bonus rewards activities that assure our success in the near term, with measures focused on safety, reliable operations, financial performance and, from 2019, a new emissions reduction target. Ensuring our near-term health is a critical building block for the longer term, providing the funds for us to invest, innovate, pursue new opportunities and enhance our productivity. For instance, the reliable operations measure in our annual plan has a strong and direct bearing on the financial measures for our three-year performance share outcomes. Our new sustainable emissions reduction measure, with a 10% weighting for 2019, connects bonus outcomes directly with the progress we make under the reduce element of our ‘reduce, improve, create’ (RIC) framework for a low carbon transition. Our longer-term view is explicitly covered in the strategic progress element for our performance shares, alongside measures that focus on shareholder returns and return on average capital employed (ROACE) over each three-year cycle. These are the measures we established two years ago with our 2017 policy, and we will see the first cycle of results under that policy when we report the 2017-19 performance shares outcome in next year’s report. Looking ahead, the committee has decided to increase the weighting of the strategic progress measure from 20% to 30% to better reflect its importance. This will apply for the performance shares we grant in 2019 as part of the 2019-21 cycle. As a result, we will reduce the weighting on ROACE from 30% to 20%. To ensure we take a rounded view in our performance assessment, the performance share plan also features an underpin to bring absolute TSR, safety and environmental factors into account. This underpin allows the committee to embrace the energy transition in a way that enhances our investor proposition and allows us to be competitive at a time when prices, policy, technology and customer preferences are volatile and evolving, while managing the alignment between remuneration outcomes and our strategic progress. Reducing our emissions in our operations Improving our products Creating low carbon businesses See our low carbon ambitions on page 46. BP set out an update of its strategy in 2017, which was reinforced in the results announcements in February 2018 and 2019. The foundations for strong performance are safe and reliable operations, a balanced portfolio, and a focus on returns. Safer Fit for future Safe, reliable and efficient execution A distinctive portfolio fit for a changing world Focused on returns Value based, disciplined investment and cost focus Growing sustainable free cash flow and distributions to shareholders over the long term How we align our strategy and remuneration measures Annual bonus Safety Environment Reliable operations Financial performance Performance shares Total shareholder return Return on average capital employed Strategic priorities Underpin: absolute TSR and safety/ environmental factors 94 Directors’ remuneration report BP Annual Report and Form 20-F 2018Executive directors’ pay for 2018 Single figure table – executive directors (audited) Remuneration is reported in the currency in which the individual is paid Salary and benefits Salary Benefits Retirement benefits Pension and retirement savings – value increasea Cash in lieu of future accrual Annual bonus Cash bonus Shares – deferred for three years Bob Dudley (thousand) 2018 2017 $1,854 $1,854 $79 $70 $0 – $845 $845 $746 – $1,491 $1,491 Brian Gilvary (thousand) 2018 £769 £67 £0 £269 £353 £353 2017 £752 £38 £186 £263 £611 £611 Performance shares Performance shares $11,043b $9,455c £4,083b £3,595c Discontinued plans Deferred share awards from prior-year bonuses –d –d £2,083e £1,060e Total remunerationf Value attributable to share price appreciationg $14,666 $2,042 $15,108 $1,349 £7,977 £1,876 £7,115 £936 a For Bob Dudley this represents the aggregate value of the company match and investment gains on the accumulating unfunded BP Excess Compensation (Savings) Plan (ECSP) account under Bob’s US retirement savings arrangements. In 2018 Bob incurred investment losses of $193,910 in this account, hence this aggregate value is negative and reported as zero per regulations. Full details are set out on page 96. For Brian Gilvary this represents the annual increase in accrued pension, net of inflation, multiplied by 20. In 2018 Brian’s salary increased by less than inflation, hence the net increase is reported as zero per regulations. Full details are set out on page 96. b Represents the assumed vesting of shares in 2019 following the end of the relevant performance period, based on a preliminary assessment of performance achieved under the rules of the plan and includes accrued 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 2018 which was £5.33 for ordinary shares and $41.48 for ADSs. The final vesting will be confirmed by the committee in the second quarter of 2019 and provided in the 2019 directors’ remuneration report. c In accordance with UK regulations, in the 2017 single figure table, the performance outcome values were based on fourth-quarter average prices of £5.01 for ordinary shares and $39.85 for ADSs. In May 2018, after the external data became available, the committee reviewed the relative reserves replacement ratio position, and this resulted in no adjustment to the final vesting of 70%. On 22 May 2018, 198,306 ADSs for Bob Dudley and 603,831 ordinary shares for Brian Gilvary vested at prices of $47.09 and £5.88 respectively. On 31 July 2019 an additional 2,599 ADS and 7,795 ordinary shares vested, representing accrued dividends at prices of $45.09 and £5.73 for Bob and Brian respectively. The 2017 reported values for the total vesting have therefore increased by $1,168 thousand for Bob and by £614 thousand for Brian. d Bob Dudley has voluntarily agreed to defer performance assessment and vesting of the awards related to his 2015 annual bonus until at least one year after retirement, therefore the performance period is expected to exceed the minimum term of three years. As stated in the 2017 directors’ remuneration report, Bob voluntarily deferred performance assessment and vesting of the 2014 deferred and matching awards until at least one year after retirement – see the Deferred shares table on page 101 for further details on these awards. e The amounts reported for 2018 relate to the 2015 annual bonus deferred over three years, which vested on 19 February 2019 at the market price of £5.38 for ordinary shares and include accrued dividends on shares vested. Brian Gilvary has voluntarily agreed to defer performance assessment and vesting of the matching awards related to his 2015 annual bonus for a further two years – see the Deferred shares table on page 101 for further details on these awards. The amounts reported for 2017 relate to the 2014 annual bonus and have been adjusted from the number provided in the 2017 directors’ remuneration report to include the accrual and vesting of accrued dividends. f Due to rounding, the total does not agree exactly with the sum of its component parts. g The values shown for performance shares and deferred share awards include the share price appreciation experienced over the three-year vesting periods. This additional line shows the value of those awards that is directly attributable to share price appreciation, being the number of shares vesting, including accrued dividends, multiplied by the increase in share price from grant date to vesting date. 95 Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018Overview of single figure outcomes The single figures of total remuneration for Bob Dudley and Brian Gilvary are $14.67 million and £7.98 million respectively. This is a 3% decrease for Bob, and a 12% increase for Brian. In both cases 2018 remuneration includes material value from share price appreciation over the 2016 to 2018 period. Both individuals pay a majority of their taxes in the UK. After these tax and social security liabilities on this BP income, the net values of 2018 total remuneration are approximately $7.77 million for Bob, and approximately £4.23 million for Brian. Salary and benefits Bob Dudley’s salary remained at $1,854,000 throughout 2018. Brian Gilvary’s salary was increased by 2% to £775,000 with effect from 21 May 2018. Both executive directors received car-related benefits, assistance with tax return preparation, security assistance, insurance and medical benefits. In 2018 BP reimbursed Brian for holiday curtailment costs incurred due to BP commitments. Part of this reimbursement is considered non-business related, hence is subject to tax and included as a benefit in the single figure table. 2018 annual bonus and 2016-18 performance shares Please refer to pages 91-93 for details of the performance measures, targets, and outcomes, and the related reward outcomes for annual bonus and performance shares. Discontinued plans: deferral of 2015 bonus – deferred and matching awards of shares In accordance with 2014 policy, Bob Dudley and Brian Gilvary deferred two thirds of their 2015 annual bonus. As a result, they each received an equivalent value deferred award of BP shares, together with a matching award of BP shares. Both the deferred and matching awards were subject to a three-year performance period which ended on 31 December 2018. Conclusions of the safety and sustainability assessment Bob has requested that the committee delay the performance assessment and hence the vesting of his 2015 deferred and matching awards. This reflects his commitment to the long-term success of BP and adds to his alignment with shareholders’ interests. These awards will now vest, subject to an assessment against the original safety and environmental sustainability conditions, after his retirement. Similarly, Brian has requested a two-year extension to the performance assessment and vesting date of his 2015 matching award. For the 2015 deferred award for Brian, the committee considered operational and financial performance and reviewed safety and environmental sustainability performance over the 2016-18 period, seeking input from the SEEAC on safety and sustainability measures. The committee concluded that safety performance continues to show improvement, with safety embedded in the culture of the organization and supporting strong operational and financial performance. The committee concluded that the deferred award should vest in full. 2015 bonus – deferred and matching awards Name Bob Dudleya Deferred award Matching award Brian Gilvaryb Deferred award Matching award Shares granted Vesting agreed Total shares vesting, including dividends Total value at vesting 551,784 551,784 –a –a – – – – 318,042 318,042 100% –b 387,160 £2,082,921c – – a Vesting of deferred and matching awards deferred until at least one year after retirement, subject to conditions. b Vesting of matching award deferred for two years, subject to conditions. c Based on a vesting share price of £5.38. No systemic issues identified No major incidents Safety culture and values embedded within the global organization Strong safety performance supports efficiency and financial results across the group Retirement benefits Bob Dudley is a member of the US pension and retirement savings plans described on page 108. His normal retirement age is 60. In 2018 Bob’s accrued defined benefit pension did not increase. In accordance with the requirements of the UK regulations, the amount included in the single figure table on page 95 is therefore zero. In 2018 Bob made contributions to the BP Employee Savings Plan (ESP) totalling $27,000 and BP made matching contributions to the ESP, and notional contributions to the BP Excess Compensation (Savings) Plan (ECSP), totalling $129,780. However, investment losses of $193,910 in his unfunded ECSP account (aggregating the unfunded arrangements relating to his overall service with BP and TNK-BP), exceeded the sum of these contributions, hence the amount included in the single figure table is zero. Brian Gilvary is a member of the UK pension arrangement described on page 108 in common with more than 3,800 UK employees employed prior to 2010 (or before 2014 in the North Sea). His normal retirement age is 60, although benefits accrued before 1 December 2006 may be paid from age 55 with BP’s consent. Brian’s 2018 salary increase was below inflation, and his accrued defined benefit pension increase was therefore likewise below inflation. In accordance with the requirements of the UK regulations, the amount included in the single figure table is therefore zero. Brian has exceeded the lifetime allowance under UK pension legislation and now receives a cash allowance of 35% of base salary in lieu of further service accrual. This amount has been separately identified in the single figure table on page 95. This cash allowance is a feature of the UK pension arrangement, and will transition down to 15% of salary by 1 June 2023 – see page 105 for more detail. The committee continues to review the value of pension benefits for individual directors and its alignment to the broader workforce. History of group chief executive remuneration Group chief executive Tony Hayward Tony Hayward Bob Dudley Bob Dudley Bob Dudley Bob Dudley Bob Dudley Bob Dudley Bob Dudley Bob Dudley Bob Dudley Total remuneration thousanda £6,753 £3,890 $8,057 $8,439 $9,609 $15,086 $16,390 $19,376 $11,904 $15,108 $14,666 Annual bonus % of maximum 88.9b 0 0 66.7 64.9 88.0 73.3 100.0 61.0 71.5 40.5 Performance shares vesting % of maximum 17.5 0 0 16.7 0 45.5 63.8 74.3 40.0 70.0 80.0 Year 2009 2010c 2011 2012 2013 2014 2015 2016 2017 2018 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 2018 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. 96 Directors’ remuneration report BP Annual Report and Form 20-F 2018Wider workforce in 2018 Workforce experience Delivery of our strategy, both near and long term, depends upon BP’s success in attracting and engaging a highly talented workforce, and on equipping our people with the skills for the future. While the board is currently considering ways to engage more deeply with the workforce, and about the workplace in its broadest sense, the remuneration committee continues to receive and review information on pay outcomes and processes for our wider workforce. We are building insight into the remuneration models used in different BP entities and stay informed on the pay structures and typical salary budgets for the core areas of the group’s business. For example, we have looked at data from the organization’s gender pay reporting, at progression of reward across the hierarchy of job levels, and reviewed the reward structures and processes in BP’s trading business. Overall we observe a well-balanced and structured approach to reward (summarized in the table below), and to the ‘non-financial’ reward elements that contribute to an engaged and productive environment. This context has informed our decision making on executive director pay and our views on incentive outcomes across the group. In our consideration of the annual bonus scorecard for 2018, for instance, while we felt the formulaic result delivered appropriate outcomes for BP’s senior leadership, we agreed with Bob’s decision to apply a more generous outcome to the wider workforce on the basis that, individually, they have limited influence over financial outcomes such as cash flow. Looking beyond pay, much of the workforce experience at BP is centred on a disciplined approach to performance management, for which employees set annual priorities related to both safety and value creation, balanced with behavioural objectives that give focus to the importance of good conduct. This deeply embedded programme has served to develop the management skills of team leaders and drives quality dialogue between employees and their managers. We agree with the executive team’s view that the time invested in managing performance both aligns individual effort to corporate goals and allows employees to understand the value of their own contribution. The benefit of this approach is largely qualitative, through direction and feedback, but the individual contribution is also measured and then rewarded as part of the annual bonus. For a more immediate impact, BP is also encouraging more ‘in the moment’ feedback through our new global recognition programme ‘energize!’, introduced in 2018. Energize! has been well received in all business areas and locations, with 77% of employees recognized at least once, at a frequency of around 1,500 recognition moments every day by year end. With strong emphasis on diversity and inclusion to create teams that reflect their communities, and with the enduring foundation of BP’s values and behaviours to build respect, we believe BP employees work in a supportive, meritocratic and progressive environment. This positive environment is reflected in being the highest-ranked UK recruiter in the oil and gas sector in the Times newspaper’s Top 100 Graduate Employer rankings 2018. Summary of remuneration structure for employees below the board Element Policy features for the wider workforce Comparison with executive director remuneration y r a l a S d n a s n o i s n e P s t fi e n e b s u n o b l a u n n A e c n a m r o f r e P s e r a h s Our salary is the basis for a competitive total reward package for all employees, and we conduct an annual salary review for all non-unionized employees. As we determine salaries in this review, we take account of comparable pay rates at other relevant employers, the skills, knowledge and experience of each individual, relativity to peers within BP, individual performance, and the overall budget we set for each country. In setting the budget each year, we assess how employee pay is currently positioned relative to market rates, forecasts of any further market increases, and business context related to such things as growth plans, workforce turnover and affordability. The salaries of our executive directors and executive team form the basis of their total remuneration, and we review these salaries annually. The primary purpose of the review is to stay aligned with relevant market comparators, although we ensure any increases are kept within the budgets set for our wider workforce salary review. We offer market-aligned benefits packages reflecting normal practice in each country in which we operate. Where appropriate, and subject to scale, we offer significant elements of personal benefit choice to our employees. Other than the addition of security-related benefits, our executive director benefit packages are broadly aligned with other employees who joined BP in the same country at the same time. Approximately half of our global workforce participate in an annual cash bonus plan that multiplies a target bonus amount by a performance factor in the range 0 to 2. The performance factor is an average of performance outcomes measured at a group, business area and individual level. This structure places equal emphasis on the importance of an employee’s personal contribution, the success of their broad team, and the results achieved by BP. We operate different bonus plans for those distinct parts of our business where remuneration models in the market are markedly different, such as our trading and marketing businesses. Annual bonus for executive directors is directly related to the same group performance measures and outcomes as the wider workforce, but without the business area and individual performance element. We operate a performance share plan with three-year vesting for employees from our professional entry level and above. Operation varies based on seniority in three broad tiers: group leaders (approximately 400); senior leaders (approximately 4,000); and all other professional employees (approximately 35,000 potential participants, of whom 20% will participate). Vesting is subject to group performance outcomes for the group leader population only. Performance shares for our executive directors are assessed using the same group performance scorecard used for the group leader performance shares, with some adjustment to the weightings. 97 Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018 Group chief executive-to-employee pay ratio In 2016 and 2017 we disclosed the ratio between our group chief executive’s (GCE) total remuneration and the median (P50) remuneration of a comparator group of our UK and US professional workforce (representing 38% of our global professional workforce). We believe this representation offers a valuable data point, highlighting relevant pay differentials within BP. On this basis, our 2018 GCE to median pay ratio is 106:1. GCE pay ratios Year 2017 2018 Method BP voluntary BP voluntary P50 pay ratio on total remuneration 105:1a 106:1 P50 salary $112,100 $114,800 P50 total remuneration $136,865 $138,101 a Re-based from original 92:1 to reflect final value at vesting of 2015-17 performance shares. With effect from year ending 31 December 2019, the UK government will require that we calculate the total remuneration of the three BP UK employees whose remuneration represents the 25th, 50th and 75th percentile of our entire UK workforce. We are then required to disclose the ratio of our group chief executive’s total remuneration against each of those three representative employees. Percentage change comparisons: GCE remuneration versus professional workforce Comparing 2018 to 2017 % change in GCE remuneration Salary Benefits Bonus 0% 8.0% -43.4% % change in comparator group remuneration 4.4% 0% -7.8% The comparator group used here is the same as used in our voluntary pay ratio disclosures since 2017, i.e. our professional and managerial grade staff in the UK and US. This group is employed on readily comparable terms to the group chief executive, and represents approximately one third of our total employee base. Relative importance of spend on pay ($ million) Distributions to shareholders Remuneration paid to all employees Capital investment 16,501 15,140 8,435a 8,210a 10,494 10,204 2018 2017 2018 2017 2018 2017 a Distributions to shareholders comprise dividend payments of $8,080 million ($7,867 million in 2017) and share buybacks at a cost of $355 million ($343 million in 2017). See page 275 for details. 98 Directors’ remuneration report BP Annual Report and Form 20-F 2018The illustration below, from our 2018 UK gender pay gap reporting, highlights the representation issue and how it relates to the gender pay gap for each entity. For instance, our larger gender pay gaps relate to BP Exploration and BP p.l.c. where we have the largest differential between female representation in the top and bottom pay quartiles. By contrast, we reported a negative pay gap in BP Chemicals, where male to female representation is more consistent. Equal pay and UK gender pay gap reporting As well as looking at pay structures, the committee has spent time understanding how effectively current pay policies and processes manage fairness and avoid bias in pay outcomes. We noted the February 2018 UK gender pay gap reporting for the five legal entities covered by the regulations, and the explanations provided in the narrative that accompanied BP’s reporting. Overall the committee feels assured that the anti-discrimination controls written into pay policies, and the quality of processes behind individual pay decision making, are effective in delivering an equal pay environment (like pay for like work) for the wider workforce. While the UK gender pay gap reporting showed pay gaps in favour of men for four out of the five entities, we understand that these gaps result largely from the relative under-representation of women in senior roles, and that the group’s primary focus should therefore be on improving female representation, rather than adjusting pay practices. Therefore we have reviewed the various initiatives taken by management to address these representation concerns and will continue to monitor progress in addressing the underlying issues. Proportion of females and males in each quartile band These charts show how men and women are represented in each pay band. An even distribution across the quartiles would tend to minimize the gender pay gap. BP Chemicals Limited BP Exploration Operating Company Limited Upper 85% 82% 93% Lower 76% BP Chemicals is our petrochemicals business in the UK, principally our operations in Hull. BP Oil UK Limited Upper 69% 68% 63% Lower 44% BP Oil represents our downstream fuels and lubricants businesses. BP p.l.c. Upper 71% 70% 60% Lower 36% 15% 18% 7% 24% 31% 32% 37% 56% 29% 30% 40% 64% Upper 92% 88% 83% Lower 63% BP Exploration covers upstream activities in the UK, principally North Sea operations. BP Express Shopping Limited Upper 63% 62% 48% Lower 42% BP Express Shopping is our largest UK employing business, concerned with retail operations supporting our UK-wide network of forecourts. 8% 12% 17% 37% 37% 38% 52% 58% BP p.l.c. predominantly covers employees in corporate business and functions, including our integrated supply and trading and Air BP businesses. Men Women 99 Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018Stewardship and executive director interests We believe that our executive directors should have a material interest in the company, both during their tenure and after they leave BP. Our shareholding policy therefore requires executive directors to build a personal shareholding of five times their salary within five years of their appointment. They are expected to maintain personal shareholdings of at least two and a half times salary for two years post employment. Directors’ shareholdings (audited) The tables below detail the personal shareholdings of each executive director, and demonstrate that both significantly exceed the policy requirement as at 15 March 2019. These figures include all beneficial and non-beneficial ownership of shares of BP (or calculated equivalents) that have been disclosed to the company and exclude the anticipated vesting of the 2016-18 performance shares. Ordinary shares or Ordinary shares equivalents at or equivalents 31 Dec 2018 at 1 Jan 2018 3,065,520 3,718,284 1,709,243 2,043,899 Changes from 31 Dec 2018 to 15 Mar 2019 Ordinary shares or equivalents total at 15 Mar 2019 -210b 3,718,074 205,006 2,248,905 Director Bob Dudleya Brian Gilvary a Held as ADSs. b This reflects change in the equivalent value of BP ADRs under the BP Employee Savings Plan (‘ESP’), due to the BP ADR price movement. See page 108 for explanation of the ESP. Performance shares (audited) Director Bob Dudley Brian Gilvary Appointment date October 2010 January 2012 Value of current shareholding Multiple of salary achieved (policy requires 5x) $27,185,318 14.66 x salary £12,256,532 15.80 x salary The executive directors have interests in both performance shares and deferred bonus shares under the executive directors’ incentive plan (EDIP). The share interests are shown in aggregate and by plan in the tables below. These figures show the maximum possible vesting levels. The actual number of shares/ADSs that vest will depend on the extent to which performance conditions are satisfied. Unvested ordinary shares or equivalents at 1 Jan 2018 Unvested ordinary shares or equivalents as 31 Dec 2018 Changes from 31 Dec 2018 to 15 Mar 2019 Unvested ordinary shares or equivalents at 15 Mar 2019 Director Bob Dudleya Brian Gilvary 6,569,010b 3,329,274 6,825,606b 3,291,614 1,459,350 400,709 8,284,956 3,692,323 a Held as ADSs. b This shareholding has been re-based to reflect the 500% of salary grant level of the 2017 policy, in place of the original 550% per the 2014 policy. Bob Dudleyb Brian Gilvary Date of award of performance shares Performance period 2015-17 11 Feb 2015 4 Mar 2016 2016-18 2017-19g 19 May 2017 2018-20i 22 May 2018 11 Feb 2015 2015-17 4 Mar 2016 2016-18 2017-19g 19 May 2017 2018-20i 22 May 2018 Share element interests Potential maximum performance sharesa At 1 Jan 2018 1,365,240 1,645,074 1,571,628h – 685,246 786,559 722,093 – Awarded 2018 – – – 1,395,600 – – – 696,705 At 31 Dec 2018 – 1,645,074e 1,571,628 1,395,600 – 786,559 722,093 696,705 Interests vested in 2018 and 2019 Number of ordinary shares vested Vesting date 1,205,430c 22 May 2018d 2019f 1,597,374f – – – – 611,626c 22 May 2018d 2019f 765,998f – – – – Face value of the award, £ – – 7,418,084 8,206,128 – – 3,408,279 4,096,625 a For awards under the 2015-17 and 2016-18 plans, performance conditions are measured one third on TSR relative to Chevron, ExxonMobil, Shell and Total (‘comparator companies’); one third on operating cash flow; and one third on a balanced scorecard of strategic imperatives. 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, each of the strategic imperatives and strategic progress reaching the minimum threshold, has been calculated. For awards under the 2017-19 plan, performance conditions are measured 50% on TSR relative to Chevron, ExxonMobil, Shell and Total over three years; 30% on ROACE based on performance in 2019 and 20% on strategic progress assessed over the performance period. For awards under the 2018-20 plan, performance conditions are measured on the same basis as the 2017-19 plan, except ROACE which will be based on performance in the last two years of the performance period (i.e. 2019 and 2020). Each performance period ends on 31 December of the third year. b Bob Dudley received awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares. c 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 22 May 2018 was £5.88 and for ADSs was $47.09. These totals include the additional accrual of dividends which vested on 31 July 2018. d The 2015-17 award vested on 22 May 2018. Details can be found in the single figure table on page 95. e Bob Dudley has requested that the EDIP performance shares vesting in respect of the performance period 2016-18 is based on the 500% maximum annual award level which applies under the 2017 directors’ remuneration policy, rather than the 550% maximum annual award level which applies under the 2014 directors’ remuneration policy. The number reported here has been re-based to 500%. f For the assumed vestings in the second quarter of 2019 a price of £5.33 per ordinary share and $41.48 per ADS has been used. These are the average prices from the fourth quarter of 2018. g The face value has been calculated using the market price of ordinary shares on 19 May 2017 of £4.72. h In our 2017 report, the 31 December 2017 value for this award was incorrectly stated as 1,428,750. i The face value has been calculated using the market price of ordinary shares on 22 May 2018 of £5.88. 100 Directors’ remuneration report BP Annual Report and Form 20-F 2018 Deferred shares (audited)a Bob Dudleyb Brian Gilvary Bonus year Type 2014c Comp Vol Mat 2015e Comp Vol Mat 2016f Comp Mat 2017g Comp 2014 Comp Vol Mat 2015 Comp Vol Mat 2016f Comp Mat 2017g Comp Performance period 2015-17d 2015-17d 2015-17d 2016-18d 2016-18d 2016-18d 2017-19 2017-19d 2018-20 2015-17 2015-17 2015-17i 2016-18 2016-18 2016-18i 2017-19 2017-19k 2018-20 Date of award of deferred shares 11 Feb 2015 11 Feb 2015 11 Feb 2015 4 Mar 2016 4 Mar 2016 4 Mar 2016 19 May 2017 19 May 2017 22 May 2018 11 Feb 2015 11 Feb 2015 11 Feb 2015 4 Mar 2016 4 Mar 2016 4 Mar 2016i 19 May 2017 19 May 2017 22 May 2018 Share element interests Potential maximum deferred shares At 1 Jan 2018 147,054 147,054 294,108 275,892 275,892 551,784 147,642 147,642 – 88,288 88,288 176,576 159,021 159,021 318,042 73,070 73,070 – Awarded 2018 – – – – – – – – 226,236 – – – – – – – – 127,457 At 31 Dec 2018 147,054 147,054 294,108 275,892 275,892 551,784 147,642 147,642 226,236 – – 176,576 159,021 159,021 318,042 73,070 73,070 127,457 Interests vested in 2018 and 2019 Number of ordinary shares vested – – – – – – – – – Vesting date – – – – – – – – – 111,161h 20 Feb 2018 111,161h 20 Feb 2018 – 193,580j 19 Feb 2019 193,580j 19 Feb 2019 – – – – – – – – – Face value of the award, £ 655,861 655,861 1,311,722 1,015,283 1,015,283 2,030,565 696,870 696,870 1,330,268 – – 787,529 – – 1,170,395 344,890 344,890 749,447 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 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 The face value has been calculated using the market price of ordinary shares on 11 February 2015 of £4.46. d Bob Dudley has voluntarily agreed to defer the performance assessment and vesting of these awards until at least one year after retirement, therefore the performance period is expected to exceed the minimum term of three years. e The face value has been calculated using the market price of ordinary shares on 4 March 2016 of £3.68. f The market price at closing of ordinary shares on 19 May 2017 was £4.72 and for ADSs was $36.94. The sterling value has been used to calculate the face value. g The market price at closing of ordinary shares on 22 May 2018 was £5.88 and for ADSs was $47.09. The sterling value has been used to calculate the face value. h 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 date of 20 February 2018 was £4.75. These totals include the additional accrual of dividends which vested on 22 May 2018 and 31 July 2018. i Brian Gilvary has voluntarily agreed to defer the performance assessment and vesting of these matching awards for a total of five years with a further one-year retention period. The face values have been calculated using the market prices of £4.46 per ordinary share on 11 February 2015 and £3.68 per ordinary share on 4 March 2016. j Represents vesting of shares at the end of the relevant performance period based on performance achieved under rules of the plan. Includes reinvested dividends on the shares vested. The market price of each share used to determine the total value on the vesting date of 19 February 2019 was £5.38. k Brian Gilvary has voluntarily agreed to defer the performance assessment and vesting of these awards until the later of three years post award or one year post employment, therefore the performance period is expected to exceed the minimum term of three years. In common with many of our UK employees, Brian Gilvary holds options under the BP group save as you earn (SAYE) schemes as shown below. These options are not subject to performance conditions. Share interests in share options plans (audited) Brian Gilvary Option type At 1 Jan 2018 BP 2011b 500,000 3,103 SAYE Granted – – Exercised 100,000 – At 31 Dec 2018a 400,000 3,103 Option price £3.72 £2.90 Market price at date of exercise Date from which first exercisable Expiry date £5.27 07 Sep 2014 07 Sep 2021 – 01 Sep 2019 28 Feb 2020 a The closing market price of an ordinary share on 31 December 2018 was £4.96. During 2018 the highest market price was £5.98 and the lowest market price was £4.60. b ‘BP 2011’ means the BP 2011 plan. These options were granted to Brian Gilvary prior to his appointment as a director and are not subject to performance conditions. Neither Bob Dudley or Brian Gilvary have any interest in BP preference shares, debentures or option plans (other than as listed above), and neither have interests in shares or loan stock of any subsidiary company. No directors or other executive team members (see page 63) own more than 1% of the ordinary shares in issue. At 15 March 2019, our directors and other executive team members collectively held interests of 17,436,602 ordinary shares or their calculated equivalents, 5,978,567 restricted share units (with or without conditions) or their calculated equivalents, 11,977,279 performance shares or their calculated equivalents and 4,417,149 options over ordinary shares or their calculated equivalents, under BP group share option schemes. Post employment share ownership interests As we reported last year, to maintain their alignment with shareholders and in keeping with the long-term nature of our business, our executive directors will retain significant interests in BP post employment. These ongoing interests are centred on a) the personal commitment by each executive director to maintain actual holdings equivalent to two and a half times salary for two years post employment, and b) their anticipated interests in share awards under group plans which remain subject to vesting and/or holding periods at the time they leave BP. 101 Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018 Non-executive director outcomes and interests The board’s remuneration policy for the chairman and non-executive directors (NEDs) was approved at the 2017 AGM and implemented during 2017. There has been no variance of the fees or allowances for the chairman and the NEDs since approval in 2017. Chairman The fee structure for the chairman, which has been in place since May 2013, is £785,000 per year. The chairman is not eligible for committee chairmanship and membership fees or intercontinental travel allowance. As chairman throughout 2018, Carl-Henric Svanberg had the use of a fully maintained office for company business, a car and driver, and security advice in London. He received a contribution to an office and secretarial support as appropriate to his needs in Sweden. The table below shows the fees paid for the year ended 31 December 2018. 2018 remuneration (audited) £ thousand Carl-Henric Svanberg Fees Benefitsa Total 2018 785 2017 785 2018 24 2017 35 2018 809 2017 820 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. 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 according to the disclosure guidance and transparency rules in the Financial Conduct Authority handbook (‘the DTRs’) as at the applicable dates. The chairman’s holdings as at 31 December 2018, as a percentage of the shareholding policy, were 1,312%. Ordinary shares or equivalents at 1 Jan 2018 Ordinary shares or equivalents at 31 Dec 2018 Change from 31 Dec 2018 to 15 Mar 2019 Ordinary shares or equivalents total at 15 Mar 2019 2,076,695 2,076,695 – – Chairman Carl-Henric Svanberga a Resigned on 31 December 2018. Helge Lund assumed the role of chairman with effect from 1 January 2019. His share interests are disclosed on page 103. 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. 2018 remuneration (audited) £ thousand Fees Benefitsa Totalb Nils Andersen Paul Andersonc Alan Boeckmann Admiral Frank Bowman Dame Alison Carnwathd Pamela Daleye Ian Davis Professor Dame Ann Dowlingf Helge Lunde Melody Meyerh Brendan Nelson Paula Rosput Reynolds Sir John Sawers 2018 132 69 155 160 74 55 170 158 46 160 150 166 150 2017 115 155 165 155 – – 154 145 – 86 138 146i 145 2018 11 6 10 14 47 42 2 2 122g 26 12 33 1 2017 17 27 11 15 – – 2 5 – 23 14 8 5 2018 144 76 165 174 121 97 172 159 169 186 162 200 151 2017 132 182 176 170 – – 156 150 – 109 152 154i 150 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 Due to rounding, the totals may not agree exactly with the sum of its component parts. c Resigned on 21 May 2018. d Appointed on 21 May 2018. e Appointed on 26 July 2018. f Fee includes £25 thousand for chairing and being a member of the BP technology advisory council. g Benefits include relocation expenses. h Appointed on 17 May 2017. i Amended from £140 thousand (fees) and £148 thousand (total) as originally disclosed in our 2017 report. 102 Directors’ remuneration report BP Annual Report and Form 20-F 2018 Non-executive directors’ interests (audited) 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 Andersen Paul Andersonb Alan Boeckmann Admiral Frank Bowman Dame Alison Carnwathd Pamela Daleye Ian Davis Professor Dame Ann Dowling Helge Lundf Melody Meyer Brendan Nelson Paula Rosput Reynolds Sir John Sawers Ordinary shares or equivalents at 1 Jan 2018 125,000 30,000c 44,772c 24,864c – – 47,500 22,320 – 20,646c 11,040 58,200c 14,198 Ordinary shares or equivalents at 31 Dec 2018 125,000 – 44,772c 24,864c 17,700 17,592c 50,296 22,320 600,000 20,646c 11,040 73,200c 15,030 Changes from 31 Dec 2018 to 15 Mar 2019 – – – – – – – – – – – – – Ordinary shares or equivalents at 15 Mar 2019 125,000 – 44,772c 24,864c 17,700 17,592c 50,296 22,320 600,000 20,646c 11,040 73,200c 15,030 Value of current shareholdinga £681,250 – $327,358 $181,797 £96,465 $128,627 £274,113 £121,644 £3,270,000 $150,957 £60,168 $535,214 £81,914 % of policy achieved 757% – 273% 151% 107% 107% 305% 135% 417% 126% 67% 446% 91% a Based on share and ADS prices at 15 March 2019 of £5.45 and $43.87. b Resigned on 21 May 2018. c Held as ADSs. d Appointed on 21 May 2018. e Appointed on 26 July 2018. f Appointed 26 July 2018. Became chairman with effect from 1 January 2019. Percentage of policy achieved based on annual equivalent fee for role of chairman. Payments for loss of office and payments to past directors (audited) We made no payments for loss of office during or in respect of 2018 to current or former 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 2018, he received £100,000 for this role. Other than this, we made no payment to any past director of BP during 2018 (we have no de minimis threshold for such disclosures). 103 Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018 Other disclosures Historical TSR performance FTSE 100 BP £250 £200 £150 £100 l i 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 l £50V Shareholder engagement Throughout 2018 we continued to discuss remuneration policy and approach with many of our largest shareholders, as well as investor representative bodies. We plan to continue this dialogue in 2019, as we consider updates to our remuneration and minimum shareholdings policies for 2020. The table below shows the votes on the report for the last three years. AGM directors’ remuneration report vote results Year 2018 2017 2016 % vote ‘for’ 96.42% 97.05% 40.70% % vote ‘against’ 3.58% 2.95% 59.30% Votes withheld 42,741,541 63,453,383 464,259,340 The remuneration policy was approved by shareholders at the 2017 AGM on 17 May 2017. The votes on the policy are shown below. 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2017 AGM directors’ remuneration policy vote results Year 2017 % vote ‘for’ 97.28% % vote ‘against’ 2.72% Votes withheld 36,563,886 External appointments The board supports executive directors taking up appointments outside the company to broaden their knowledge and experience. Each executive director is permitted to retain any fee from their external appointments. Such external appointments are subject to agreement by the chairman and reported to the board. Any external appointment must not conflict with a director’s duties and commitments to BP. Details of appointments as non-executive directors of publicly listed companies during 2018 are shown below. Director Bob Dudley Brian Gilvary Appointee company Rosnefta Additional position held at appointee company Director Total fees 0 Air Liquide Non-executive director Euros 70,500 a Bob Dudley holds this appointment as a result of the company’s shareholding in Rosneft. Committee membership Please refer to the committee report on page 83 for details of membership of the remuneration committee during 2018. This graph shows the growth in value of hypothetical £100 investments in BP p.l.c. ordinary shares, and in the FTSE 100 Index (of which BP is a constituent), over 10 years from 31 December 2008 to 31 December 2018. Independence and advice The board considers all committee members to be independent with no personal financial interest, other than as shareholders, in the committee’s decisions. Further detail on the activities of the committee, advice received and shareholder engagement is set out in the remuneration committee report on page 83. During 2018 David Jackson, the then company secretary, and subsequently Hannah Ashdown, both of whom were employed by the company and reported to the chairman of the board, acted as secretary to the remuneration committee. The committee also received advice on various matters relating to the remuneration of executive directors’ and senior management from Helmut Schuster, executive vice president, group human resources, and Ashok Pillai, vice president, group reward. PricewaterhouseCoopers LLP (‘PwC’) continued to provide independent advice to the committee in 2018, following its appointment as independent adviser to the committee in September 2017, following a competitive tender process. PwC is a member of the Remuneration Consulting Group and, as such, operates under the code of conduct in relation to executive remuneration consulting in the UK. The committee is satisfied that the advice received is objective and independent. Freshfields Bruckhaus Deringer LLP provided legal advice on specific compliance matters to the committee. PwC and Freshfields provide other advice in their respective areas to the group. During the year, PwC provided BP with services including subsidiary company secretarial support. Total fees or other charges (based on an hourly rate) for the provision of remuneration advice to the committee in 2018 (save in respect of legal advice) were £179,200 to PwC. 104 Directors’ remuneration report BP Annual Report and Form 20-F 2018 Executive director remuneration policy and implementation for 2019 2019 The table below shows how the remuneration policy approved by shareholders at the 2017 AGM will be implemented in 2019. For the full remuneration policy, please go to bp.com/remuneration. Salary and benefits Reflects role and home country market Salary and benefits reflect the scale and complexity of the role, and competitive practice in the market. • Bob Dudley’s salary will remain at $1,854,000 for 2019. • Benefits will remain unchanged for 2019. These include • With effect from the AGM, Brian Gilvary’s salary will increase by 2% to £790,500. • This compares to an average increase of over 3.5% to our UK salaried staff, effective on our annual salary review date 1 April. car-related benefits, assistance with tax return preparation, security assistance, insurance and medical benefits. Retirement benefits Reflects home country market • Since September 2016, Bob has had no further service accrual under his defined benefit pension arrangements. The 401(k) benefits have been partially capped for future years. His normal retirement age is 60. • Starting from 1 June 2019, we agreed to reduce Brian’s cash supplement by 5% of salary each year to reach 20% of salary with effect from 1 June 2021, with a further 5% reduction, to 15% of salary, with effect from 1 September 2023. Annual bonus Up to 225% of salary Aligned with annual objectives • Brian is a member of the BP UK defined benefits pension plan and he receives a cash supplement in lieu of further service accrual on the same terms as other participants in the plan, currently 35% of salary. • These changes reduce Brian’s cash supplement sooner than the transition for other members of the BP UK defined benefits plan, and Brian will not receive any form of compensation related to the reductions. His normal retirement age is 60, although benefits accrued before 1 December 2006 may be paid from age 55 with BP’s consent. The bonus links variable pay to safety, environmental goals, reliable operations and financial performance for the year. • Maximum bonus requires performance at the top of the measurement scale on every measure – a scorecard outcome of 2.0. • A scorecard outcome of 1.0, reflecting target on each measurement scale, delivers half of maximum bonus. • 50% of bonus earned is paid in cash, 50% is deferred into shares for three years. • The scorecard measures for the bonus are set annually to reflect priorities. The committee sets measurement scales (disclosed retrospectively) that require year-on-year improvement. • For 2019, performance will be assessed against: – Safety – 20% – Environment – 10% – Reliable operations – 20% – Financial performance – 50%. • The committee holds discretion to adjust outcomes to reflect broader performance considerations. Bonus is subject to malus and clawback provisions following events such as misconduct, restatement or misstatement of results, and miscalculation. Malus may also be applied following a material failure impacting safety or environmental sustainability, or other exceptional circumstances as decided by the committee. Performance shares GCE – 500% CFO – 450% of salary Vesting reflects three-year performance Directly linked to long-term performance and represents the largest part of total remuneration. • Three-year performance period, followed by further three-year holding period. • Measures aligned to BP strategy and shareholders’ interests. • For the 2019-21 cycle, vesting level will first be assessed on performance over the three years in these areas: – TSR relative to oil and gas majors – 50% weighting. – ROACE – averaged over the full period – 20% weighting. – Progress against our strategic objectives – 30% weighting. • Underpin – the committee will then review broader performance, including absolute TSR, safety and environmental factors in order to determine the final vesting outcome. Performance shares are subject to malus and clawback provisions following events such as misconduct, restatement or misstatement of results, and miscalculation. Malus may also be applied following a material failure impacting safety or environmental sustainability, or other exceptional circumstances as decided by the committee. Share ownership Long-term shareholding obligation Reinforces alignment with shareholder interests, and stewardship of the enterprise. • Continuing requirement for executive directors to maintain a holding of five times salary. • Bob and Brian are expected to maintain a holding of at least two and a half times salary for two years post employment. • In addition, the executive directors have voluntarily elected to defer the vesting date of certain other share awards, with associated performance conditions, which would otherwise have been unrestricted. 105 Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018Salary and benefits Bob’s annual salary will remain at $1,854,000 for 2019. Brian’s salary will increase by 2% to £790,500 from the date of the 2019 AGM. For reference, the April 2019 annual pay review of our salaried employees in the UK was subject to a budget in excess of 3.5%. We expect to maintain benefits at the current level. Salary increases over the last five years Bob Dudley Brian Gilvary 2019 Nil 2018 Nil 2017 Nil 2016 Nil 2015 Nil Bob Dudley Brian Gilvary 2.0% 2.0% 3.75% 2019 2018 2017 2016 Nil 2015 Nil Salary with effect from AGM $1,854,000 £790,500 Increase Nil 2.0% Annual bonus For 2019 we have amended our bonus measures to include an environmental measure (10%) alongside safety (20%), reliable operations (20%) and financial performance (50%). This approach will provide a balanced assessment of how the business has performed over the course of the year and of our progress in addressing emissions reduction. We are also changing downstream refining availability to BP-operated downstream refining availability to more closely align to our BP-operated upstream plant reliability measure. The committee has set the 2019 targets after consultation on the safety targets with the SEEAC and on the financial targets with the MBAC. Although the detail of these targets is currently commercially sensitive, the committee will provide retrospective disclosure following the year end, as with previous cycles. As before, the committee will consider changes in plan conditions (including oil and gas prices and refining margins) when reviewing financial outcomes at year end, and retains discretion to review outcomes in the context of overall performance. Awards will be subject to malus and clawback provisions as described in the 2017 policy. The maximum bonus opportunity remains 225% of salary, for a maximum bonus score of 2.0. In accordance with the 2017 policy, the bonus payable for performance which meets the annual plan (i.e. a bonus score of 1.0 out of a maximum of 2.0) is half of maximum, 112.5% of salary. For any bonus earned, 50% will be delivered in cash and 50% will be deferred into shares that will vest after three years. Measures for 2019 annual bonus Element Safety 20% Measures include Environment 10% Financial performance Reliable operations 50% 20% Weighting for 2019 Measures include Weighting for 2019 Measures include Weighting for 2019 Measures include Weighting for 2019 Recordable injury frequency KPI 10% Sustainable emissions 10% reduction KPI Tier 1 and tier 2 process 10% safety events KPI Operating cash flow excluding Gulf of Mexico oil spill payments KPI 20% Underlying replacement cost profit KPI 20% Upstream unit production costs KPI 10% BP-operated upstream 10% plant reliability KPI 10% BP-operated downstream refining availability (Solomon Associates’ operational availability) KPI 106 Directors’ remuneration report BP Annual Report and Form 20-F 2018 Performance shares In line with our 2017 policy, the performance share awards for our 2019-21 cycle will be granted in 2019 at the level of 500% of salary for Bob and 450% of salary for Brian. Performance will then be measured over three years, with any vested shares being subject to a mandatory holding period of a further three years. These awards are subject to malus and clawback provisions as set out in the policy. The measures for the 2019-21 cycle of performance shares focus on shareholder value, capital discipline and future growth. Shareholder value The TSR element is measured on a relative basis against the oil majors: Chevron, ExxonMobil, Shell and Total. We maintain our belief that the current comparator group remains appropriate as it is used for benchmarking across a range of activities in other parts of the group. This measure carries a 50% weighting in the vesting calculation, with targets shown below. Capital discipline ROACE is calculated by dividing the underlying replacement cost profit (after adding back net interest) by average capital employed excluding cash and goodwill (see Glossary on page 315 for full definition). ROACE is measured based on the actual price environment for each of the years in question; there will be no adjustments for changes to plan conditions. For the 2019-21 performance shares award, this assessment will be averaged over the full three-year period. This ROACE measure carries a 20% weighting in the vesting calculation, and targets are shown in the table below. Future growth Measures for the strategic element are directly focused on delivery of 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 progress targets – which carry a 30% weighting in the vesting calculation – 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 will be able to review the basis of our assessment. The board regularly reviews progress on the strategic priorities throughout the year and BP’s quarterly results announcement includes updates on the group’s strategic progress. Broader performance assessment – the underpin Prior to approving vesting outcomes, the committee will also consider the broader performance of the business including absolute TSR performance, together with safety and environmental factors (including consideration of issues around greenhouse gases) over the three-year period. We refer to this as the underpin. The underpin will be applied after the formulaic outcome for the performance shares but before the final vesting outcome has been determined. In looking at environmental factors, the committee will consider the group’s progress on issues such as reducing emissions, improving our products and creating low carbon businesses – see page 46. Measures for 2019-21 performance shares Element Relative TSR versus oil majorsa Return on average capital employedb Strategic progress 50% Threshold vesting Maximum vesting KPI 20% KPI 30% 25% of element Third out of five 100% of element First place 0% of element 8.5% return on average capital employed 100% of element 12.5% return on average capital employed • Growing gas and advantaged oil in the upstream • Market-led growth in the downstream • Venturing and low carbon across multiple fronts • Gas, power and renewables trading and marketing growth a Nil vesting for fourth and fifth place. Vesting of 80% for second place. b Based on the average of performance over 2019, 2020 and 2021. 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). 107 Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018provided directly by the company rather than through the BPPS. The rules of this non-qualified arrangement are designed to mirror the design of the approved BPPS. The BPPS is closed to new hires, but for existing participants the plan continues to provide 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. On 1 April 2011, Brian elected to stop future service accrual and instead receive a cash allowance. His accrued benefits in the approved and unapproved plans remain linked to his final base pay. 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, Brian has a normal retirement age of 60. Subject to the consent of the committee, Brian may retire between age 55 and 60 and 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 from his leaving date. BPPS members can elect to stop accrual and instead receive a cash allowance of 35% of salary until March 2021, then progressively reducing to 15% of salary by March 2024 (or such earlier date that they would have accrued a maximum two-thirds pension under the BPPS had they not opted out). As noted above, on 1 April 2011 Brian elected to stop future service accrual and receive this cash allowance. Currently over 650 employees have elected to stop future service accrual under the final salary plan and instead receive the 35% cash allowance. Brian has offered to accelerate the schedule of this progressive reduction. Accordingly reductions to 30%, 25% and 20% will be made with effect from 1 June 2019, 2020 and 2021 respectively, and a final reduction to 15% with effect from 1 September 2023 being the date on which Brian would have reached a maximum two-thirds pension under the BPPS had he not opted out. Retirement benefits Bob Dudley Bob is provided with pension benefits and retirement savings through a combination of tax-qualified and non-qualified benefit plans. His normal retirement age is 60. The BP Supplemental Executive Retirement Benefit Plan (SERB) is a non-qualified defined benefit pension plan which provides a pension of 1.3% of final average earnings for each year of service, less benefits paid under all other BP (US) tax-qualified and non-qualified pension plans. In 2016 Bob reached the SERB service limit of 37 years of service and therefore no longer builds up further service accrual under these pension plans. However the accrued benefit remains linked to highest average earnings within the final 10 years. The benefit payable under the SERB is unreduced at age 60 or older. The BP Employee Savings Plan (ESP) is a US tax-qualified defined contribution plan to which both Bob and BP contribute. BP matches Bob’s salary contributions to a maximum of 7% of base salary, up to the IRS limit. The BP Excess Compensation (Savings) Plan (ECSP) is a non-qualified, unfunded, retirement savings plan to which BP notionally contributes 7% of base salary above the annual IRS limit. In common with around 2,000 other participants, Bob does not contribute to the ECSP. Under both savings plans, Bob is entitled to make investment elections, involving the actual investment holdings in the case of the ESP, and the notional investment holdings in the case of the ECSP. Benefits payable under the ECSP are unfunded and will therefore be paid from corporate assets. Accordingly annual investment returns on the ECSP are recognized as income for the single figure table, in addition to the notional contributions themselves. Conversely, annual investment losses are offset against the value of contributions and notional contributions by BP and therefore reduce the amount recognized as income for the single figure table. Brian Gilvary Brian is provided with pension benefits and retirement savings through a combination of tax-qualified and non-qualified benefit plans and a cash allowance. His normal retirement age is 60, although benefits accrued before 1 December 2006 may be paid from age 55 with BP’s consent. Brian is a member of a UK final salary defined benefit pension plan, the BP Pension Scheme (BPPS), along with over 3,800 other UK employees. Pension benefits that have been accrued in the BPPS in excess of the individual lifetime tax allowance set by legislation are provided to Brian via a non-qualified, unfunded pension arrangement Shareholding requirements Both executive directors remain subject to the share ownership requirement of five-times salary, which they currently exceed. Based on the commitments each director has made to the committee, we expect that Bob and Brian will each maintain shareholdings of at least 250% of salary for two years post employment. 108 Directors’ remuneration report BP Annual Report and Form 20-F 2018Non-executive director remuneration policy for 2019 The table below shows the remuneration policy approved by shareholders at the 2017 AGM. For the full remuneration policy, please go to bp.com/remuneration. 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 The chairman is provided with support and reasonable travelling expenses. Operation and opportunity The chairman is provided with an office and full-time secretarial and administrative support in London and a contribution to an office and secretarial support in 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 Approach Operation and opportunity 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. Non-executive directors are provided with administrative support and reasonable travelling expenses. Professional fees are reimbursed in the form of cash, payable following the provision of advice and assistance. Non-executive directors are reimbursed for all reasonable travelling and subsistence expenses (including any relevant tax) incurred in carrying out their duties. The reimbursement of professional fees incurred by non-executive directors based outside the UK in connection with advice and assistance on UK tax compliance matters. 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 Jens Bertelsen, company secretary on 29 March 2019. 109 Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018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), including FRS 101 ‘Reduced Disclosure Framework’. In preparing the consolidated financial statements the directors have also elected to comply with IFRS as issued by the International Accounting Standards Board (IASB). In preparing those financial statements, the directors are required to: • Select suitable accounting policies and then apply them consistently. • Make judgements and estimates that are reasonable and prudent. • Present information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information. • Provide additional disclosure when compliance with the specific requirements of IFRS is insufficient to enable users to understand the impact of particular transactions, other events and conditions on the group’s financial position and financial performance. • State that applicable accounting standards have been followed, subject to any material departures disclosed and explained in the parent company financial statements. • Prepare the financial statements on the going concern basis unless it is inappropriate to presume that the company will continue in business. The directors are responsible for keeping adequate accounting records that disclose with reasonable accuracy at any time the financial position of the group and company and enable them to ensure that the consolidated financial statements comply with the Companies Act 2006 and Article 4 of the IAS Regulation and the parent company financial statements comply with the Companies Act 2006. They are also responsible for safeguarding the assets of the group and company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities. Having made the requisite enquiries, so far as the directors are aware, there is no relevant audit information (as defined by Section 418(3) of the Companies Act 2006) of which the company’s auditors are unaware, and the directors have taken all the steps they ought to have taken to make themselves aware of any relevant audit information and to establish that the company’s auditors are aware of that information. The directors confirm that to the best of their knowledge: • The consolidated financial statements, prepared in accordance with IFRS as issued by the IASB, IFRS as adopted by the EU and in accordance with the provisions of the Companies Act 2006, give a true and fair view of the assets, liabilities, financial position and profit or loss of the group. • The parent company financial statements, prepared in accordance with United Kingdom generally accepted accounting practice, give a true and fair view of the assets, liabilities, financial position, performance and cash flows of the company. • The management report, which is incorporated in the strategic report and directors’ report, includes a fair review of the development and performance of the business and the position of the group, together with a description of the principal risks and uncertainties that they face. Helge Lund Chairman 29 March 2019 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 55. 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 53. 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 75-86. This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 110 BP Annual Report and Form 20-F 2018Going concern In accordance with provision C.1.3 of the Code, the directors 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. 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. An audit committee meeting in January 2019 carried out an annual review of the effectiveness of the system of internal control. In considering this system, the audit committee noted that it is designed to manage, rather than eliminate, the risk of failure to achieve business objectives and can only provide reasonable, and not absolute, assurance against material misstatement or loss. This review included a report from the group head of audit which summarized group audit’s consideration of the design and operation of elements of BP’s system of internal control over significant risks arising in the categories of strategic and commercial, safety and operational and compliance and control, in addition to considering 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 audit committee was satisfied that these were or are being appropriately addressed by the remedial actions proposed by management. At its meeting in March 2019, the board considered the review undertaken by the audit committee and the proposed disclosures outlining the company’s risk management and internal control systems prior to publication of the annual report and accounts. A statement regarding the company’s internal controls over financial reporting is set out on page 300. 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 a viability 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, including committed capital investment. Taking into account the company’s current position and its principal risks on page 55, 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. These scenarios included a process safety incident and a sustained oil price decline. 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. This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 111 Corporate governanceBP Annual Report and Form 20-F 2018112 BP Annual Report and Form 20-F 2018Financial statements 114 Consolidated financial statements of the BP group Independent auditor’s reports Group income statement Group statement of comprehensive income 114 129 130 Group statement of changes in equity Group balance sheet Group cash flow statement 131 132 133 1. 2. 3. 151 134 4. 5. 6. 153 154 156 134 Notes on financial statements Significant accounting policies Significant event – Gulf of Mexico oil spill Business combinations and other significant transactions Disposals and impairment Segmental analysis Revenue from contracts with customers Income statement analysis Exploration expenditure Taxation Dividends Earnings per share Property, plant and equipment Capital commitments Goodwill Intangible assets Investments in joint ventures Investments in associates Other investments Inventories Trade and other receivables Valuation and qualifying accounts 13. 14. 15. 16. 17. 18. 19. 20. 165 165 166 167 168 168 170 170 159 159 160 160 163 163 7. 8. 9. 10. 11. 12. 171 171 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. Trade and other payables Provisions Pensions and other post- retirement benefits Cash and cash equivalents Finance debt Capital disclosures and analysis of changes in net debt Operating leases Financial instruments and financial risk factors Derivative financial instruments Called-up share capital Capital and reserves Contingent liabilities Remuneration of senior management and non- executive directors Employee costs and numbers Auditor’s remuneration Subsidiaries, joint arrangements and associates Condensed consolidating information on certain US subsidiaries 210 Supplementary information on oil and natural gas (unaudited) Oil and natural gas exploration and production activities Movements in estimated net proved reserves 211 217 Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves Operational and statistical information 238 Parent company financial statements of BP p.l.c. Company balance sheet Company statement of changes in equity Notes on financial statements 1. 2. 3. 4. 5. Significant accounting policies Investments Receivables Pensions Payables 238 239 240 240 243 243 243 247 6. 7. 8. 9. 10. 11. 12. 13. 14. Taxation Called-up share capital Capital and reserves Financial guarantees Share-based payments Auditor’s remuneration Directors’ remuneration Employee costs and numbers Related undertakings 172 172 172 179 179 180 180 181 185 192 194 197 198 199 199 200 201 232 235 247 248 248 249 249 249 249 250 251 BP Annual Report and Form 20-F 2017 BP Annual Report and Form 20-F 2018 115 113 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 Independent auditor’s report on the Annual Report and Accounts to the members of BP p.l.c. Report on the audit of the financial statements Opinion In our opinion: • The financial statements of BP p.l.c. (the ‘parent company’) and its subsidiaries (the ‘group’) give a true and fair view of the state of the group’s and of the parent company’s affairs as at 31 December 2018 and of the group’s profit for the year then ended. • The group financial statements have been properly prepared in accordance with International Financial Reporting Standards (IFRSs) as adopted by the European Union (EU) and IFRSs as issued by the International Accounting Standards Board (IASB). • The parent company financial statements have been properly prepared in accordance with United Kingdom generally accepted accounting practice including FRS 101 ‘Reduced Disclosure Framework'. • The financial statements have been prepared in accordance with the requirements of the Companies Act 2006 and, as regards the group financial statements, Article 4 of the IAS Regulation. We have audited the financial statements of BP p.l.c. which comprise: • Group income statement; • Group statement of comprehensive income; • Group and parent company statements of changes in equity; • Group and parent company balance sheets; • Group cash flow statement; • Group related Notes 1 to 38 to the financial statements, including a summary of significant policies; and • Parent company related Notes 1 to 14 to the financial statements, including a summary of significant accounting policies. The financial reporting framework that has been applied in the preparation of the group financial statements is applicable law and IFRSs as adopted by the European Union and as issued by the IASB. The financial framework that has been applied in the preparation of the parent company financial statements is applicable law and United Kingdom accounting standards including FRS 101 (United Kingdom generally accepted accounting practice). Basis for opinion We conducted our audit in accordance with International Standards on Auditing (UK) (ISAs (UK)) and applicable law. Our responsibilities under those standards are further described in the auditor’s responsibilities for the audit of the financial statements section of our report. We are independent of the group and the parent company in accordance with the ethical requirements that are relevant to our audit of the financial statements in the UK, including the Financial Reporting Council’s (the ‘FRC’s’) Ethical Standard as applied to listed public interest entities, and we have fulfilled our other ethical responsibilities in accordance with these requirements. We confirm that the non-audit services prohibited by the FRC’s Ethical Standard were not provided to the group or the parent company. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. Summary of our audit approach Key audit matters The key audit matters that we identified in the current year were: • Impairment of Upstream oil and gas property, plant and equipment (PP&E) assets; • Accounting for acquisitions and disposals within the Upstream segment; • Impairment of exploration and appraisal assets; • Accounting for structured commodity transactions within the integrated supply and trading function, and the valuation of other level 3 financial instruments, where fraud risks may arise in revenue recognition; • User access management controls relating to financial systems; and • Management override of controls. Two key audit matters were identified by the previous auditor and described in their report for the year ended 31 December 2017 and are not included in our report for the year ended 31 December 2018. These were: • The determination of the liabilities, contingent liabilities and disclosures arising from the Gulf of Mexico oil spill - the provisions have substantially decreased from a quantitative perspective and the level of judgement in determining BP’s liabilities has reduced significantly as legal settlements have been reached; and • US Tax reform - the reform was signed into law in 2017 and gave rise to a one-off taxation charge. Whilst the impact of the reform has continued to be assessed in 2018, the judgement required and quantitative impact in the current year is considerably lower. The previous auditor also included a key audit matter in respect of unauthorized trading activity in the integrated supply and trading function. This is covered by the key audit matter set out above covering the accounting for structured commodity transactions and valuation of certain level 3 financial instruments. They also identified a key audit matter in respect of the estimation of oil and gas reserves and resources, which we have considered in the context of impairment of Upstream oil and gas PP&E assets. Materiality We have set materiality for the current year at $750 million based on profit before tax and underlying replacement cost profit before interest and tax. 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 2018 Scoping Our scope covered 136 components. Of these, 108 were full-scope audits, covering 71% of group revenue, and the remaining 28 were subject to specific procedures on certain account balances by component audit teams or the group audit team. First year audit transition The year ended 31 December 2018 is our first as auditor of the group. We commenced transition activities after our selection as auditor being announced in November 2016. These activities included: • Establishing independence from BP by exiting non-audit services which would be independence-impairing, as BP transitioned these to new service providers; • Establishing an appropriately resourced and skilled global audit team, including specialists, in all relevant locations; • Developing and delivering a bespoke “BP Academy” training course for Deloitte personnel joining the BP audit engagement; and • Holding introductory meetings with BP management. We commenced our audit planning procedures subsequent to us becoming independent on 16 October 2017. After establishing independence, our work included: • Shadowing the previous auditor through the 31 December 2017 audit, including attendance at key meetings, including audit committee meetings; • Reviewing the previous auditor’s 2016 and 2017 audit files; • Reviewing historical accounting policies and accounting judgements through discussion with management and review and challenge of management’s papers and supporting documentation; and • Conducting group audit team visits to components. These procedures built our understanding of the group which, together with our existing knowledge of the oil and gas industry, informed our audit risk assessment, through which we identified the risks of material misstatement to the group’s financial statements. We presented our transition observations to the group’s audit committee in a transition report in April 2018, with an update in May 2018. We presented further observations, together with our audit plan, in July 2018, and provided an update to our plan in December 2018. Conclusions relating to going concern, principal risks and viability statement Going concern We have reviewed the directors’ statement on page 111 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 group’s and company’s ability to continue to do so over a period of at least twelve months from the date of approval of the financial statements. We considered as part of our risk assessment the nature of the group, its business model and related risks including where relevant the impact of Brexit, the requirements of the applicable financial reporting framework and the system of internal control. We evaluated the directors’ assessment of the group’s ability to continue as a going concern, including challenging the underlying data and key assumptions used to make the assessment, and evaluated the directors’ plans for future actions in relation to their going concern assessment. We are required to state whether we have anything material to add or draw attention to in relation to that statement required by Listing Rule 9.8.6R(3) and report if the statement is materially inconsistent with our knowledge obtained in the audit. Principal risks and viability statement We confirm that we have nothing material to report, add or draw attention to in respect of these matters. Based solely on reading the directors’ statements and considering whether they were consistent with the knowledge we obtained in the course of the audit, including the knowledge obtained in the evaluation of the directors’ assessment of the group’s and the company’s ability to continue as a going concern, we are required to state whether we have anything material to add or draw attention to in relation to: • the disclosures on pages 55-56 that describe the principal risks and explain how they are being We confirm that we have nothing material to report, add or draw attention to in respect of these matters. managed or mitigated; • the directors' confirmation on page 110 that they have carried out a robust assessment of the principal risks facing the group, including those that would threaten its business model, future performance, solvency or liquidity; or • the directors’ explanation on page 111 as to how they have assessed the prospects of the group, 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 group 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. We are also required to report whether the directors’ statement relating to the prospects of the group required by Listing Rule 9.8.6R(3) is materially inconsistent with our knowledge obtained in the audit. Key audit matters Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial statements of the current period and include the most significant assessed risks of material misstatement (whether or not due to fraud) that we identified. 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 2018 115 These matters included those which had the greatest effect on: the overall audit strategy, the allocation of resources in the audit; and directing the efforts of the engagement team. Throughout the course of our audit we identify risks of material misstatement (‘risks’) and classify those risks according to their severity. In assigning a category we consider both the likelihood of a risk of a material misstatement and the potential magnitude of a misstatement in making the assessment. Certain risks are classified as ‘significant’ or ‘higher’ depending on their severity. The category of the risk determines the level of evidence we seek in providing assurance that the associated financial statement item is not materially misstated. These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters. Impairment of upstream oil and gas PP&E assets Key audit matter description How the scope of our audit responded to the key audit matter The group balance sheet includes property, plant and equipment (PP&E) of $135 billion, of which $99 billion is oil and gas properties within the Upstream segment. As required by IAS 36 'Impairment of Assets', management performed a review of the upstream cash generating units (CGUs) for indicators of impairment and impairment reversal as at 31 December 2018. Where such indicators were identified, management estimated the recoverable amount of the CGU to determine if any impairment charges or reversals were required. For the year ended 31 December 2018, BP recorded $400 million of Upstream impairment charges and $580 million of impairment reversals. Through our risk assessment procedures, we have determined that there are three key estimates in management’s review for indicators of impairment/reversal and the level of impairment charge/reversal to record where indicators are identified. These are: • Long-term oil and gas prices - BP’s long-term oil and gas price assumptions have a significant impact on CGU impairment assessments and valuations performed across the portfolio, and are inherently uncertain. There is a risk that management’s oil and gas price assumptions are not reasonable, leading to a material misstatement. • Discount rates - Given the long timeframes involved, certain impairment assessments and valuations are sensitive to the discount rate applied. There is a risk that discount rates do not reflect the return required by the market and the risks inherent in the cash flows being discounted, leading to a material misstatement. Determination of the appropriate discount rate can be judgemental. • Reserves estimates - A key input to impairment assessments and valuations is the production forecast, in turn closely related to the group’s reserves estimates and field development assumptions. CGU-specific estimates are not generally material. However, material misstatements could arise either from systematic flaws in reserves estimation policies, or due to flawed estimates in a particularly material individual impairment test. Whilst all CGUs must be assessed for indicators of impairment and impairment reversal annually, we focused on certain individual CGUs with a total carrying value of $21.8 billion which we determined would be most at risk of a material impairment ($750 million) as a result of a reasonably possible change in the key assumptions, particularly the long-term oil and gas price assumptions. Accordingly, we identified these as a significant audit risk. We also focused on assets with a further $31.5 billion of combined CGU carrying value which were less sensitive. We identified these as a higher audit risk as they would be potentially at risk in aggregate to a material impairment by a change in such assumptions. Further information regarding these sensitivities is given in Note 1. We tested management’s internal controls over the setting of oil and gas prices, discount rates and reserve estimates. In addition, we conducted the following substantive procedures. Long-term oil and gas prices • We compared BP’s oil and gas price assumptions against third- party forecasts, peer information and relevant market data to determine whether BP’s forecasts were within the range of such forecasts. • In challenging management's forecasts, we considered the extent to which they reflected the energy transition due to climate change. Discount rates • We independently evaluated BP’s discount rates used in impairment tests with input from Deloitte valuation specialists. • We assessed whether country risks were appropriately reflected in BP’s discount rates. Reserves estimates • We performed a look-back analysis to check for indications of bias over time. • We reviewed BP’s reserves estimation methods and policies, assisted by Deloitte reserves experts. • We assessed how these policies had been applied to seven internal reserves estimates. • We reviewed reports provided by external experts and assessed their scope of work and findings. • We assessed the competence, capability and objectivity of BP’s internal and external reserve experts, through obtaining their relevant professional qualifications and experience. Other procedures • We challenged management’s cash generating unit determination, scrutinized the impairment and impairment reversal indicator analysis and considered whether there was any contradictory evidence present. • Where such indicators were identified, we validated that BP’s asset impairment methodology was appropriate and tested the integrity of impairment models. • We compared hydrocarbon production forecasts and proved and probable reserves to reserve reports and our understanding of the life of fields. • We verified estimated future capital and operational costs by comparison to approved budgets and assessed them with reference to field production forecasts. • We also assessed these estimates against management’s historical forecasting accuracy and whether the estimates had been determined and applied on a consistent basis across the group where relevant. 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 2018 Key observations Long-term oil and gas prices We determined that BP’s Brent oil price forecasts are reasonable when compared against the range of other third-party forecasts. We challenged BP’s Henry Hub, NBP and Asian LNG price curves for periods when they were somewhat higher than the range of other third-party forecasts. However, management ran additional tests using a Henry Hub, NBP and Asian LNG price curve consistent with the range of third-party forecasts, which demonstrated that the carrying values recorded in the balance sheet are not impacted. Discount rates Our Deloitte valuation specialists calculated a different range for weighted average cost of capital than was determined by management. We also found that some simplifications are taken when making group- wide assumptions for country and asset-specific risk premium adjustments, and for calculating pre-tax discount rates, given the group's CGUs which operate in multiple tax jurisdictions. Management reperformed impairment tests using higher discount rates and only one impairment test was impacted, with a difference which was not significant. Accordingly we were satisfied with the results of the testing. We reviewed the disclosures included in Note 1 to the accounts in respect of price and discount rate assumptions used and confirmed that they were the same as those used in the impairment tests.  Reserves estimates Having involved Deloitte oil and gas reserves experts in our testing, we concluded that the assumptions used to derive the estimates were reasonable. Accounting for acquisitions and disposals within the Upstream segment Key audit matter description How the scope of our audit responded to the key audit matter There were certain acquisition and disposal transactions within the Upstream segment that required fair valuation of assets and liabilities acquired and disposed of, and consideration of complex accounting judgements, to which we devoted significant engagement team time and resource. Accordingly, this had a significant effect on our audit strategy. These transactions were: • The $10.3 billion acquisition of onshore US assets from BHP, including the fair valuation of assets and liabilities acquired; • The disposal of BP’s interest in the Greater Kuparuk Area in Alaska and simultaneous purchase of an incremental interest in the BP-operated Clair field in the UK North Sea; and • The disposal of BP’s interest in the Magnus field in the North Sea, where the consideration included a level 3 financial asset, the valuation of which depends on the future performance of Magnus. We tested management’s internal key controls over the valuation assumptions and accounting approaches for each of these significant transactions. In addition, we conducted the following substantive procedures: • We reviewed the enacted sale and purchase agreements and management’s accounting analysis to corroborate that the accounting treatment applied was consistent with the underlying commercial terms. • With input from our valuations and reserves specialist teams, we reviewed and challenged management’s fair value estimates, focusing on the key assumptions (including pricing, discount rates and reserves risking estimates). • We tested the mechanical accuracy of the valuation models. • We assessed the independence, objectivity, competence and scope of work performed by BP’s third-party valuation specialist used in the acquisition from BHP. Key observations We noted that the assumptions underlying the fair value calculation for the onshore US assets acquired from BHP were at the conservative end of the range but concurred that the purchase price represented the fair value of the assets and liabilities acquired, in accordance with IFRS 3. We observed that in some cases, the fair values of oil and gas assets from certain market transactions, including the BHP acquisition, implied valuation assumptions that were more conservative than those used in value-in-use impairment calculations. The latter, as defined in IAS 36, represents management’s best estimate of the future cash flows of an asset, discounted at a market rate of return, whereas the former, as defined in IFRS 13 'Fair Value Measurement', is determined by the prices at which oil and gas assets are actually changing hands in orderly transactions under prevailing market conditions. We concluded that in their respective IFRS contexts, and in the presence of valid evidence, the use of different assumptions to estimate fair values and value in use was appropriate. We reviewed the disclosures included by management in Note 3 to the accounts and concluded that these are compliant with IFRS 3 requirements. 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 2018 117 Impairment of exploration and appraisal assets Key audit matter description How the scope of our audit responded to the key audit matter The group capitalizes exploration and appraisal (E&A) expenditure on a project-by-project basis in line with IFRS 6 'Exploration for and Evaluation of Mineral Resources'. At the end of 2018, $16.0 billion of E&A expenditure was carried in the group balance sheet. E&A activity is inherently risky and a significant proportion of projects fail, requiring the write-off of the related capitalized costs when the relevant criteria in IFRS 6 and BP’s accounting policy are met. There is a risk that certain capitalized E&A costs are not written off promptly at the appropriate time, in line with information from, and decisions about E&A activities, and the impairment requirements of IFRS 6. Through our detailed risk assessment, which is based on our analysis of the portfolio of E&A assets held by BP, making reference to BP’s own analysis of the same assets, we identified a significant risk in respect of certain specific assets in the Gulf of Mexico with a total carrying value of $2.3 billion, as certain licences in question have expired and a partner has recently withdrawn from other licences, and three licences elsewhere ($1.6 billion) which are scheduled to expire or require next phase decisions in 2019. BP is in negotiations to extend all these licences. Further details regarding the significant accounting judgement are given in Note 1 to the accounts. We obtained an understanding of the group’s E&A impairment assessment processes and tested management’s controls. In addition, we conducted the following substantive procedures: We reviewed and challenged management’s significant IFRS 6 impairment judgements, guided by our risk assessment, having regard to the impairment criteria of IFRS 6 and BP’s accounting policy. We verified key facts relevant to significant carrying amounts (e.g. obtaining evidence of future E&A plans and budgets, evidence of active dialogue with partners and regulators including negotiations to renew licences or modify key terms). We performed a licence-by-licence risk assessment of the group’s E&A balance through to year end, to identify significant carrying amounts with a significant current period risk of impairment (e.g. new information from exploration activities, or imminent licence expiry). We performed a look-back analysis of impairment charges recorded in the period, and assessed whether impairment charges were timely. We tested the completeness and accuracy of information used in management’s E&A impairment assessment, by reviewing and testing key controls over management’s register of E&A licences and vouching key aspects of this to underlying support (e.g. licence documentation); holding meetings and discussions with operational and finance management; considering adverse changes in management’s reserves and resource estimates associated with E&A assets; reviewing correspondence with regulators and joint arrangement partners; and considering the implications of capital allocation decisions. When considering capital allocation decision making, we considered whether any projects are unlikely to proceed on the grounds that they are not currently consistent with BP’s strategy or which would otherwise have a prohibitively high environmental or social impact for the directors to sanction the necessary investment. Key observations We concluded that the key assumptions had been appropriately determined, the judgements management had made were appropriately supported, and no additional impairments were identified from the work we performed. Where BP had concluded that E&A costs should continue to be carried in respect of projects where licences had expired, we obtained appropriate evidence that there was ongoing correspondence with the relevant regulatory bodies, as referred to in Note 1 to the financial statements, to support management’s judgement. We also confirmed management's view that they did not consider that the development of any of their assets is inconsistent with BP’s strategy and stated climate change ambitions. 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 2018 Accounting for structured commodity transactions (SCTs) within the integrated supply and trading function (IST), and the valuation of other level 3 financial instruments, where fraud risks may arise in revenue recognition Key audit matter description How the scope of our audit responded to the key audit matter In the normal course of business, the integrated supply and trading function (IST) enters into a variety of transactions for delivering value across the group’s supply chain. The nature of these transactions requires significant audit effort be directed towards challenging management’s valuation estimates or the adopted accounting treatment. Accounting for structured commodity transactions: IST may also enter into a variety of transactions which we refer to as SCTs. We generally consider a SCT to be an arrangement having one of the following features: a) two or more counterparties with non-standard contractual terms; b) multiple commodity-based transactions; and/or c) contractual arrangements entered into in contemplation of each other. SCTs are often long-dated, can have a significant multi-year financial impact, and may require the use of complex valuation models or unobservable market inputs when determining their fair value, in which case they will be classified as level 3 financial instruments under IFRS 13, Fair Value Measurement. There are inherent risks in the accounting for SCTs as these contracts are often complex and the associated accounting considerations often feature multiple elements, which are subject to management judgement, that will have a material impact on the presentation and disclosure of these transactions on the primary financial statements and key performance measures, including in particular whether finance debt should be recognized. We have identified the accounting for SCTs as a significant audit risk. Level 3 financial instruments: Unlike other financial instruments whose values or inputs are readily observable and therefore more easily independently corroborated, there are certain transactions for which the valuation is inherently more subjective due to the use of either bespoke valuation models and/or unobservable inputs. These instruments are classified as level 3 financial assets or liabilities under IFRS 13. This degree of subjectivity also gives rise to potential fraud through management incorporating bias in determining fair values. Accordingly, we have identified these as a significant audit risk, and the area in which a fraud risk is most likely to arise in relation to revenue recognition. As at 31 December 2018, the group’s total financial assets and liabilities measured at fair value were $12.8 billion and $8.9 billion, of which level 3 derivative financial instruments were $3.6 billion and $3.1 billion, respectively. Accounting for structured commodity transactions: For structured commodity transactions, we performed audit procedures to: • Evaluate the design, implementation and operating effectiveness of controls related to the review of such non-standard transactions, including the: • New activity integration control, which is designed to evaluate and approve the appropriateness of the new activity; and • Accounting policy review, which is designed to evaluate the appropriateness of accounting treatment in line with published IFRS accounting literature. • Develop an understanding of the commercial rationale of the transactions through review of executed transaction documents and discussions with management. • Perform a detailed accounting analysis for a sample of structured commodity transactions involving significant day 1 profits, working capital arrangements, offtake arrangements and/or commitments. To assess the appropriateness of the accounting treatment of SCTs, we embedded technical accounting specialists on the audit team to assist in performing an assessment of the treatment applied by management. Other level 3 financial instruments: To address the complexities associated with auditing the value of level 3 financial instruments, our team included valuation specialists having significant quantitative and modelling expertise to assist in performing our audit procedures. Our valuation audit procedures included the following control and substantive procedures: We tested the design and operating effectiveness of the group’s valuation controls including the: • Model certification control, which is designed to review a model’s theoretical soundness and the appropriateness of its valuation methodology; and • Independent price verification control, which is designed to review the appropriateness of valuation inputs that are not observable and are significant to the financial instrument’s valuation. We performed substantive valuation testing procedures at interim and year-end balance sheet dates, including: • Developing independent estimates, using externally sourced inputs and challenger models to evaluate against management’s fair value estimates by evaluating whether the differences between our independent estimates and management’s estimates were within a reasonable range; • Evaluating management’s valuation methodologies against standard valuation practice and analysing whether a consistent framework is applied across the business period over period; and • Benchmarking management’s input assumptions against the expected assumptions of other market participants and observable market data. Key observations We reviewed the features of 10 SCTs and determined that the accounting adopted for each of these was appropriate and in accordance with IFRS. We concluded that management’s valuations relating to level 3 instruments were appropriate. We did not identify any transactions, valuation estimates or accounting entries which were the result of fraudulent misrepresentation of revenue recognition. 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 2018 119 User access management controls relating to financial systems Key audit matter description How the scope of our audit responded to the key audit matter The group’s financial systems environment is complex, with 107 separate systems scoped as being relevant for the group audit. In addition, during the year, BP changed one of its key IT service providers. We obtained an understanding of management’s processes and relevant financial systems and tested the associated general IT controls. This testing led us to identify a number of deficiencies, notably in relation to user access. Due to the reliance on financial systems within the group, controls over system user access are critical to maintaining an effective control environment. As a result of our procedures, we identified a number of deficiencies relating to user access management, both within the group and the group’s IT service organizations (together ‘access deficiencies’). The access deficiencies identified increase the risk that individuals within the group and at service organizations had inappropriate access during the period. The existence of deficiencies during the year and at the year end, and the transition of the main IT service organization from one supplier to another during the year, result in an increased risk that data and reports from the affected systems are not reliable. The issues identified impact all components within the scope of our group audit. The group put in place a programme of activities to remediate the deficiencies, which extends into 2019. Accordingly, management also identified mitigating and compensating controls, and in particular established controls to analyse, through exploitation analyses, whether inappropriate access had been exploited during the year, working with both the legacy and new IT service organizations. The user access management controls are pervasive to the group’s operations and accordingly the level of risk ascribed to our work in this area is dependent on the nature and complexity of the control itself and balances within the financial statements the control addresses. In responding to the identified deficiencies in user access we have used our teams of IT and internal control specialists to: • Test the controls that management has implemented or re- designed in order to remediate the deficiencies; • Assess and test the alternative or compensating controls that management has identified as mitigating access deficiencies, including the direct assessment of those controls operated by the legacy and new IT service organizations and identified business controls that do not rely on information that is potentially affected by the access deficiencies; and • Determine the impact that utilizing inappropriate levels of access could feasibly have had on the affected systems including assessing the likelihood of inappropriate user access impacting the financial statements, and testing controls implemented by management to identify instances of the use of inappropriate access, working with both the legacy and new IT service organizations. Key observations Our review of the analysis management performed to identify whether the access deficiencies were exploited during the year did not identify instances where such access had been used inappropriately. As a result, we were satisfied with the results of the remediation to date and mitigation activities such that we continued to adopt an audit approach which places reliance on the effectiveness of financial controls and which, under our methodology, enables us to apply lower sample sizes in our substantive testing. Management continues to work, with the support of the new IT service provider, to remediate fully the access deficiencies identified. This page does not form part of BP's Annual Report on Form 20-F as filed with the SEC. 120 BP Annual Report and Form 20-F 2018 Management override of controls Key audit matter description How the scope of our audit responded to the key audit matter We conducted a risk assessment for management override fraud risks by considering: • Potential areas where the group’s financial statements could be We tested the relevant primary and, where necessary, compensating controls that management identified as responding to the risk of fraudulent journal entries. manipulated; • Pressures or incentives to achieve certain IFRS or non-GAAP measures due to the remuneration arrangements of people in Financial Reporting Oversight Roles (FRORs), including management and senior executives; • Potential for inappropriate accounting estimates and judgements; and • Accounting for significant unusual transactions and estimates arising from changes to the business. Our response to the risk of management override of controls included testing the appropriateness of journal entries recorded in the general ledger. We identified control deficiencies at components where testing was performed and as a result, our audit approach required adjustment. Management remediated the control deficiencies identified where it was possible to do so. Some remediation activity will continue into 2019 and accordingly, management also directed us to other compensating controls which they considered to mitigate the risks, which we subsequently tested. This had a bearing on the allocation of resources in the audit, and the direction of effort of the audit team. Accordingly, we identified this as a key audit matter. In addition, we have: • Made inquiries of individuals involved in the financial reporting process about inappropriate or unusual activity relating to the processing of journal entries and other adjustments. • Identified and tested relevant entity-level controls, in particular those related to the BP Code of Conduct, whistleblowing (BP OpenTalk) and controls monitoring financial reporting processes and financial results. • Used our data analytics tools to select journal entries and other adjustments made at the end of a reporting period or otherwise having characteristics which are associated with common fraud schemes for testing. • Tested journal entries and other adjustments recorded in the general ledger throughout the period, with a particular focus on adjustments that occur late in the financial close process. We have reviewed accounting estimates for bias and evaluated whether the circumstances producing the bias, if any, represent a risk of material misstatement due to fraud. A number of the most significant estimates are covered by the other Key Audit Matters set out above. This assessment included: • Evaluating whether the judgements and decisions made by management in making the accounting estimates included in the financial statements, even if they are individually reasonable, indicate a possible bias on the part of BP's management that may represent a risk of material misstatement due to fraud; and • Performing a retrospective review of management judgements and assumptions related to significant accounting estimates reflected in the financial statements of the prior year. We considered whether there were any significant transactions that are outside the normal course of business, or that otherwise appear to be unusual due to their nature, timing or size. The risks and responses to the revenue recognition risks within the integrated supply and trading function are set out above. Key observations The nature of the identified deficiencies over journal-entry controls varies from business to business, so there is no single root cause. At the year end: • In some businesses these operating effectiveness deficiencies were able to be remediated by management and our testing of the remediation concluded it was effective. • In other businesses the deficiencies could not be quickly remediated and management identified direct and precise compensating controls to mitigate the design deficiencies identified. These compensating controls included low-level analytical reviews (e.g. individual asset reviews), controls over closing balances, period-end analytical review controls, and certain automated business controls. Our testing of these compensating controls concluded that they were, in combination, appropriately designed and implemented and that they were operating effectively for the period. Our substantive testing of the journal entries and other adjustments, selected through the use of data analytics tools, did not identify any inappropriate items, and accordingly we concluded that there was no evidence of management override. We did not identify any evidence of overall bias or any significant unusual transactions for which the business rationale (or the lack thereof) of the transaction suggested that it may have been entered into to engage in fraudulent financial reporting or to conceal misappropriation of assets. Our application of materiality We define materiality as the magnitude of misstatement in the financial statements that could reasonably be expected to influence the economic decisions of a reasonably knowledgeable user. We use materiality both in planning the scope of our audit work and in evaluating the results of our work. Based on our professional judgement, we determined materiality for the financial statements as a whole as follows: 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 2018 121 Materiality Basis for determining materiality Rationale for the benchmark applied Group financial statements Parent company financial statements Materiality has been set at $750 million for the current year. In 2017, the previous auditor used a materiality of $500 million. This reflects BP’s financial performance in 2018 and 2017. We used a number of metrics to determine group materiality, most notably profit before taxation and underlying replacement cost profit before interest and taxation. Our selected materiality figure represents 4.5% of profit before taxation, and 3.2% of underlying replacement cost profit before interest and taxation. In 2017, the previous auditor used 5% of underlying replacement cost profit before interest and taxation to determine materiality. Materiality has been set at $1,200 million for the current year. In 2017, the previous auditor used a materiality of $1,300 million. We determined materiality for our audit of the standalone parent using 1% of net assets. We conducted an assessment of which line items we understand to be the most important to investors and analysts by reviewing analyst reports and BP’s communications to shareholders and lenders, as well as the communications of peer companies. This assessment resulted in us selecting the financial statement line items above. The materiality determined for the standalone parent company financial statements exceeds the group materiality as it is determined on a different basis given the nature of the operations. As the company is non- trading and operates primarily as a holding company, we believe the net asset position is the most appropriate benchmark to use. Profit before tax is the benchmark ordinarily considered by us when auditing listed entities. It provides comparability against other companies across all sectors, but has limitations when auditing companies whose earnings are strongly correlated to commodity prices, which can be volatile from one period to the next, and therefore may not be representative of the volume of transactions and the overall size of the business in the year. Where there were balances and transactions within the parent company accounts that were within the scope of the audit of the group financial statements, our procedures were undertaken using the lower materiality level applying to the group audit components. It was only for the purposes of testing balances not relevant to the group audit, such as intercompany investment balances, that the higher level of materiality applied in practice. Whilst not a GAAP measure, underlying replacement cost profit before interest and tax is one of the key metrics communicated by management in BP's results announcements. It excludes some of the volatility arising from changes in crude oil, gas and product prices as well as “non-operating items” and this was also the key measure applied by the previous auditor when determining materiality in 2017. Profit before tax $16,723 million Profit before tax Group materiality Group materiality $750 million Component materiality range $413 million to $150 million Audit committee reporting threshold $25 million Performance materiality, which is the value that determines the extent of our audit sampling, has been set at $375 million which is 50% of group materiality (2017 75%). Given overall group materiality is higher in 2018 reflecting the improved results of the business, performance materiality could also be set at a higher level but we judged it to be appropriate to constrain this for 2018 given it is our first year as auditor, which gives a potentially heightened risk of not identifying misstatements due to us having a lower level of knowledge of the business than a recurring auditor would have. We agreed with the Main Board Audit Committee that we would report to the committee all audit differences in excess of $25 million (2017 $25 million), as well as differences below that threshold that, in our view, warranted reporting on qualitative grounds. We also report to the audit committee on disclosure matters that we identified when assessing the overall presentation of the financial statements. An overview of the scope of our audit As a result of the highly disaggregated nature of the group, with operations in over 70 countries through approximately 1,000 components, a significant portion of our audit planning effort was ensuring that the scope of our work is appropriate in addressing the identified risks of material misstatement. This page does not form part of BP's Annual Report on Form 20-F as filed with the SEC. 122 BP Annual Report and Form 20-F 2018 The factors that we considered when assessing the scope of the BP audit, and the level of work to be performed at the components that are in scope for group reporting purposes, included the following: • The financial significance of an operating unit to BP’s revenue and profit before tax, or PP&E, including consideration of the financial significance of specific account balances or transactions. • The significance of specific risks relating to an operating unit, history of unusual or complex transactions, identification of significant audit issues or the potential for, or a history of, material misstatements. • The effectiveness of the control environment and monitoring activities, including entity-level controls. • The findings, observations and audit differences that we noted as a result of the previous auditor’s 2016 and 2017 audit engagements. To ensure we were able to obtain sufficient, appropriate audit evidence for the purposes of our audit of the financial statements, we performed full scope audit procedures for 108 reporting consolidation units ('cons units' or components) which were selected based on their size or risk characteristics. Our full-scope audits are in the UK, US, Angola, Azerbaijan, Germany and Singapore. One of the full-scope cons units includes the investment in Rosneft, a material associate not controlled by BP. In addition, we performed audit procedures on specified account balances by local teams for 16 cons units also covering operations in Trinidad & Tobago and Australia. We performed audit procedures on specified account balances by segment teams to component materiality, with certain additional specific procedures performed by local teams, covering an additional 12 cons units. In our assessment of the residual balances, we have considered in particular the risk that there could be a material misstatement within the large number of geographically dispersed businesses, in particular within the Downstream segment. This assessment included use of our analytic tools to interrogate data, preparation of trend analysis and comparison of business performance to market benchmark prices. We concluded that through this additional risk assessment, we have reduced the audit risk of such a misstatement arising to a sufficiently low level. The remaining components are not significant individually and include many small, low risk components and balances. On average, they each represent 0.06% of group revenue and 0.08% of property, plant and equipment. For these components, we performed other procedures, including conducting analytical review procedures, making inquiries, and evaluating and testing management’s group-wide controls across a range of locations and segments in order to address the risk of residual misstatement on a segment-wide and component basis. Oversight of component auditors The group audit team provides direct oversight, review, and coordination of our local audit teams. The group audit team interacted regularly with the local Deloitte teams during each stage of the audit, were responsible for the scope and direction of the audit process and reviewed key working papers. We maintained continuous and open dialogue with our local teams in addition to holding formal meetings quarterly to ensure that we were fully aware of their progress and results of their procedures. The senior statutory auditor and other group audit partners and staff visited local component teams in all of the locations named above. These visits included attending planning meetings, discussing the audit approach and any issues arising from the component team's work, meetings with local management, and reviewing key audit working papers on higher and significant-risk areas to drive a consistent and high-quality audit. We were provided with direct access to Rosneft’s auditor in order to evaluate their audit work on the financial statements of Rosneft, used as the basis for BP’s equity accounting. We held meetings with Rosneft’s auditor throughout the year, issued audit instructions to them, reviewed their written clearance reports responding to these instructions and, through our direct access, were able to exercise appropriate supervision and oversight of their audit work. We also tested directly BP’s procedures and controls over its accounting for the investment in Rosneft. 19% 20% 9% Property, plant and equipment 8% 64% 3% Sales and other 6% operating revenues 71% Full audit scope Specified account balances Specific audit procedures Review at group level Full audit scope Specified account balances Specific audit procedures Review at group level 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 2018 123 Other information The directors are responsible for the other information. The other information comprises the information included in the annual report other than the financial statements and our auditor’s report thereon. Our opinion on the financial statements does not cover the other information and, except to the extent otherwise explicitly stated in our report, we do not express any form of assurance conclusion thereon. We have nothing to report in respect of these matters. In connection with our audit of the financial statements, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the financial statements or our knowledge obtained in the audit or otherwise appears to be materially misstated. If we identify such material inconsistencies or apparent material misstatements, we are required to determine whether there is a material misstatement in the financial statements or a material misstatement of the other information. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. In this context, matters that we are specifically required to report to you as uncorrected material misstatements of the other information include where we conclude that: • Fair, balanced and understandable - the statement given by the directors that they consider 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 group’s position and performance, business model and strategy, is materially inconsistent with our knowledge obtained in the audit; or • Audit committee reporting - the section describing the work of the audit committee does not appropriately address matters communicated by us to the audit committee; or • Directors’ statement of compliance with the UK Corporate Governance Code - the parts of the directors’ statement required under the Listing Rules relating to the company’s compliance with the UK Corporate Governance Code containing provisions specified for review by the auditor in accordance with Listing Rule 9.8.10R(2) do not properly disclose a departure from a relevant provision of the UK Corporate Governance Code. Responsibilities of directors As explained more fully in the directors’ responsibilities statement, the directors are responsible for the preparation of the financial statements and for being satisfied that they give a true and fair view, and for such internal control as the directors determine is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error. In preparing the financial statements, the directors are responsible for assessing the group’s and the parent company’s ability to continue as a going concern, disclosing as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the group or the parent company or to cease operations, or have no realistic alternative but to do so. Auditor’s responsibilities for the audit of the financial statements Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISAs (UK) will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of a reasonably knowledgeable user, taken on the basis of these financial statements. Details of the extent to which the audit was considered capable of detecting irregularities, including fraud are set out below. A further description of our responsibilities for the audit of the financial statements is located on the FRC’s website at: frc.org.uk/ auditorsresponsibilities. This description forms part of our auditor’s report. Extent to which the audit was considered capable of detecting irregularities, including fraud We identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and then design and perform audit procedures responsive to those risks, including obtaining audit evidence that is sufficient and appropriate to provide a basis for our opinion. Identifying and assessing potential risks related to irregularities In identifying and assessing risks of material misstatement in respect of irregularities, including fraud and non-compliance with laws and regulations, our procedures included the following: • Meeting throughout the year with the group head of ethics and compliance and reviewing BP’s internal ethics and compliance reporting summaries, including concerning investigations; • Enquiring of management, internal audit, and the audit committee, including obtaining and reviewing supporting documentation, concerning the group’s policies and procedures relating to: – identifying, evaluating and complying with laws and regulations and whether they were aware of any instances of non-compliance – detecting and responding to the risks of fraud and whether they have knowledge of any actual, suspected or alleged fraud – the internal controls established to mitigate risks related to fraud or non-compliance with laws and regulations; • Discussing among the engagement team regarding how and where fraud might occur in the financial statements and any potential indicators of fraud. The engagement team includes audit partners and staff who have extensive experience of working with companies in the same sectors as BP operates, and this experience was relevant to the discussion about where fraud risks may arise. The discussions also involved fraud experts from Deloitte’s forensic accounting function in the Corporate Finance service line, who advised the engagement team of fraud schemes that had arisen in similar sectors and industries and participated in the initial fraud risk assessment brainstorming discussions; and • Obtaining an understanding of the legal and regulatory frameworks that the group operates in, focusing on those laws and regulations that we determined had a direct effect on the financial statements or that had a fundamental effect on the operations of the group. These include This page does not form part of BP's Annual Report on Form 20-F as filed with the SEC. 124 BP Annual Report and Form 20-F 2018 the UK Companies Act, UK Corporate Governance Code, IFRS as issued by the IASB and adopted by the EU, FRS 101, US Securities Exchange Act 1934 and relevant SEC regulations, as well as laws and regulations prevailing in each country in which we identified a full- scope component. In addition, we considered compliance with terms of the group’s operating licence / regulatory solvency requirements / environmental regulations when assessing the group’s ability to continue as a going concern. Audit response to risks identified As a result of performing the above, we did not identify any key audit matters related to the potential risk of non-compliance with laws and regulations. We did identify two key audit matters relating to fraud risks, as described above. Our procedures to respond to risks identified included the following: • Reviewing the financial statement disclosures and testing supporting documentation to assess compliance with relevant laws and regulations discussed above; • Enquiring of management, the audit committee and legal counsel concerning actual and potential litigation and claims; • Performing analytical procedures to identify any unusual or unexpected relationships that may indicate risks of material misstatement due to fraud; • Reading minutes of meetings of those charged with governance, reviewing internal audit reports and reviewing correspondence with HMRC; and • In addressing the risk of fraud through management override of controls, testing the appropriateness of journal entries and other adjustments; assessing whether the judgements made in making accounting estimates are indicative of a potential bias; and evaluating the business rationale of any significant transactions that are unusual or outside the normal course of business. We also communicated relevant identified laws and regulations and potential fraud risks to all engagement team members, including internal specialists and significant component audit teams, and remained alert to any indications of fraud or non-compliance with laws and regulations throughout the audit. Report on other legal and regulatory requirements Opinions on other matters prescribed by the Companies Act 2006 In our opinion the part of the directors’ remuneration report to be audited has been properly prepared in accordance with the Companies Act 2006. In our opinion, based on the work undertaken in the course of the audit: • The information given in the strategic report and the directors’ report for the financial year for which the financial statements are prepared is consistent with the financial statements; and • The strategic report and the directors’ report have been prepared in accordance with applicable legal requirements. In the light of the knowledge and understanding of the group and the parent company and their environment obtained in the course of the audit, we have not identified any material misstatements in the strategic report or the directors’ report. Matters on which we are required to report by exception Adequacy of explanations received and accounting records Under the Companies Act 2006 we are required to report to you if, in our opinion: • We have not received all the information and explanations we require for our audit; or • Adequate accounting records have not been kept by the parent company, or returns adequate for our audit We have nothing to report in respect of these matters. have not been received from branches not visited by us; or • The parent company financial statements are not in agreement with the accounting records and returns. Directors’ remuneration Under the Companies Act 2006 we are also required to report if in our opinion certain disclosures of directors’ remuneration have not been made or the part of the directors’ remuneration report to be audited is not in agreement with the accounting records and returns. We have nothing to report in respect of these matters. Other matters Auditor tenure The board appointed Deloitte as the company’s auditor with effect from 29 March 2018 to fill the vacancy arising from the resignation of the previous auditor. On 21 May 2018, shareholders resolved at the annual general meeting to appoint Deloitte as auditor from the conclusion of the meeting until the conclusion of the annual general meeting to be held in 2019 and authorized the directors to set the audit fees. The first accounting period we audited was the 12 months ended 31 December 2018. In 2017, we commenced our audit planning procedures. The period of total uninterrupted engagement including previous renewals and reappointments of the firm is accordingly one year. Consistency of the audit report with the additional report to the audit committee Our audit opinion is consistent with the additional report to the audit committee we are required to provide in accordance with ISAs (UK). Use of our report This report is made solely to the company’s members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work has been undertaken so that we might state to the company’s members those matters we are required to state to them in an auditor’s report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the company’s members as a body, for our audit work, for this report, or for the opinions we have formed. Douglas King FCA (Senior statutory auditor) For and on behalf of Deloitte LLP Statutory Auditor London, United Kingdom 29 March 2019 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 2018 125 Consolidated financial statements of the BP group Report of Independent Registered Public Accounting Firm To the shareholders and board of directors of BP p.l.c. Opinion on the financial statements We have audited the accompanying group balance sheet of BP p.l.c. and subsidiaries (the Company) as at 31 December 2018, the related group income statement, statements of comprehensive income and changes in equity, and group cash flow statement, for the year ended 31 December 2018, and the related notes (collectively referred to as the 'financial statements'). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of 31 December 2018, and the results of its operations and its cash flows for the year ended 31 December 2018, in conformity with International Financial Reporting Standards (IFRS) as adopted by the European Union and IFRS as issued by the International Accounting Standards Board. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of 31 December 2018, based on criteria established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting relating to internal control over financial reporting and our report dated 29 March 2019 expressed an unqualified opinion on the Company's internal control over financial reporting. Basis for opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. /s/ Deloitte LLP London United Kingdom 29 March 2019 The first accounting period we audited was the 12 months ended 31 December 2018. In 2017, we commenced our audit planning procedures. 126 BP Annual Report and Form 20-F 2018 Consolidated financial statements of the BP group Report of Independent Registered Public Accounting Firm To the shareholders and board of directors of BP p.l.c. Opinion on internal control over financial reporting We have audited the internal control over financial reporting of BP p.l.c. and subsidiaries (the Company) as at 31 December 2018, based on the criteria established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting relating to internal control over financial reporting (UK FRC Guidance). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of 31 December 2018, based on the criteria established in the UK FRC Guidance. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as at and for the year ended 31 December 2018, of the Company and our report dated 29 March 2019, expressed an unqualified opinion on those financial statements. As described in Management’s report on internal control over financial reporting on page 301, management excluded from its assessment the internal control over financial reporting at Petrohawk Energy Corporation, which was acquired on 31 October 2018 and whose financial statements constitute 10.3% and 4.0% of net and total assets, respectively, 0.2% of total revenues and other income, and 0.05% of profit for the year of the consolidated financial statement amounts as at and for the year ended 31 December 2018. Accordingly, our audit did not include the internal control over financial reporting at Petrohawk Energy Corporation. Basis for opinion The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and limitations of internal control over financial reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ Deloitte LLP London, United Kingdom 29 March 2019 Consent of independent registered public accounting firm We consent to the incorporation by reference of our reports dated 29 March 2019, relating to the consolidated financial statements of BP p.l.c. (the 'company'), and the effectiveness of the company's internal control over financial reporting, appearing in the Annual Report on Form 20-F of the company for the year ended 31 December 2018, in the following Registration Statements: Registration Statements on Form F-3 (File Nos. 333-226485, 333-226485-01 and 333-226485-02) of BP p.l.c., BP Capital Markets p.l.c. and BP Capital Markets America Inc.; 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, 333-210318) of BP p.l.c. /s/ Deloitte LLP London, United Kingdom 29 March 2019 BP Annual Report and Form 20-F 2018 127 Consolidated financial statements of the BP group Report of Independent Registered Public Accounting Firm To the shareholders and board of directors of BP p.l.c. Opinion on the financial statements We have audited the accompanying group balance sheets of BP p.l.c. (the Company) as of 31 December 2017, 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 two years in the period ended 31 December 2017, and the related notes (collectively referred to as the "group financial statements"). In our opinion, the group financial statements present fairly, in all material respects, the financial position of BP p.l.c. at 31 December 2017 and the results of its operations and its cash flows for each of the two years in the period ended 31 December 2017, in conformity with International Financial Reporting Standards (IFRS) as adopted by the European Union and IFRS as issued by the International Accounting Standards Board. Basis for opinion These financial statements are the responsibility of BP p.l.c.'s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to BP p.l.c. in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ Ernst & Young LLP We served as the Company's auditor from 1909 to 2018. London, United Kingdom 29 March 2018 Note that the report set out above is included for the purposes of BP p.l.c.’s Annual Report on Form 20-F for 2018 only and does not form part of BP p.l.c.’s Annual Report and Accounts for 2017. 1. 2. 128 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 2018 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 Profit (loss) for the year attributable to BP shareholders Per ordinary share (cents) 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 2018 2017 5 16 17 7 4 19 5 5 4 8 7 24 9 11 11 11 11 298,756 897 2,856 773 456 303,738 229,878 23,005 1,536 15,457 860 1,445 12,179 19,378 2,528 127 16,723 7,145 9,578 9,383 195 9,578 46.98 46.67 2.82 2.80 240,208 1,177 1,330 657 1,210 244,582 179,716 24,229 1,775 15,584 1,216 2,080 10,508 9,474 2,074 220 7,180 3,712 3,468 3,389 79 3,468 17.20 17.10 1.03 1.03 $ million 2016 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 BP Annual Report and Form 20-F 2018 129  $ million 2016 172 254 30 1 (639) 196 81 — — 833 13 769 (2,496) — 739 (1,757) (988) (816) (846) 30 (816) Note 2018 9,578 2017 3,468 (3,771) 1,986 — — (126) 120 — (244) 58 417 4 (3,542) 2,317 (37) (718) 1,562 (1,980) 7,598 7,444 154 7,598 (120) 14 197 116 112 — — 564 (196) 2,673 3,646 — (1,303) 2,343 5,016 8,484 8,353 131 8,484 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 Currency translation differences Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on 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 Costs of hedging marked to market Costs of hedging reclassified to the income statement Share of items relating to equity-accounted entities, net of tax Income tax relating to items that may be reclassified 30 30 30 30 30 16, 17 9 Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Cash flow hedges that will subsequently be transferred to the balance sheet Income tax relating to items that will not be reclassified 24 30 9 Other comprehensive income Total comprehensive income Attributable to BP shareholders Non-controlling interests a See Note 32 for further information. 130 BP Annual Report and Form 20-F 2018 Group statement of changes in equitya At 31 December 2017 Adjustment on adoption of IFRS 9, net of tax At 1 January 2018 Profit (loss) for the year Other comprehensive income Total comprehensive income Dividendsb Cash flow hedges transferred to the balance sheet, net of tax Repurchase of ordinary share capital Share-based payments, net of tax Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests, net of tax At 31 December 2018 At 1 January 2017 Profit (loss) for the year Other comprehensive income Total comprehensive income Dividendsb Repurchase of ordinary share capital Share-based payments, net of tax Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests, net of tax At 31 December 2017 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, net of tax At 31 December 2016 a See Note 32 for further information. b See Note 10 for further information. Share capital and capital reserves 46,122 — 46,122 — — — — — — 230 — — Treasury shares (16,958) — (16,958) — — — — — — 1,191 — — Foreign currency translation reserve (5,156) — (5,156) — (3,746) (3,746) — — — — — — Fair value reserves Profit and loss account BP shareholders' equity Non- controlling interests Total equity $ million (743) (54) (797) — (216) (216) — 26 — — — — 75,226 (126) 75,100 9,383 2,023 11,406 (6,699) — (355) (718) 14 — 98,491 (180) 98,311 9,383 (1,939) 7,444 (6,699) 26 (355) 703 14 — 1,913 — 1,913 195 (41) 154 (170) 100,404 (180) 100,224 9,578 (1,980) 7,598 (6,869) — — — — 207 26 (355) 703 14 207 46,352 (15,767) (8,902) (987) 78,748 99,444 2,104 101,548 46,122 — — — — — — — — (18,443) — — — — — 1,485 — — (6,878) — 1,722 1,722 — — — — — (1,153) — 410 410 — — — — — 75,638 3,389 2,832 6,221 (6,153) (343) (798) 215 446 95,286 3,389 4,964 8,353 (6,153) (343) 687 215 446 1,557 79 52 131 (141) — — — 366 96,843 3,468 5,016 8,484 (6,294) (343) 687 215 812 46,122 (16,958) (5,156) (743) 75,226 98,491 1,913 100,404 43,902 — — — — 2,220 — — (19,964) — — — — 1,521 — — (7,267) — 389 389 — — — — (823) — (330) (330) — — — — 81,368 115 (1,020) (905) (4,611) (750) 106 430 97,216 115 (961) (846) (4,611) 2,991 106 430 1,171 57 (27) 30 (107) — — 463 98,387 172 (988) (816) (4,718) 2,991 106 893 46,122 (18,443) (6,878) (1,153) 75,638 95,286 1,557 96,843 BP Annual Report and Form 20-F 2018 131 Note 2018 12 14 15 16 17 18 20 30 9 24 19 20 30 18 25 22 30 26 23 22 30 26 9 23 24 32 32 32 135,261 12,204 17,284 8,647 17,673 1,341 192,410 637 1,834 5,145 1,179 3,706 5,955 210,866 326 17,988 24,478 3,846 963 1,019 222 22,468 71,310 282,176 46,265 3,308 4,626 9,373 2,101 2,564 68,237 13,830 5,625 575 56,426 9,812 17,732 8,391 112,391 180,628 101,548 99,444 2,104 101,548 $ million 2017 129,471 11,551 18,355 7,994 16,991 1,245 185,607 646 1,434 4,110 1,112 4,469 4,169 201,547 190 19,011 24,849 3,032 1,414 761 125 25,586 74,968 276,515 44,209 2,808 4,960 7,739 1,686 3,324 64,726 13,889 3,761 505 55,491 7,982 20,620 9,137 111,385 176,111 100,404 98,491 1,913 100,404 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 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 Total equity Helge Lund Chairman R W Dudley Group chief executive 29 March 2019 132 BP Annual Report and Form 20-F 2018 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 Expenditure on property, plant and equipment, intangible and other assets Acquisitions, net of cash acquired Investment in joint ventures Investment in associates Total cash capital expenditure Proceeds from disposals of fixed assets Proceeds from disposals of businesses, net of cash disposed Proceeds from loan repayments Net cash used in investing activities Financing activities Repurchase of shares 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 yeara Cash and cash equivalents at end of year a See Note 1 for further information. Note 2018 2017 $ million 2016 16,723 7,180 (2,295) 8 5 4 7 24 24 3 4 4 10 1,085 15,457 404 (3,753) 1,535 (468) 348 2,528 (1,928) 127 690 (386) 986 672 (2,858) (2,577) (5,712) 22,873 (16,707) (6,986) (382) (1,013) (25,088) 940 1,911 666 (21,571) (355) 9,038 (7,210) 1,317 — (6,699) (170) (4,079) (330) (3,107) 25,575 22,468 1,603 15,584 6 (2,507) 1,253 (304) 375 2,074 (1,572) 220 661 (394) 2,106 (848) (4,848) 2,344 (4,002) 18,931 (16,562) (327) (50) (901) (17,840) 2,936 478 349 (14,077) (343) 8,712 (6,276) (158) 1,063 (6,153) (141) (3,296) 544 2,102 23,484 25,586 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 (16,701) (1) (50) (700) (17,452) 1,372 1,259 68 (14,753) — 12,442 (6,685) 51 887 (4,611) (107) 1,977 (820) (2,905) 26,389 23,484 BP Annual Report and Form 20-F 2018 133 Notes on financial statements 1. Significant accounting policies, judgements, estimates and assumptions Authorization of financial statements and statement of compliance with International Financial Reporting Standards The consolidated financial statements of BP p.l.c and its subsidiaries (collectively referred to as BP or the group) for the year ended 31 December 2018 were approved and signed by the group chief executive and chairman on 29 March 2019 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 as applicable to companies reporting under IFRS. 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 2018. The accounting policies that follow have been consistently applied to all years presented, except where otherwise indicated. The consolidated financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where otherwise indicated. Significant accounting policies: use of judgements, estimates and assumptions Inherent in the application of many of the accounting policies used in preparing the consolidated financial statements is the need for BP management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and assumptions used. The accounting judgements and estimates that have a significant impact on the results of the group are set out in boxed text below, and should be read in conjunction with the information provided in the Notes on financial statements. The areas requiring the most significant judgement and estimation in the preparation of the consolidated financial statements are: accounting for the investment in Rosneft; oil and natural gas accounting, including the estimation of reserves; the recoverability of asset carrying values; derivative financial instruments; provisions and contingencies; and pensions and other post-retirement benefits. Where an estimate has a significant risk of resulting in a material adjustment to the carrying amounts of assets and liabilities within the next financial year this is specifically noted within the boxed text. The group no longer considers the recoverability of trade receivables to represent one of its significant accounting judgements following the adoption of IFRS 9 ‘Financial Instruments´ and resulting recognition of expected credit losses, see Impact of new International Financial Reporting Standards for more information. The group does not consider income taxes to represent a significant estimate or judgement for 2018, see Income taxes for more information. 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 14 for further information. Goodwill may arise upon investments in joint ventures and associates, being the surplus of the cost of investment over the group’s share of the net fair value of the identifiable assets and liabilities. Any such goodwill is recorded within the corresponding investment in joint ventures and associates. Goodwill may also arise upon acquisition of interests in joint operations that meet the definition of a business. The amount of goodwill separately recognized is the excess of the consideration transferred over the group's share of the net fair value of the identifiable assets and liabilities. Interests in joint arrangements The results, assets and liabilities of joint ventures are incorporated in these consolidated financial statements using the equity method of accounting as described below. Certain of the group’s activities, particularly in the Upstream segment, are conducted through joint operations. BP recognizes, on a line-by-line basis in the consolidated financial statements, its share of the assets, liabilities and expenses of these joint operations incurred jointly with the other partners, along with the group’s income from the sale of its share of the output and any liabilities and expenses that the group has incurred in relation to the joint operation. Interests in associates The results, assets and liabilities of associates are incorporated in these consolidated financial statements using the equity method of accounting as described below. 134 BP Annual Report and Form 20-F 2018 1. Significant accounting policies, judgements, estimates and assumptions – continued Significant judgement: investment in Rosneft Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. For BP, the judgement that the group has significant influence over Rosneft Oil Company (Rosneft), a Russian oil and gas company is significant. As a consequence of this judgement, BP uses the equity method of accounting for its investment and BP's share of Rosneft's oil and natural gas reserves is included in the group's estimated net proved reserves of equity-accounted entities. If significant influence was not present, the investment would be accounted for as an investment in an equity instrument measured at fair value as described under 'Financial assets' below and no share of Rosneft's oil and natural gas reserves would be reported. Significant influence is defined in IFRS as the power to participate in the financial and operating policy decisions of the investee but is not control or joint control of those policies. Significant influence is presumed when an entity owns 20% or more of the voting power of the investee. Significant influence is presumed not to be present when an entity owns less than 20% of the voting power of the investee. BP owns 19.75% of the voting shares of Rosneft. The Russian federal government, through its investment company JSC Rosneftegaz, owned 50% plus one share of the voting shares of Rosneft at 31 December 2018. 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 chairman 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. BP's management consider, therefore, that the group has significant influence over Rosneft, as defined by IFRS. The equity method of accounting Under the equity method, an investment is carried on the balance sheet at cost plus post-acquisition changes in the group’s share of net assets of the entity, less distributions received and less any impairment in value of the investment. Loans advanced to equity-accounted entities that have the characteristics of equity financing are also included in the investment on the group balance sheet. The group income statement reflects the group’s share of the results after tax of the equity-accounted entity, adjusted to account for depreciation, amortization and any impairment of the equity-accounted entity’s assets based on their fair values at the date of acquisition. The group statement of comprehensive income includes the group’s share of the equity-accounted entity’s other comprehensive income. The group’s share of amounts recognized directly in equity by an equity-accounted entity is recognized 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 in the accounting policies used by the equity-accounted entity and those used by BP, adjustments are made to those financial statements to bring the accounting policies used into line with those of the group. Unrealized gains on transactions between the group and its equity-accounted entities are eliminated to the extent of the group’s interest in the equity-accounted entity. The group assesses investments in equity-accounted entities for impairment whenever there is objective evidence that the investment is impaired. If any such objective evidence of impairment exists, the carrying amount of the investment is compared with its recoverable amount, being the higher of its fair value less costs of disposal and value in use. If the carrying amount exceeds the recoverable amount, the investment is written down to its recoverable amount. Segmental reporting The group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the group chief executive, BP’s chief operating decision maker, in deciding how to allocate resources and in assessing performance. The accounting policies of the operating segments are the same as the group’s accounting policies described in this note, except that IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker. For BP, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit. 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 if the borrowings form part of the net investment in the subsidiary, joint venture or associate. On disposal or for certain partial disposals of a non-US dollar functional currency subsidiary, joint venture or associate, the related accumulated exchange gains and losses recognized in equity are reclassified from equity to the income statement. Non-current assets held for sale Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell. Significant non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale, and actions required to complete the plan of sale should indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. BP Annual Report and Form 20-F 2018 135 1. Significant accounting policies, judgements, estimates and assumptions – continued Property, plant and equipment and intangible assets are not depreciated or amortized once classified as held for sale. Intangible assets Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, computer software, patents, licences and trademarks and are stated at the amount initially recognized, less accumulated amortization and accumulated impairment losses. Intangible assets are carried initially at cost unless acquired as part of a business combination. Any such asset is measured at fair value at the date of the business combination and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights. Intangible assets with a finite life, other than capitalized exploration and appraisal costs as described below, are amortized on a straight-line basis over their expected useful lives. For patents, licences and trademarks, expected useful life is the shorter of the duration of the legal agreement and economic useful life, and can range from three to fifteen years. Computer software costs generally have a useful life of three to five years. The expected useful lives of assets and the amortization method are reviewed on an annual basis and, if necessary, changes in useful lives or the amortization method are accounted for prospectively. Oil and natural gas exploration, appraisal and development expenditure Oil and natural gas exploration, appraisal and development expenditure is accounted for using the principles of the successful efforts method of accounting as described below. Licence and property acquisition costs Exploration licence and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still under way or planned or that it has been determined, or work is under way to determine, that the discovery is economically viable based on a range of technical and commercial considerations, and sufficient progress is being made on establishing development plans and timing. If no future activity is planned, the remaining balance of the licence and property acquisition costs is written off. Lower value licences are pooled and amortized on a straight-line basis over the estimated period of exploration. Upon 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. The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within one year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover potentially economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. an offshore platform or a pipeline) would be required before production could begin, and where the economic viability of that major capital expenditure depends on the successful completion of further exploration or appraisal work in the area, remain capitalized on the balance sheet as long as such work is under way or firmly planned. 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 Judgement is required to determine whether it is appropriate to continue to carry costs associated with exploration wells and exploratory- type stratigraphic test wells on the balance sheet. This includes costs relating to exploration licences or leasehold property acquisitions. It is not unusual to have such costs remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and natural gas field is performed or while the optimum development plans and timing are established. 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 circumstances that indicate 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 that were scheduled to expire at the end of 2013 and some with terms that 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. The carrying amount of capitalized costs is included in Note 8. 136 BP Annual Report and Form 20-F 2018 1. Significant accounting policies, judgements, estimates and assumptions – continued 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, directly attributable general or specific finance costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. The capitalized value of a finance lease is also included within property, plant and equipment. Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated with the item will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Inspection costs associated with major maintenance programmes are capitalized and amortized over the period to the next inspection. Overhaul costs for major maintenance programmes, and all other maintenance costs are expensed as incurred. Oil and natural gas properties, including related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is amortized over proved developed reserves. Licence acquisition, common facilities and future decommissioning costs are amortized over total proved reserves. The unit-of-production rate for the depreciation of common facilities takes into account expenditures incurred to date, together with estimated future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed through these common facilities. Information on the carrying amounts of the group’s oil and natural gas properties, together with the amounts recognized in the income statement as depreciation, depletion and amortization is contained in Note 12 and Note 5 respectively. Estimates of oil and natural gas reserves determined by applying US Securities and Exchange Commission regulations including the determination of prices using 12-month historical data 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. 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 210, which is unaudited. Details on BP’s proved reserves and production compliance and governance processes are provided on page 286. The 2018 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 210. 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 and depreciation method of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives or the depreciation method are accounted for prospectively. An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in the period in which the item is derecognized. 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. BP Annual Report and Form 20-F 2018 137 1. Significant accounting policies, judgements, estimates and assumptions – continued 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 that are not reflected in the discount rate and are discounted to their present value typically using a pre-tax discount rate that reflects current market assessments of the time value of money. Fair value less costs of disposal is the price that would be received to sell the asset in an orderly transaction between market participants and does not reflect the effects of factors that may be specific to the group and not applicable to entities in general. An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to the lower of its recoverable amount and the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Impairment reversals are recognized in profit or loss. After a reversal, the depreciation charge is adjusted in future periods to allocate the asset’s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life. Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the group of CGUs to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of the group of CGUs to which goodwill has been allocated is compared with its recoverable amount. Where the recoverable amount of the group of CGUs is less than the carrying amount (including goodwill), an impairment loss is recognized. An impairment loss recognized for goodwill is not reversed in a subsequent period. 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. For example, certain oil and gas properties with shared infrastructure may be grouped together to form a single CGU. Alternative groupings of assets or CGUs may result in a different outcome from impairment testing. See Note 14 for details on how these groupings have been determined in relation to the impairment testing of goodwill. As 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 expected sales proceeds or similar recent market transaction data or, where recent market transactions 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, estimates are made about the assumptions market participants would use when pricing the asset, CGU or group of CGUs containing goodwill and the test is performed on a post-tax basis. Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts of assets are shown in Note 12, Note 14 and Note 15. The estimates for assumptions made in impairment tests in 2018 relating to discount rates, oil and gas properties and oil and gas prices are discussed below. Changes in the economic environment or other facts and circumstances may necessitate revisions to these assumptions and could result in a material change to the carrying values of the group's assets within the next financial year. Discount rates For discounted cash flow calculations, future cash flows are adjusted for risks specific to the cash-generating unit. Value-in-use calculations are typically discounted using a pre-tax discount rate based upon the cost of funding the group derived from an established model, adjusted to a pre-tax basis. 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 2018 the post-tax discount rate was 6% (2017 6%) and the pre- tax discount rate was 9% (2017 9%). 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 (2017 2%). The judgement of classifying a country as higher risk takes into account various economic and geopolitical factors. 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. 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 The long-term price assumptions used to determine recoverable amount based on value-in-use impairment tests from 2024 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 (2017 $75 per barrel and $4/mmBtu, both in 2015 prices, from 2023 onwards). The price assumptions used for the five-year period to 2023 have been set such that there is a gradual transition from current market prices to the long-term price assumptions as noted above, with the rate of increase reducing in the later years. 138 BP Annual Report and Form 20-F 2018 1. Significant accounting policies, judgements, estimates and assumptions – continued Oil prices rebounded in 2018 in the face of cooperative production restraint from OPEC and some non-OPEC producers, but weakened late in the year as production restraint eased and US supply recorded record growth. BP's long-term assumption for oil prices is higher than recent market prices, reflecting the judgement that recent prices are not consistent with the market being able to produce sufficient oil to meet global demand sustainably in the longer term, especially given the financial requirements of key low-cost oil producing economies. US gas prices remained relatively low for much of 2018, before increasing temporarily in the final quarter due to a combination of low storage and cold weather. Strong growth of low-cost supply helped to moderate prices through much of the year. BP's long-term price assumption for US gas is higher than recent market prices as US gas demand is expected to grow strongly, both domestic demand as well as exports of liquefied natural gas, absorbing the lowest cost resources from the sweet spots, and forcing producers to go to more expensive/drier gas, as well as requiring increased investment in infrastructure. Oil and natural gas reserves In addition to oil and gas prices, significant technical and commercial assessments are required to determine the group’s estimated oil and natural gas reserves. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of the group’s estimates of its oil and natural gas reserves. BP bases its proved reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements. Reserves assumptions for value-in-use and fair value tests reflect the reserves and resources that management currently intend to develop. The recoverable amount of oil and gas properties is determined using a combination of inputs including reserves, resources and production volumes. Risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved.  The interdependency of these inputs, risk factors and the wide diversity of our oil and gas properties limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to one or more of the underlying assumptions. The recoverable amount of oil and gas properties is primarily sensitive to changes in the long-term oil and gas price assumptions. Management do not expect a change in these long-term price assumptions within the next financial year that would result in a material impairment charge. However, sensitivity analysis may be performed if a specific oil and gas property is identified to have low headroom above its carrying amount. In 2018, the group identified oil and gas properties with carrying amounts totalling $22,000 million where the headroom, as at the dates of the last impairment test performed on those assets, was less than or equal to 20% of the carrying value, including $1,345 million in relation to equity-accounted entities. A change in the discount rate, reserves, resources or the oil and gas price assumptions in the next financial year may result in the recoverable amount of one or more of these assets falling below the current carrying amount. Goodwill Irrespective of whether there is any indication of impairment, BP is required to test annually for impairment of goodwill acquired in business combinations. The group carries goodwill of approximately $12.2 billion on its balance sheet (2017 $11.6 billion), principally relating to the Atlantic Richfield, Burmah Castrol, Devon Energy and Reliance transactions. If there are low oil or natural gas prices for an extended period or the long-term price outlook weakens, the group may need to recognize goodwill impairment charges against its Upstream segment goodwill. Sensitivities relating to impairment testing of goodwill in the Upstream segment are provided in Note 14. Inventories Inventories, other than inventories held for short-term trading purposes, are stated at the lower of cost and net realizable value. Cost is determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses. Net realizable value is determined by reference to prices existing at the balance sheet date, adjusted where the sale of inventories after the reporting period gives evidence about their net realizable value at the end of the period. Inventories held for short-term trading purposes are stated at fair value less costs to sell and any changes in fair value are recognized in the income statement. Supplies are valued at the lower of cost on a weighted average basis and net realizable value. Leases Agreements under which payments are made to owners in return for the right to use a specific 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 except where capitalized as exploration or appraisal expenditure. See significant accounting policy: Exploration and appraisal expenditure. Financial assets Financial assets are recognized initially at fair value, normally being the transaction price. In the case of financial assets not at fair value through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their classification, as set out below. The group derecognizes financial assets when the contractual rights to the cash flows expire or the financial asset is transferred to a third party. This includes the derecognition of receivables for which discounting arrangements are entered into. From 1 January 2018, the group classifies its financial asset debt instruments as measured at amortized cost, fair value through other comprehensive income or fair value through profit or loss. The classification depends on the business model for managing the financial assets and the contractual cash flow characteristics of the financial asset. Financial assets measured at amortized cost Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets are derecognized or impaired and when interest is recognized using the effective interest method. This category of financial assets includes trade and other receivables. BP Annual Report and Form 20-F 2018 139 1. Significant accounting policies, judgements, estimates and assumptions – continued Financial assets measured at fair value through other comprehensive income Financial assets are classified as measured at fair value through other comprehensive income when they are held in a business model the objective of which is both to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely payments of principal and interest. The group does not have any financial assets classified in this category. Financial assets measured at fair value through profit or loss Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at amortized cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category. Investments in equity instruments Investments in equity instruments are subsequently measured at fair value through profit or loss unless an election is made on an instrument- by-instrument basis to recognise fair value gains and losses in other comprehensive income. Derivatives designated as hedging instruments in an effective hedge 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. Cash equivalents Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets measured at amortized cost or fair value through profit or loss. Impairment of financial assets measured at amortized cost The group assesses on a forward looking basis the expected credit losses associated with financial assets classified as measured at amortized cost at each balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is exposed to credit risk. Since this is typically less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group's in-scope financial assets. The measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit loss is estimated as the difference between the asset’s carrying amount and the present value of the future cash flows the group expects to receive discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain or loss recognized in the income statement. A financial asset or group of financial assets classified as measured at amortized cost is considered to be credit-impaired if there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due. Financial liabilities The measurement of financial liabilities depends on their classification, as follows: Financial liabilities measured at fair value through profit or loss Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category. Derivatives designated as hedging instruments in an effective hedge 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 directly attributable transaction costs. For interest-bearing loans and borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing. After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively. This category of financial liabilities includes trade and other payables and finance debt. Derivative financial instruments and hedging activities The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and commodity prices, as well as for trading purposes. These derivative financial instruments are recognized initially at fair value on the date on which a derivative contract is entered into and subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative. Contracts to buy or sell a non-financial item (for example, oil, oil products, gas or power) that can be settled net in cash, with the exception of contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the group’s expected purchase, sale or usage requirements, are accounted for as financial instruments. Gains or losses arising from changes in the fair value of derivatives that are not designated as effective hedging instruments are recognized in the income statement. If, at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation methodology is not recognized in the income statement but is deferred on the balance sheet and is commonly known as ‘day-one gain or loss’. This deferred gain or loss is recognized in the income statement over the life of the contract until substantially all the remaining contract term can be valued using observable market data at which point any remaining deferred gain or loss is recognized in the income statement. Changes in valuation subsequent to the initial valuation at inception of a contract are recognized immediately in the income statement. 140 BP Annual Report and Form 20-F 2018 1. Significant accounting policies, judgements, estimates and assumptions – continued For the purpose of hedge accounting, hedges are classified as: • Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability. • Cash flow hedges when hedging exposure to variability in cash flows that is attributable to either a particular risk associated with a recognized asset or liability or a highly probable forecast transaction. Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for undertaking the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the existence at inception of an economic relationship and subsequent measurement of the hedging instrument's effectiveness in offsetting the exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged risk, the hedge ratio and sources of hedge ineffectiveness. Hedges meeting the criteria for hedge accounting are accounted for as follows: Fair value hedges The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the risk being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss, where it offsets. The group applies fair value hedge accounting when hedging interest rate risk and certain currency risks on fixed rate finance debt. Fair value hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This includes when the risk management objective changes or when the hedging instrument is sold, terminated or exercised. The accumulated adjustment to the carrying amount of a hedged item at such time is then amortized prospectively to profit or loss as finance interest expense over the hedged item's remaining period to maturity. Cash flow hedges The effective portion of the gain or loss on a cash flow hedging instrument is reported in other comprehensive income, while the ineffective portion is recognized in profit or loss. Amounts reported in other comprehensive income are reclassified to the income statement when the hedged transaction affects profit or loss. Where the hedged item is a highly probably forecast transaction that results in the recognition of a non-financial asset or liability, such as a forecast foreign currency transaction for the purchase of property, plant and equipment, the amounts recognized within other comprehensive income are transferred to the initial carrying amount of the non-financial asset or liability. Where the hedged item is an equity investment, the amounts recognized in other comprehensive income remain in the separate component of equity until the hedged cash flows affect profit or loss. Where the hedged item is recognized directly in profit or loss, the amounts recognized in other comprehensive income are reclassified to production and manufacturing expenses. Cash flow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable to occur, or when the hedging instrument is sold, terminated or exercised without replacement or rollover. When cash flow hedge accounting is discontinued amounts previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to profit or loss or transferred to the initial carrying amount of a non-financial asset or liability as above. If the forecast transaction is no longer expected to occur, amounts previously recognized within other comprehensive income will be immediately reclassified to profit or loss. Costs of hedging Time value of options and the foreign currency basis spread of cross-currency interest rate swaps are excluded from hedge designations and accounted for as costs of hedging. Changes in fair value of the time-value component of option contracts and the foreign currency basis spread of cross-currency interest rate swaps are recognized in other comprehensive income to the extent that they relate to the hedged item. For transaction-related hedged items, the amount recognized in other comprehensive income is reclassified to profit or loss when the hedged transaction affects profit or loss. For time-period related hedged items, the amount recognized in other comprehensive income is amortized to profit or loss on a straight line over the term of the hedging relationship. Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The group categorizes assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed in their measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs that are observable, either directly or indirectly, other than quoted prices included within level 1 for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or BP’s assumptions about pricing by market participants. Significant judgement and estimate: derivative financial instruments In some cases the fair values of derivatives are estimated using internal models due to the absence of quoted prices or other observable, market-corroborated data. This 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 historical and long-term pricing relationships. Price volatility is also an input for options models. Changes in the key assumptions, in particular price curves, could have a material impact on the carrying amounts of derivative assets and liabilities in the next financial year. The impact on net assets and the Group income statement would be limited as a result of offsetting movements on derivative assets and liabilities. For more information see Note 30. In some cases, judgement is required to determine whether contracts to buy or sell commodities meet the definition of a derivative. In particular longer -term contracts to buy and sell LNG are not considered to meet the definition as they are not considered capable of being net settled due to a lack of liquidity in the LNG market and so are accounted for on an accruals basis. 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. BP Annual Report and Form 20-F 2018 141 1. Significant accounting policies, judgements, estimates and assumptions – continued Provisions and contingencies Provisions are recognized when the group has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk- free rate that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to the passage of time is recognized within finance costs. Provisions are discounted using a nominal discount rate of 3.0% (2017 2.5%). Provisions are split between amounts expected to be settled within 12 months of the balance sheet date (current) and amounts expected to be settled later (non-current). Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within the control of the group, or present obligations where it is not probable that an outflow of resources will be required or the amount of the obligation cannot be measured with sufficient reliability. Contingent liabilities are not recognized in the consolidated financial statements but are disclosed unless the possibility of an outflow of economic resources is considered remote. Decommissioning Liabilities for decommissioning costs are recognized when the group has an obligation to plug and abandon a well, dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Where an obligation exists for a new facility or item of plant, such as oil and natural gas production or transportation facilities, this liability will be recognized on construction or installation. Similarly, where an obligation exists for a well, this liability is recognized when it is drilled. An obligation for decommissioning may also crystallize during the period of operation of a well, facility or item of plant through a change in legislation or through a decision to terminate operations; an obligation may also arise in cases where an asset has been sold but the subsequent owner is no longer able to fulfil its decommissioning obligations, for example due to bankruptcy. The amount recognized is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. The provision for the costs of decommissioning wells, production facilities and pipelines at the end of their economic lives is estimated using existing technology, at future prices, depending on the expected timing of the activity, and discounted using the nominal discount rate. 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 where that asset is generating or is expected to generate future economic benefits. Environmental expenditures and liabilities Environmental expenditures that are required in order for the group to obtain future economic benefits from its assets are capitalized as part of those assets. Expenditures that relate to an existing condition caused by past operations that do not contribute to future earnings are expensed. Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Generally, the timing of recognition of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The amount recognized is the best estimate of the expenditure required to settle the obligation. Provisions for environmental liabilities have been estimated using existing technology, at future prices and discounted using a nominal discount rate. The weighted-average period over which these costs are generally expected to be incurred is estimated to be approximately six years. Significant judgements and estimates: provisions The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest decommissioning obligations facing BP relate to the plugging and abandonment of wells and the removal and disposal of oil and natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly changing, as are political, environmental, safety and public expectations. The timing and amounts of future cash flows are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognized. Any changes in the expected future costs are reflected in both the provision and the asset. If oil and natural gas production facilities and pipelines are sold to third parties, judgement is required to assess whether the new owner will be unable to meet their decommissioning obligations, whether BP would then be responsible for decommissioning, and if so the extent of that responsibility. 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 current estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology. The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually, together with the interest rate used in discounting the cash flows. The interest rate used to determine the balance sheet obligations at the end of 2018 was a nominal rate of 3.0% (2017 a real rate of 0.5% and a nominal rate of 2.5%), which was based on long-dated US government bonds. 142 BP Annual Report and Form 20-F 2018 1. Significant accounting policies, judgements, estimates and assumptions – continued Further information about the group’s provisions is provided in Note 21. Changes in assumptions in relation to the group's provisions could result in a material change in their carrying amounts within the next financial year. A 0.5% change in the nominal discount rate could have an impact of approximately $1.3 billion on the value of the group’s provisions, excluding those relating to the Gulf of Mexico oil spill. The impact on the group income statement would not be significant as the majority of the group’s provisions relate to decommissioning costs. As described in Note 33, the group is subject to claims and actions for which no provisions have been recognized. The facts and circumstances relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized or revised. Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the outcome of litigation is difficult to predict. Change in significant estimate - decommissioning provision Decommissioning provision cost estimates are reviewed regularly and such a review was undertaken in the second quarter of 2018. The timing and amount of estimated future expenditures were re-assessed and discounted to determine the present value. From 30 June 2018 the present value of the decommissioning provision is determined by discounting the estimated cash flows expressed in expected future prices, i.e. taking account of expected inflation, at a nominal discount rate of 2.5% as at 30 June 2018. Prior to 30 June 2018, the group estimated future cash flows in real terms i.e. at current prices and discounted them using a real discount rate of 0.5% as at 31 December 2017. The impact of the review was a reduction in the provision of $1.5 billion as at 30 June 2018, with a similar reduction in the carrying amount of property, plant and equipment. There was no significant impact on the income statement for the first half of 2018. The impact on the income statement for the second half of 2018 was a decrease in depreciation, depletion and amortization of approximately $80 million and an increase in finance costs of approximately $80 million. The nominal discount rate applied to provisions was revised at 31 December 2018 to 3.0%. The impact of this increase was a further $1.3- billion reduction in the decommissioning provision, with a similar reduction in the carrying amount of property, plant and equipment. 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, either by way of a refund from the plan or reductions in future contributions to the plan. Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable. BP Annual Report and Form 20-F 2018 143 1. Significant accounting policies, judgements, estimates and assumptions – continued Significant estimate: pensions and other post-retirement benefits Accounting for defined benefit pensions and other post-retirement benefits involves making significant estimates when measuring the group's pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties. Pensions and other post-retirement benefit assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group's balance sheet, and pension and other post-retirement benefit expense for the following year. The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate, salary growth and mortality levels. Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in material changes to the carrying amounts of the group's pension and other post-retirement benefit obligations within the next financial year, in particular for the UK, US and Eurozone plans. Any differences between these assumptions and the actual outcome will also affect future net income and net assets. The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and obligation used are provided in Note 24. Income taxes Income tax expense represents the sum of current tax and deferred tax. Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity. Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are taxable or deductible in other periods as well as items that are never taxable or deductible. The group’s liability for current tax is calculated using tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for all taxable temporary differences except: • Where the deferred tax liability arises on the initial recognition of goodwill. • Where the deferred tax liability arises on the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss. • In respect of taxable temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements, where the group is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred tax assets are recognized for deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits and unused tax losses can be utilized, except where the deferred tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss. In respect of deductible temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized. The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable or increased to the extent that it is probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and liabilities are not discounted. Deferred tax assets and liabilities are offset only when there is a legally enforceable right to set off current tax assets against current tax liabilities and when the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the current tax assets and liabilities on a net basis or to realize the assets and settle the liabilities simultaneously. Where tax treatments are uncertain, if it is considered probable that a taxation authority will accept the group's proposed tax treatment, income taxes are recognized consistent with the group's income tax filings. If it is not considered probable, the uncertainty is reflected using either the most likely amount or an expected value, depending on which method better predicts the resolution of the uncertainty. The computation of the group’s income tax expense and liability involves the interpretation of applicable tax laws and regulations in many jurisdictions throughout the world. The resolution of tax positions taken by the group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Therefore, judgement is required to determine whether provisions for income taxes are required and, if so, estimation is required of the amounts that could be payable. In addition, the group has carry-forward tax losses and tax credits in certain taxing jurisdictions that are available to offset against future taxable profit. However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused tax losses or tax credits can be utilized. Management judgement is exercised in assessing whether this is the case and estimates are required to be made of the amount of future taxable profits that will be available. Management do not assess there to be a significant risk of a material change to the group’s tax provisioning or recognition of deferred tax assets within the next financial year, however the tax position remains inherently uncertain and therefore subject to change. To the extent that actual outcomes differ from management’s estimates, income tax charges or credits, and changes in current and deferred tax assets or liabilities, may arise in future periods. For more information see Note 9 and Note 33. 144 BP Annual Report and Form 20-F 2018 1. Significant accounting policies, judgements, estimates and assumptions – continued Judgement is also required when determining whether a particular tax is an income tax or another type of tax (for example a production tax). Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes; rather such taxes are recognized in the income statement in accordance with the applicable accounting policy such as Provisions and contingencies. No new significant judgements were made in 2018 in this regard. Customs duties and sales taxes Customs duties and sales taxes that are passed on or charged to customers are excluded from revenues and expenses. Assets and liabilities are recognized net of the amount of customs duties or sales tax except: • Customs duties or sales taxes incurred on the purchase of goods and services which are not recoverable from the taxation authority are recognized as part of the cost of acquisition of the asset. • Receivables and payables are stated with the amount of customs duty or sales tax included. The net amount of sales tax recoverable from, or payable to, the taxation authority is included within receivables or payables in the balance sheet. Own equity instruments – treasury shares The group’s holdings in its own equity instruments are shown as deductions from shareholders’ equity 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 consolidated financial statements as treasury shares. Consideration, if any, received for the sale of such shares is also recognized in equity. No gain or loss is recognized in the income statement on the purchase, sale, issue or cancellation of equity shares. Shares repurchased under the share buy-back programme which are immediately cancelled are not shown as treasury shares, but are shown as a deduction from the profit and loss account reserve in the group statement of changes in equity. Revenue and other income Revenue from contracts with customers is recognized when or as the group satisfies a performance obligation by transferring control of a promised good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products, and other items usually coincides with title passing to the customer and the customer taking physical possession. The group principally satisfies its performance obligations at a point in time; the amounts of revenue recognized relating to performance obligations satisfied over time are not significant. When, or as, a performance obligation is satisfied, the group recognizes as revenue the amount of the transaction price that is allocated to that performance obligation. The transaction price is the amount of consideration to which the group expects to be entitled. The transaction price is allocated to the performance obligations in the contract based on standalone selling prices of the goods or services promised. Contracts for the sale of commodities are typically priced by reference to quoted prices. Revenue from term commodity contracts is recognized based on the contractual pricing provisions for each delivery. Certain of these contracts have pricing terms based on prices at a point in time after delivery has been made. Revenue from such contracts is initially recognized based on relevant prices at the time of delivery and subsequently adjusted as appropriate. Physical exchanges with counterparties in the same line of business in order to facilitate sales to customers are reported net, as are sales and purchases made with a common counterparty, as part of an arrangement similar to a physical exchange. Where the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is recognized but no purchase or sale is recorded. 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. Interest income is recognized as the interest accrues (using the effective interest rate, that is, the rate that exactly discounts estimated future cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset). Dividend income from investments is recognized when the shareholders’ right to receive the payment is established. 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. BP Annual Report and Form 20-F 2018 145 1. Significant accounting policies, judgements, estimates and assumptions – continued Impact of new International Financial Reporting Standards BP adopted two new accounting standards issued by the IASB with effect from 1 January 2018, IFRS 9 ‘Financial instruments’ and IFRS 15 ‘Revenue from contracts with customers’. There are no other new or amended standards or interpretations adopted during the year that have a significant impact on the consolidated financial statements. IFRS 9 ‘Financial Instruments’ IFRS 9 ‘Financial Instruments’ was issued in July 2014 and replaced IAS 39 ‘Financial Instruments: Recognition and Measurement.’ BP adopted IFRS 9 and the related consequential amendments to other IFRSs in the financial reporting period commencing 1 January 2018. The group has applied the new standard in accordance with the transition provisions of IFRS 9. Comparatives have not been restated and adjustments on transition have been reported in opening retained earnings at 1 January 2018. The group’s revised accounting policies in relation to financial instruments are provided above. The overall impact on transition to IFRS 9, including the impact upon the group's share of equity-accounted entities, was a reduction of $180 million in net assets, net of tax. This adjustment mainly related to an increase in the loss allowance for financial assets in the scope of IFRS 9's impairment requirements. As comparatives have not been restated the closing balance at 31 December 2017 for certain line items in the balance sheet differ from the opening balance at 1 January 2018 (as summarized below). Cash and cash equivalents at the beginning of 2018 in the Group cash flow statement are the 1 January 2018 amounts included in the table below. Non-current Investments in equity-accounted entities Loans, trade and other receivables Deferred tax liabilities Current Loans, trade and other receivables Cash and cash equivalents Net assets Reserves Available-for-sale investments Costs of hedging Profit and loss account 31 December 2017 1 January 2018 $ million Adjustment on adoption of IFRS 9 24,985 2,080 (7,982) 25,039 25,586 24,903 2,069 (7,946) 24,927 25,575 100,404 100,224 17 — 75,226 75,243 — (37) 75,100 75,063 (82) (11) 36 (112) (11) (180) (17) (37) (126) (180) Classification and measurement IFRS 9 provides a single classification and measurement approach for financial assets that reflects the business model in which they are managed and their cash flow characteristics. For financial liabilities the existing classification and measurement requirements of IAS 39 are largely retained. The table below illustrates the classification and carrying amounts of financial assets under IFRS 9 and IAS 39 at the date of initial application, 1 January 2018. There were no differences in classification or carrying amounts for financial liabilities and no differences in the measurement of liabilities for financial guarantee contracts. At 1 January 2018 Financial assets Other investments – equity shares  – other  – other Loans Loans Trade and other receivables Derivative financial instruments Derivative financial instruments Cash and cash equivalents Cash and cash equivalents Cash and cash equivalents Cash and cash equivalents Classification under IAS 39 Classification under IFRS 9 Available-for-sale financial assets Available-for-sale financial assets At fair value through profit or loss Loans and receivables Amortized cost Loans and receivables Fair value through Fair value through profit or loss Fair value through profit or loss Fair value through profit or loss profit or loss Fair value through profit or loss Derivative hedging instruments Loans and receivables Amortized cost At fair value through profit or loss Derivative hedging instruments Loans and receivables Amortized cost Available-for-sale financial assets Available-for-sale financial assets Held-to-maturity investments Fair value through profit or loss Amortized cost Amortized cost 146 BP Annual Report and Form 20-F 2018 Carrying amount under IAS 39 Measurement category adjustment on transition Measurement attribute adjustment on transition $ million Carrying amount under IFRS 9 433 275 662 836 — 24,361 6,454 688 21,916 — — — (100) 100 — — — — 2,270 (2,058) — 2,058 1,400 59,295 — — — — — — (8) 433 275 662 736 92 (115) 24,246 — — 6,454 688 (11) 21,905 — — — 212 2,058 1,400 (134) 59,161 1. Significant accounting policies, judgements, estimates and assumptions – continued Other investments existing on transition that were classified as available-for-sale financial assets under IAS 39 are classified as mandatorily measured at fair value through profit or loss (FVTPL) under IFRS 9. The contractual terms of these assets do not give rise to cash flows that are solely payments of principal and interest. Fair value gains and losses will be recognized in profit or loss rather than in other comprehensive income as was the case under IAS 39. An adjustment to the 2018 opening balance sheet was made to transfer $17 million of fair value gains net of related tax from the available-for-sale investments reserve to the profit and loss account reserve. Certain loans that were classified as loans and receivables under IAS 39 have been classified as mandatorily measured at FVTPL under IFRS 9 as a result of the business model in which they are held. The adjustment of $8m to the carrying amount of these assets on transition reflects the difference between amortized cost measurement under IAS 39 and fair value measurement under IFRS 9. Cash and cash equivalents that were classified as available-for-sale and held-to-maturity financial assets under IAS 39 have been classified as either measured at amortized cost or measured at FVTPL under IFRS 9. Cash and cash equivalents measured at FVTPL comprise money market funds that do not give rise to cash flows that are solely payments of principal and interest. For cash and cash equivalents that have been reclassified to measured at amortized cost, the carrying amount of those assets at the end of the reporting period approximate their fair value. The fair value gain or loss that would have been recognized in other comprehensive income in the reporting period if those financial assets had not been reclassified to amortized cost is immaterial. Adjustments to the carrying amount of financial assets classified as measured at amortized cost under IFRS 9 relate entirely to the additional loss allowance required by the new standard's expected credit loss model. There were no financial assets or financial liabilities which the group had previously designated as at FVTPL under IAS 39 that were required to be reclassified, or which the group has elected to reclassify upon the application of IFRS 9. The group did not elect to designate at FVTPL any financial assets or financial liabilities at the date of initial application of IFRS 9. Under IFRS 9 the group has elected to apply hedge accounting prospectively to certain of its commodity price risk management activities for which hedge accounting was not possible under IAS 39. Certain derivatives that were previously classified as at FVTPL have therefore been reclassified to derivative hedging instruments at 1 January 2018. As the hedging instruments are exchange traded derivatives, the value transferred on transition was nil. Impairment The financial asset impairment requirements of IFRS 9 introduce a forward-looking expected credit loss model that results in earlier recognition of credit losses than the incurred loss model of IAS 39. The adjustment to the 2018 opening balance sheet relating to expected credit loss reduced both the carrying amounts of financial assets and the profit and loss account reserve. The table below reconciles the ending impairment allowances in accordance with IAS 39 and the provisions in accordance with IAS 37 to the opening loss allowances determined in accordance with IFRS 9. Classification under IAS 39 Classification under IFRS 9 Available-for-sale financial assets Loans and receivables Amortized cost Loans and receivables Amortized cost Fair value through profit or loss At 1 January 2018 Financial assets Other investments – equity shares Trade and other receivables Cash and cash equivalents Total loss allowance on financial assets Loans that form part of the net investment in equity-accounted entities Total loss allowance Measurement category effect on transition Measurement attribute adjustment on transition IAS 39 loss allowance $ million IFRS 9 loss allowance 91 335 — 426 37 463 (91) — — (91) — (91) — 115 11 126 6 132 — 450 11 461 43 504 Impairment allowances on available-for-sale assets represent amounts provided against investments in equity instruments that were held at cost under IAS 39. Under IFRS 9 these assets are classified as measured at fair value through profit or loss and therefore no loss allowance exists on these assets under IFRS 9. The increase in the loss allowances for financial assets classified as measured at amortized cost under IFRS 9 and loans that form part of the net investment in equity-accounted entities represent the additional loss allowance required by the new standard's expected credit loss model. Hedge accounting Under IFRS 9 all existing hedging relationships qualified as continuing hedging relationships and the group has applied hedge accounting prospectively to certain of its commodity price risk management activities for which hedge accounting was not possible under IAS 39. BP Annual Report and Form 20-F 2018 147 1. Significant accounting policies, judgements, estimates and assumptions – continued IFRS 9 also introduces a new way of treating fair value movements on the time value and foreign currency basis spreads of certain hedging instruments. Whereas under IAS 39 these movements were recognized in profit or loss, the group is either required, or has elected to initially recognize these movements within equity to the extent that they relate to the hedged item. An adjustment to the 2018 opening balance sheet was made to transfer $37 million of losses net of related tax from the profit and loss account reserve to the costs of hedging reserve for relevant hedging instruments existing on transition. Under IAS 39 the effective portion of the gain or loss on a cash flow hedging instrument is reported in other comprehensive income and is reclassified to the balance sheet as part of the initial carrying amount of the corresponding non-financial asset or liability. Under IFRS 9 the effective portion of the gain or loss continues to be reported in the statement of other comprehensive income but the transfer to the balance sheet is shown in the statement of changes in equity. IFRS 15 ‘Revenue from Contracts with Customers’ IFRS 15 ‘Revenue from Contracts with Customers’ was issued in May 2014 and replaced IAS 18 ‘Revenue’ and certain other standards and interpretations. IFRS 15 provides a single model for accounting for revenue arising from contracts with customers, focusing on the identification and satisfaction of performance obligations. BP adopted IFRS 15 from 1 January 2018 and applied the ‘modified retrospective’ transition approach to implementation. The group’s revised accounting policy in relation to revenue is provided above. A disaggregation of revenue from contracts with customers is provided in note 5. The group identified certain minor changes in accounting relating to its revenue from contracts with customers but the new standard had no material effect on the group’s net assets as at 1 January 2018 and so no transition adjustment is presented. The most significant change identified is the accounting for revenues relating to oil and natural gas properties in which the group has an interest with joint operation partners. From 1 January 2018, BP ceased using the entitlement method of accounting under which revenue was recognized in relation to the group's entitlement to the production from oil and gas properties based on its working interest, irrespective of whether the production was taken and sold to customers. In its 2018 consolidated financial statements the group has recognized revenue when sales are made to customers; production costs have been accrued or deferred to reflect differences between volumes taken and sold to customers and the group's ownership interest in total production volumes. Compared to the group’s previous accounting policy this may result in timing differences in respect of revenues and profits recognized in each period, but there will be no change in the total revenues and profits over the duration of the joint operation. The impact on the consolidated financial statements for the year ended 31 December 2018 was not material. In addition, BP has made determinations about presentation and disclosure relating to its revenue from contracts with customers as follows: Derivative contracts resulting in physical delivery to a customer Certain contracts entered into by the group that result in physical delivery to a counterparty of products such as crude oil, natural gas and refined products are required by IFRS to be accounted for as financial instruments. These contracts are within the scope of IFRS 9 rather than IFRS 15. The group’s counterparties in these transactions, however, may meet the IFRS 15 definition of a customer. Revenue recognized relating to such contracts when physical delivery occurs is, therefore, presented together with revenue from contracts with customers in the group’s consolidated financial statements. Changes in the fair value of derivative assets and liabilities prior to physical delivery are excluded from revenue from contracts with customers and are presented as other operating revenues. Additionally, where forward sales and purchase contracts for oil, natural gas or power have been determined to be for short-term trading purposes, the associated sales and purchases continue to be reported net within other operating revenues consistent with the group’s practice prior to implementation of IFRS 15. Contracts with post-delivery pricing terms Contracts entered into by the group for the sale of oil, natural gas (including LNG), NGLs and refined products are typically priced by reference to quoted prices. In line with market practice, certain of these contracts are based on average prices over a period that is partially or entirely after delivery. Revenue relating to such contracts is recognized initially based on relevant prices at the time of delivery and subsequently adjusted as prices are finalized, consistent with the group’s practice prior to implementation of IFRS 15. Whilst these post-delivery adjustments are changes in the value of receivables within the scope of IFRS 9, not IFRS 15, the distinction between revenue recognized at the time of delivery and revenue recognized as a result of post-delivery changes in quoted commodity prices relating to the same transaction is not considered to be significant. All revenue from these contracts, both that recognized at the time of delivery and that from post-delivery price adjustments, is disclosed as revenue from contracts with customers. Disclosure of the amount of the transaction price allocated to unsatisfied performance obligations The disclosures required by IFRS 15 include the amount of the contract transaction price allocated to performance obligations that are unsatisfied at the balance sheet date. Many of BP’s commodity sales are made under term contracts in which sales are made based on quoted prices at or near the time of delivery, meaning the consideration for future deliveries is entirely variable. In these arrangements, each delivery is considered to be a separate performance obligation and the transaction price is the amount of revenue expected to be earned from all sales that are contracted to be made in future periods, which can be up to 20 years from the balance sheet date. BP does not consider the disclosure of the amount of the transaction price allocated to contracted future deliveries of commodities within the scope of IFRS 15 to be relevant information. This disclosure has not, therefore, been provided in these consolidated financial statements. The consideration in many such contracts is entirely variable so would be subject to the requirement of IFRS 15 relating to constraining estimates of variable consideration. Applying the constraint for the purposes of this disclosure requirement would provide an indication only of contracted revenues based on estimated future minimum market prices. Such commodities are regularly sold in liquid markets on a spot basis, using similar pricing bases to sales made under term contracts, meaning that disclosure of contracted sales would have little predictive value. Furthermore, as described above, a significant proportion of the group’s commodity sales contracts are within the scope of IFRS 9, not IFRS 15. Derivative assets or liabilities representing the difference between contracted price and forward price are recognized on the group balance sheet for these contracts. Contract assets and liabilities The group does not have material contract asset or contract liability balances and so these amounts are included within amounts presented for trade receivables and other payables. 148 BP Annual Report and Form 20-F 2018 1. Significant accounting policies, judgements, estimates and assumptions – continued Not yet adopted The IASB has issued IFRS 16 'Leases' which will become effective from financial reporting periods beginning on or after 1 January 2019 and has been adopted by the EU. The group has not adopted IFRS 16 in these consolidated financial statements and will adopt it from 1 January 2019. 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. IFRS 16 ‘Leases’ IFRS 16 ‘Leases’ provides a new model for lessee accounting in which the majority of leases will be accounted for by the recognition on the balance sheet of a right-of-use asset and a lease liability. The subsequent amortization of the right-of-use asset and the interest expense related to the lease liability will be recognized in profit or loss over the lease term. IFRS 16 replaces IAS 17 ‘Leases’ and IFRIC 4 ‘Determining whether an arrangement contains a lease’ and will be effective for financial reporting periods beginning on or after 1 January 2019. BP will adopt IFRS 16 in the financial reporting period commencing 1 January 2019 and has elected to apply the modified retrospective transition approach in which the cumulative effect of initial application is recognized in opening retained earnings at the date of initial application with no restatement of comparative periods’ financial information. IFRS 16 introduces a revised definition of a lease. As permitted by the standard, BP has elected not to reassess the existing population of leases under the new definition and will only apply the new definition for the assessment of contracts entered into after the transition date. On transition the standard permits, on a lease-by-lease basis, the right-of-use asset to be measured either at an amount equal to the lease liability (as adjusted for prepaid or accrued lease payments), or on an historical basis as if the standard had always applied. BP has elected to use the historical asset measurement for its more material leases and to use the asset equals liability approach for the remainder of the population. In addition, BP has also elected the option to adjust the carrying amounts of the right-of-use assets as at 1 January 2019 for onerous lease provisions that had been recognized on the group balance sheet as at 31 December 2018, rather than the alternative of performing impairment tests on transition. The group’s evaluation of the effect of adoption of the standard is substantially complete and a material effect on the group’s balance sheet is expected, as set out further below. 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-of-use asset and interest on the lease liability. In the cash flow statement operating lease payments are currently presented within cash flows from operating activities but under IFRS 16 payments will be presented as financing cash flows, representing repayments of debt, and as operating cash flows, representing payments of interest. Variable lease payments that do not depend on an index or rate are not included in the lease liability and will continue to be presented as operating cash flows. Information on the group’s leases classified as operating leases under IAS 17, which are not recognized on the balance sheet as at 31 December 2018, is presented in Note 28. The following table provides a reconciliation of the operating lease commitments disclosed in Note 28 to the total lease liability expected to be recognized on the group balance sheet in accordance with IFRS 16 as at 1 January 2019, with explanations below. Operating lease commitments at 31 December 2018 Leases not yet commenced Leases below materiality threshold Short-term leases Effect of discounting Impact on leases in joint operations Variable lease payments Redetermination of lease term Other Total additional lease liabilities expected to be recognized on adoption of IFRS 16 Finance lease obligations at 31 December 2018 Adjustment for finance leases in joint operations Total expected lease liabilities at 1 January 2019 $ million 11,979 (1,372) (86) (91) (1,512) 836 (58) (252) (22) 9,422 667 (189) 9,900 Leases not yet commenced: The operating lease commitments disclosed in Note 28 include amounts relating to leases entered into by the group that had not yet commenced as at 31 December 2018. In accordance with IFRS 16 assets and liabilities will not be recognized on the group balance sheet in relation to these leases until the dates of commencement of the leases. Such commitments will continue to be disclosed in future under IFRS 16. Short-term leases and leases below materiality threshold: As part of the transition to IFRS 16, BP has elected not to recognize assets and liabilities relating to short-term leases i.e. leases with a term of less than 12 months and has also applied a materiality threshold for the recognition of assets and liabilities related to leases. The disclosed operating lease commitments as at 31 December 2018 in Note 28 includes amounts related to such leases. Effect of discounting: The amount of the lease liability recognized in accordance with IFRS 16 will be on a discounted basis whereas the operating lease commitments information in Note 28 is presented on an undiscounted basis. The discount rates used on transition are incremental borrowing rates as appropriate for each lease based on factors such as the lessee legal entity, lease term and currency. The weighted average discount rate to be used on transition is expected to be around 3.5%, with a weighted average remaining lease term of around 9 years. For new leases commencing after 1 January 2019 the discount rate used will be the interest rate implicit in the lease, if this is readily determinable, or the incremental borrowing rate if the implicit rate cannot be readily determined. BP Annual Report and Form 20-F 2018 149 1. Significant accounting policies, judgements, estimates and assumptions – continued Impact on leases in joint operations: The operating lease commitments for leases within joint operations are included on the basis of BP’s net working interest for the information provided in Note 28, irrespective of whether BP is the operator and whether the lease has been co-signed by the joint operators or not. However, for transition to IFRS 16, the facts and circumstances of each lease in a joint operation have been assessed to determine the group’s rights and obligations and to recognize assets and liabilities on the group balance sheet accordingly. This relates mainly to leases of drilling rigs within joint operations in the Upstream segment. Where all parties to a joint operation jointly have the right to control the use of the identified asset and all parties have a legal obligation to make lease payments to the lessor, the group’s share of the right-of-use asset and its share of the lease liability will be recognized on the group balance sheet. This may arise in cases where the lease is signed by all parties to the joint operation. However, in cases where BP is the only party with the legal obligation to make lease payments to the lessor, the full lease liability will be recognized on the group balance sheet. This may be the case if for example BP, as operator of the joint operation, is the sole signatory to the lease. If, however, the underlying asset is jointly controlled by all parties to the joint operation BP will recognize its net share of the right-of-use asset on the group balance sheet along with a receivable representing the amounts to be recovered from the other parties. If BP is not legally obliged to make lease payments to the lessor but jointly controls the asset, the net share of the right- of-use asset will be recognized on the group balance sheet along with a payable representing amounts to be paid to the other parties. Variable lease payments: Where there are lease payments that vary depending on an index or rate, the measurement of the operating lease commitments in Note 28 is based on the variable factor as at inception of the lease and is not updated to reflect subsequent changes in the variable factor. Such subsequent changes in the lease payments are currently treated as contingent rentals and charged to profit or loss as and when paid. Under IFRS 16 the lease liability will be adjusted whenever the lease payments are changed in response to changes in the variable factor, and for transition the liability is measured on the basis of the prevailing variable factor on 1 January 2019. Redetermination of lease term: Under the transition provisions of IFRS 16, the remaining terms of certain leases have been redetermined with the benefit of hindsight, on the basis that BP is now reasonably certain to exercise its option to terminate those leases before the full term. Under IAS 17 finance leases are recognized on the group balance sheet and will continue to be recognized in accordance with IFRS 16. The amounts recognized on the group balance sheet as at 1 January 2019 in relation to the right-of-use assets and liabilities for existing finance leases within joint operations will be on a net or gross basis as appropriate as described above. In addition to the lease liability, which will be presented within finance debt, other line items on the group balance sheet expected to be adjusted on transition to IFRS 16 include property, plant and equipment, prepayments, receivables, accruals, payables, provisions and deferred tax balances, as set out below. 31 December 2018 1 January 2019 $ million Adjustment on adoption of IFRS 16 Non-current assets Property, plant and equipment Trade and other receivables Prepayments Deferred tax assets Current assets Trade and other receivables Prepayments Current liabilities Trade and other payables Accruals Finance debt and leases Provisions Non-current liabilities Other payables Accruals Finance debt and leases Deferred tax liabilities Provisions Net assets Equity BP shareholders' equity Non-controlling interests 135,261 1,834 1,179 3,706 24,478 963 46,265 4,626 9,373 2,564 13,830 575 56,426 9,812 17,732 143,950 2,159 849 3,736 24,673 872 46,209 4,578 11,525 2,547 14,013 548 63,507 9,767 17,657 101,548 101,218 99,444 2,104 101,548 99,115 2,103 101,218 The total expected adjustments to the group's lease liabilities at 1 January 2019 may be reconciled as follows: Total additional lease liabilities expected to be recognized on adoption of IFRS 16 Less: adjustment for finance leases in joint operations Total expected adjustment to lease liabilities Of which – current – non-current 150 BP Annual Report and Form 20-F 2018 8,689 325 (330) 30 195 (91) (56) (48) 2,152 (17) 183 (27) 7,081 (45) (75) (330) (329) (1) (330) $ million 9,422 (189) 9,233 2,152 7,081 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. 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 Provisions Net current assets (liabilities) Non-current assets Deferred tax Non-current liabilities Other payables 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 2018 2017 714 (714) 479 (1,193) 174 (1,019) 2,687 (2,687) 493 (3,180) (2,222) (5,402) 214 252 (2,279) (333) (2,398) (2,089) (1,439) (3,276) 1,563 2,067 (11,922) (12) 3,999 (6,372) (8,770) (1,193) 479 240 (485) (2,572) (3,531) (12,253) (1,141) 3,634 (7,693) (10,969) (3,180) 493 2,542 (1,738) (3,453) (5,336) $ million 2016 6,640 (6,640) 494 (7,134) 3,105 (4,029) (7,134) 494 4,353 (3,210) (1,608) (7,105) Income statement The group income statement for 2018 includes a pre-tax charge of $1,193 million (2017 pre-tax charge of $3,180 million, 2016 pre-tax charge of $7,134 million) in relation to the Gulf of Mexico oil spill. The charge within production and manufacturing expenses in 2018 of $714 million (2017 $2,687 million, 2016 $6,640 million) relates mainly to business economic loss (BEL) and other claims associated with the Deepwater Horizon Court Supervised Settlement Program (DHCSSP). Finance costs of $479 million (2017 $493 million, 2016 $494 million) reflect the unwinding of the discount on payables and, for 2016, 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 2012 agreement with the US government to resolve all federal criminal claims arising from the incident, amounts charged for the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states 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 cumulative pre-tax income statement charge since the incident amounts to $67.0 billion and is analysed in the table below. 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 2018 — — 629 — 85 — 714 479 1,193 2017 — — 2,647 — 40 — 2,687 493 3,180 $ million Cumulative since the incident 8,526 14,304 42,410 4,061 1,394 (5,681) 65,014 1,944 66,958 2016 — — 6,596 — 44 — 6,640 494 7,134 BP Annual Report and Form 20-F 2018 151 2. Significant event – Gulf of Mexico oil spill – continued Provisions and contingent liabilities Provisions Movements during the year in the remaining provision, which relates to litigation and claims, are presented in the table below. At 1 January Increase in provision Reclassified to other payables Utilization At 31 December Of which – current – non-current $ million 2018 Litigation and claims 2,580 629 (2,045) (819) 345 333 12 Litigation and claims – PSC settlement The Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) with the Plaintiffs' Steering Committee (PSC) provides for a court-supervised settlement programme, the DHCSSP, which commenced operation on 4 June 2012. A separate claims administrator was appointed to pay medical claims and to implement other aspects of the Medical Benefits Class Action Settlement. For further information on the PSC settlements, see Legal proceedings on page 296. The litigation and claims provision reflects the latest estimate for the remaining costs associated with the PSC settlement. These costs relate predominantly to BEL claims and associated administration costs. The amounts ultimately payable may differ from the amount provided and the timing of payments is uncertain. The DHCSSP’s determination of BEL claims was substantially completed by the end of 2017 and remaining claims continued to be processed throughout 2018 with only a very small number of claims remaining to be determined by the end of 2018. However certain BEL claims determined by the DHCSSP have been and continue to be appealed by BP and/or the claimants. During 2018 settlement agreements were reached with claimants for a significant proportion of the provision existing at the beginning of the year. Amounts payable under these settlement agreements have been reclassified from provisions to other payables. The remaining amount provided for includes the latest estimate of the amounts that are expected ultimately to be paid to resolve outstanding BEL claims. Claims under appeal will ultimately only be resolved once the full judicial appeals process has been concluded, including appeals to the Federal District Court and Fifth Circuit, as may be the case, or when settlements are reached with individual claimants. Depending upon the ultimate resolution of these claims, the amounts payable may differ from those currently provided. Payments to resolve outstanding claims under the PSC settlement are expected to be made over a number of years. The timing of payments, however, is uncertain, and, in particular, will be impacted by how long it takes to resolve claims that have been appealed and may be appealed in the future. Contingent liabilities For information on legal proceedings relating to the Deepwater Horizon oil spill, see Legal proceedings on pages 296-298. Any further outstanding Deepwater Horizon related claims are not expected to have a material impact on the group's financial performance. Other payables Other payables include amounts payable under the 2016 consent decree and settlement agreement with the United States and five Gulf coast states, including amounts payable for natural resource damages, state claims and Clean Water Act penalties. On a discounted basis the amounts included in other payables for these elements of the agreements are $5,485 million payable over 14 years, $2,897 million payable over 15 years and $4,010 million payable over 14 years respectively at 31 December 2018. For full details of these agreements, see BP Annual Report and Form 20-F 2015. In addition, other payables at 31 December 2018 also includes amounts payable for settled economic loss and property damage claims which are payable over a period of up to nine years. Cash flow statement The impact on net cash provided by operating activities on a pre-tax basis amounted to an outflow of $3,531 million (2017 outflow of $5,336 million, 2016 outflow of $7,105 million). On a post-tax basis, the amounts were an outflow of $3,218 million (2017 outflow of $5,167 million and 2016 outflow of $6,892 million). Cash outflows in 2018, 2017 and 2016 include payments made under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident and the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states. 152 BP Annual Report and Form 20-F 2018 3. Business combinations and other significant transactions Business combinations BP undertook a number of business combinations in 2018. For the full year, total consideration paid in cash amounted to $7,100 million, offset by cash acquired of $114 million. On 31 October 2018, BP acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation, a wholly owned subsidiary of BHP that holds a portfolio of unconventional onshore US oil and gas assets. The acquisition brings BP extensive oil and gas production and resources in the liquids-rich regions of the Permian and Eagle Ford basins in Texas and in the Haynesville gas basin in Texas and Louisiana. The total consideration for the transaction, after customary closing adjustments and the effect of discounting deferred payments, is $10,302 million, which will all be paid in cash. As at 31 December 2018, $6,788 million of the consideration had been paid. The remaining discounted amount of $3,514 million is included within other payables on the group balance sheet and will be paid in four instalments, with the final instalment being paid in April 2019. The transaction has been accounted for as a business combination using the acquisition method. The provisional fair values of the identifiable assets and liabilities acquired, as at the date of acquisition, are shown in the table below. No goodwill has been recognized on the acquisition. Assets Property, plant and equipment Intangible assets Inventories Trade and other receivables Cash Liabilities Trade and other payables Provisions Non-controlling interest Total consideration $ million 2018 10,845 21 27 493 104 (659) (323) (206) 10,302 The acquisition-date fair values of the assets and liabilities acquired are provisional. As we gain further understanding of the acquired properties and development options, these fair values may be adjusted. An analysis of the cash flows relating to the acquisition included within the cash flow statement for 2018 is provided below. Transaction costs of the acquisition (included in cash flows from operating activities) Interest on deferred payments (included in cash flows from operating activities) Cash consideration paid, net of cash acquired (included in cash flows from investing activities) Total net cash outflow for the acquisition $ million 2018 62 21 6,684 6,767 From the date of acquisition to 31 December 2018, the acquired activities generated revenues of $472 million and profit before tax of $49 million. If the business combination had taken place on 1 January 2018, it is estimated that the acquired activities would have generated revenues of $2,798 million and profit before tax of $431 million. In addition to the BHP transaction described above, BP undertook a number of other individually insignificant business combinations in 2018. Other significant transactions On 18 December 2018, BP purchased an additional 16.5% interest in the Clair field in the North Sea, as part of the agreements with ConocoPhillips in which ConocoPhillips simultaneously purchased BP's entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska. The purchase gives BP a 45.1% interest in Clair in total. Gross payments made and received of $1,739 million and $1,490 million are included in Capital expenditure and Proceeds from disposals of businesses, net of cash acquired, respectively, in the group cash flow statement. Goodwill of $804 million, resulting from the recognition of a deferred tax liability as part of the transaction accounting, has been recognized on the purchase of the interest in the Clair field. BP Annual Report and Form 20-F 2018 153 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 Other businesses and corporate 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 2018 437 15 4 456 2017 526 674 10 1,210 2018 2017 707 59 11 777 400 12 254 666 (580) (2) (1) (583) 860 2018 940 1,911 2,851 2,145 120 586 2,851 127 88 — 215 1,138 69 32 1,239 (176) (62) — (238) 1,216 2017 2,936 478 3,414 1,183 2,078 153 3,414 $ million 2016 557 561 14 1,132 $ million 2016 169 89 3 261 1,022 84 11 1,117 (3,025) (17) — (3,042) (1,664) $ million 2016 1,372 1,259 2,631 839 1,646 146 2,631 At 31 December 2018, deferred consideration relating to disposals amounted to $35 million receivable within one year (2017 $259 million and 2016 $255 million) and $304 million receivable after one year (2017 $268 million and 2016 $271 million). In addition, contingent consideration receivable relating to disposals amounted to $893 million at 31 December 2018 (2017 $237 million and 2016 $131 million). These amounts of contingent consideration are reported within Other investments on the group balance sheet - see Note 18 for further information. Upstream In 2018, gains principally resulted from the disposal of interests in the Bruce, Keith and Rhum fields in the UK North Sea, from the disposal of certain properties in the US, and from adjustments to disposals in prior periods. Losses included $335 million resulting from the disposal of our interest in the Magnus field and associated assets in the UK North Sea, $221 million from the disposal of our interest in the Greater Kuparuk Area in the US (see Note 3 for further information), and adjustments to disposals in prior periods. In 2017, gains principally resulted from the disposal of a portion of our interest in the Perdido offshore hub in the US, and further gains associated with disposals in the UK. 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. Downstream In 2017, gains principally resulted from the disposal of our interest in the SECCO joint venture and the disposal of certain midstream assets in Europe. 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. Other businesses and corporate In 2018 proceeds from disposals were principally in respect of life insurance policies in the US and wind farms within our US wind business. 154 BP Annual Report and Form 20-F 2018 4. Disposals and impairment – continued Summarized financial information relating to the sale of businesses is shown in the table below. The principal transaction categorized as a business disposal in 2018 was the disposal of our interest in the Greater Kuparuk Area in the US - see Note 3 for further information. The principal transaction categorized as a business disposal in 2017 was the disposal of our interest in the Forties Pipeline System in the North Sea. 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. 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 (losses) on sale of businessesb Total consideration Non-cash considerationc Consideration received (receivable) Proceeds from the sale of businesses, net of cash disposedd 2018 3,274 173 (250) (97) 3,100 — 3 3,103 (221) 2,882 (282) (689) 1,911 2017 735 57 (173) (86) 533 — 3 536 44 580 (216) 114 478 $ million 2016 4,794 1,202 (2,558) (532) 2,906 25 229 3,160 593 3,753 (2,698) 204 1,259 a 2016 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 2016 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 Proceeds are stated net of cash and cash equivalents disposed of $15 million (2017 $25 million and 2016 $676 million). Impairments Impairment losses and impairment reversals in each segment are described below. For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment, intangibles and goodwill within Note 1. See also Note 12, Note 15 and Note 21 for further information on impairments by asset category. Upstream Impairment losses and reversals related primarily to producing and midstream assets. The 2018 impairment losses of $400 million related to a number of different assets, with the most significant charges arising in Australia and the US. Impairment losses arose primarily as a result of changes to project activity, asset obsolescence and the decision to dispose of certain assets. The 2018 impairment reversals of $580 million related to a number of different assets, with the most significant reversals arising in the North Sea and Angola following a change to decommissioning cost estimates. The 2017 impairment losses of $1,138 million related to a number of different assets, with the most significant charges arising in BPX Energy (previously known as the US Lower 48 business) and the North Sea. Impairment losses within Upstream arose primarily as a result of changes in reserves estimates and the decision to dispose of certain assets, including the Forties Pipeline System business. The 2017 impairment reversals of $176 million related to a number of different assets, with the most significant reversals arising in the North Sea. 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. 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 8). 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. Downstream Impairment losses totalling $12 million, $69 million, and $84 million were recognized in 2018, 2017 and 2016 respectively. Other businesses and corporate Impairment losses totalling $254 million, $32 million, and $11 million were recognized in 2018, 2017 and 2016 respectively. The amount for 2018 is in respect of assets within our US wind business in advance of their disposal in December 2018. BP Annual Report and Form 20-F 2018 155 5. Segmental analysis The group’s organizational structure reflects the various activities in which BP is engaged. At 31 December 2018, BP had three reportable segments: Upstream, Downstream and Rosneft. Upstream’s activities include oil and natural gas exploration, field development and production; midstream transportation, storage and processing; and the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs). Downstream’s activities include the refining, manufacturing, marketing, transportation, and supply and trading of crude oil, petroleum, petrochemicals products and related services to wholesale and retail customers. BP’s interest in Rosneft is accounted for using the equity method and is reported as a separate operating segment, reflecting the way in which the investment is managed. Other businesses and corporate comprises the biofuels and wind businesses, the group’s shipping and treasury functions, and corporate activities worldwide. The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. However, IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for the purposes of performance assessment and resource allocation. For BP, this measure of profit or loss is replacement cost profit or loss before interest and tax which reflects the replacement cost of supplies by excluding from profit or loss 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. 156 BP Annual Report and Form 20-F 2018   — 298,756 3,753 20,179 (801) 19,378 (2,528) (127) 16,723 5,170 10,287 2,746 26,320 14,640 $ million 2017 Total group 5. Segmental analysis – continued By business Upstream Downstream Rosneft Other businesses and corporate Consolidation adjustment and eliminations $ million 2018 Total group 1,678 (30,010) 298,756 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 56,399 270,689 (28,565) (574) 27,834 270,115 — — — 951 589 2,283 14,328 (6) 14,322 6,940 (862) 6,078 2,221 67 2,288 (871) 807 (70) (3,521) — (3,521) 30,010 — — 211 — 211 4,211 8,907 355 12,785 11,533 900 1,177 834 2,772 2,862 — — — 10,074 — 59 203 1,557 689 245 — — — — — a See explanation of inventory holding gains and losses on page 156. b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates. By business Upstream Downstream Rosneft Other businesses and corporate Consolidation adjustment and eliminations 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 45,440 219,853 (24,179) (1,800) 21,261 218,053 — — — 930 674 922 5,221 8 5,229 7,221 758 7,979 836 87 923 4,631 8,637 220 12,093 14,500 875 1,141 304 2,349 2,677 — — — 10,059 — 1,469 (26,554) 240,208 (575) 894 (19) (4,445) — (4,445) 65 235 2,902 484 275 26,554 — — — 240,208 2,507 (212) — (212) — — — — — 8,621 853 9,474 (2,074) (220) 7,180 5,571 10,013 3,426 24,985 17,452 a See explanation of inventory holding gains and losses on page 156. b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates. BP Annual Report and Form 20-F 2018 157 5. Segmental analysis – continued By business Upstream Downstream Rosneft 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 a See explanation of inventory holding gains and losses on page 156. By geographical area Revenues Third party sales and other operating revenuesa Other income statement items Production and similar taxes Results Replacement cost profit (loss) before interest and taxation Non-current assets Non-current assetsb c Other businesses and corporate Consolidation adjustment and eliminations $ million 2016 Total group 1,667 (19,530) 183,008 (658) 1,009 (18) (8,157) — (8,157) 19,530 — — — 183,008 1,960 (196) — (196) 33,188 167,683 (17,581) (1,291) 15,607 166,392 — — — 723 608 647 574 60 634 5,162 1,484 6,646 590 53 643 4,396 7,835 352 856 1,094 758 — — — 71 253 6,719 — — — US Non-US 98,066 200,690 298,756 369 1,167 1,536 3,041 17,138 20,179 68,188 124,060 192,248 (2,027) 1,597 (430) (1,675) (190) (2,295) 5,323 9,182 7,829 $ million 2018 Total a Non-US region includes UK $65,630 million b Non-US region includes UK $19,426 million c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments. By geographical area Revenues Third party sales and other operating revenuesa Other income statement items Production and similar taxes Results Replacement cost profit (loss) before interest and taxation Non-current assets Non-current assetsb c US Non-US $ million 2017 Total 83,269 156,939 240,208 52 1,723 1,775 (266) 8,887 8,621 61,828 123,646 185,474 a Non-US region includes UK $48,837 million. b Non-US region includes UK $18,004 million. c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments. 158 BP Annual Report and Form 20-F 2018 5. Segmental analysis – continued By geographical area Revenues Third party sales and other operating revenuesa Other income statement items Production and similar taxes Results Replacement cost profit (loss) before interest and taxation a Non-US region includes UK $37,119 million. US Non-US $ million 2016 Total 65,132 117,876 183,008 155 528 683 (8,311) 6,284 (2,027) 6. Revenue from contracts with customers The amounts shown in the table below are included in Sales and other operating revenues in the group income statement. An analysis of total sales and other operating revenues by segment and region is provided in Note 5. Revenue from contracts with customers, by product Crude oil Oil products Natural gas, LNG and NGLs Non-oil products and other revenues from contracts with customers Revenues from contracts with customers 2018 65,276 195,466 21,745 13,768 296,255 2017 49,670 159,821 16,196 12,538 238,225 $ million 2016 32,284 126,465 11,337 11,487 181,573 The group’s sales to customers of crude oil and oil products were substantially all made by the Downstream segment. The group’s sales to customers of natural gas, LNG and NGLs were made by the Upstream segment. A significant majority of the group’s sales of non-oil products and other revenues from contracts with customers were made by the Downstream segment. 7. Income statement analysis Interest and other income Interest income from Financial assets measured at amortized cost Financial assets measured at fair value through profit or loss Other income Currency exchange losses charged to the income statementa Expenditure on research and development Finance costs Interest payable on liabilities measured at amortized cost Capitalized at 3.56% (2017 2.25% and 2016 1.81%)b Unwinding of discount on provisions Unwinding of discount on other payables measured at amortized cost a Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss. b Tax relief on capitalized interest is approximately $55 million (2017 $64 million and 2016 $56 million). 2018 2017 $ million 2016 421 39 313 773 368 429 2,198 (419) 210 539 2,528 288 — 369 657 83 391 1,718 (297) 150 503 2,074 183 — 323 506 698 400 1,221 (244) 310 388 1,675 BP Annual Report and Form 20-F 2018 159 8. Exploration for and evaluation of oil and natural gas resources The following financial information represents the amounts included within the group totals relating to activity associated with the exploration for and evaluation of oil and natural gas resources. All such activity is recorded within the Upstream segment. For information on significant judgements made in relation to oil and natural gas accounting see Intangible assets in Note 1. Exploration and evaluation costs Exploration expenditure written offa Other exploration costs Exploration expense for the year Impairment losses Intangible assets – exploration and appraisal expenditureb Liabilities Net assets Cash used in operating activities Cash used in investing activities 2018 2017 1,085 360 1,445 137 15,989 60 15,929 360 1,119 1,603 477 2,080 — 17,026 82 16,944 477 1,901 $ million 2016 1,274 447 1,721 62 16,960 102 16,858 447 2,920 a 2018 includes $447 million in the deepwater Gulf of Mexico principally relating to licence expiries. 2017 included a write-off in Angola of $574 million in relation to licence relinquishment, and Egypt of $208 million following a determination that no commercial hydrocarbons had been found. 2017 also included a $145-million write-off in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. 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. For further information see Upstream – Exploration on page 25. b 2018 includes $2.3 billion relating to licences in the Gulf of Mexico that have expired and approximately $1.6 billion relating to certain licences elsewhere that are due to expire in the next financial year. BP remains committed to developing these prospects. See Note 1 for further information. The carrying amount, by location, of exploration and appraisal expenditure capitalized as intangible assets at 31 December 2018 is shown in the table below. Carrying amount $1 - 2 billion $2 - 3 billion 9. Taxation Tax on profit Current tax Charge for the year Adjustment in respect of prior yearsa Deferred taxb Origination and reversal of temporary differences in the current year Adjustment in respect of prior years Tax charge (credit) on profit or loss Angola; India; Egypt; Middle East US - Gulf of Mexico; Canada; Brazil Location 2018 2017 6,217 (221) 5,996 907 242 1,149 7,145 4,208 58 4,266 (503) (51) (554) 3,712 $ million 2016 1,762 (123) 1,639 (3,709) (397) (4,106) (2,467) a The adjustments in respect of prior years reflect the reassessment of the current tax balances for prior years in light of changes in facts and circumstances during the year. b Origination and reversal of temporary differences in the current year include the impact of tax rate changes on deferred tax balances. 2018 includes a credit of $121 million (2017 $859 million charge) in respect of the reduction in the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018. The adjustments in respect of prior years reflect the reassessment of deferred tax balances for prior periods in light of all other changes in facts and circumstances during the year. In 2018, the total tax charge recognized within other comprehensive income was $714 million (2017 $1,499 million charge and 2016 $752 million credit), primarily comprising the deferred tax impact of the remeasurements of the net pension and other post-retirement benefit liability or asset. See Note 32 for further information. The total tax charge recognized directly in equity was $17 million (2017 $263 million charge and 2016 $5 million credit). For information on significant estimates and judgements made in relation to taxation see Income taxes in 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, 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. 160 BP Annual Report and Form 20-F 2018 9. Taxation – continued Profit (loss) before taxation Tax charge (credit) on profit or loss Effective tax rate Tax rate computed at the weighted average statutory ratea Increase (decrease) resulting from Tax reported in equity-accounted entities Adjustments in respect of prior years Deferred tax not recognized Tax incentives for investment Gulf of Mexico oil spill non-deductible costs Disposal impactsb Foreign exchange Items not deductible for tax purposes Impact of US tax reformc Decrease in rate of UK supplementary charged Other Effective tax rate 2016 excluding impacts of Gulf of Mexico oil spill and impairments 2016 impacts of Gulf of Mexico oil spill and impairments 2,914 (117) (4)% (5,209) (2,350) 45% 2017 7,180 3,712 52% 2018 16,723 7,145 43% $ million 2016 (2,295) (2,467) 107% % of profit or loss before taxation 43 (5) — 2 (2) — — 3 1 (1) — 2 43 44 (7) — 9 (6) 1 (1) (4) 5 12 — (1) 52 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 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. b In 2016 this related primarily to the tax impact on the contribution of BP’s Norwegian upstream business into Aker BP ASA. c Relates to the deferred tax impact of the reduction in the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018. d Relates to the deferred tax impact of the reduction in the UK supplementary charge rate applicable to profits arising in the North Sea from 20% to 10% in 2016. Deferred tax Analysis of movements during the year in the net deferred tax liability At 31 December Adjustment on adoption of IFRS 9a At 1 January Exchange adjustments Charge (credit) for the year in the income statement Charge for the year in other comprehensive income Charge for the year in equity Acquisitions and other additionsb At 31 December a 2018 reflects the deferred tax impact of adjustments recorded by the group on adoption of IFRS 9. See Note 1 for further information. b 2018 relates primarily to the purchase of an additional 16.5% interest in the Clair field. See Note 3 - Other significant transactions for further information. 2018 3,513 (36) 3,477 (68) 1,149 734 17 797 6,106 $ million 2017 2,497 — 2,497 12 (554) 1,503 1 54 3,513 BP Annual Report and Form 20-F 2018 161 9. Taxation – continued 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 creditsb 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 statementa $ million Balance sheeta 2018 2017 2016 2018 2017 (1,297) 65 (36) (57) (1,325) (6) 1,505 (25) 123 559 318 2,474 1,149 (3,971) (12) (27) (64) (4,074) 340 3,503 (50) 1,476 (964) (785) 3,520 (554) 81 (12) (230) (122) (283) 98 591 (6) (5,177) 249 422 (3,823) (4,106) 22,565 1,956 — 1,224 25,745 (1,319) (7,126) (144) (3,626) (5,900) (1,524) (19,639) 6,106 9,812 3,706 23,045 1,319 623 1,317 26,304 (1,386) (8,618) (672) (3,750) (6,493) (1,872) (22,791) 3,513 7,982 4,469 a The 2017 and 2018 income statement and balance sheet are impacted by the reduction in US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018. b The 2016 income statement reflected the impact of a loss carry-back claim in the US, displacing foreign tax credits utilized in prior periods which are now carried forward. The recognition of deferred tax assets of $2,758 million (2017 $3,503 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. For 2018, $1,563 million relates to the US (2017 $2,067 million) and $1,108 million relates to India (2017 $1,336 million). 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 2018 6.6 4.3 22.5 18.7 3.8 37.3 1.5 $ billion 2017 6.8 4.5 20.1 16.3 3.8 31.4 1.6 a For 2018 these losses expire in the period 2019-2038 with applicable tax rates ranging from 3% 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 For 2018 the US unused tax credits expire in the period 2019-2028. e The majority comprises fixed asset temporary differences in the UK. Substantially all of the temporary differences have no expiry date. Impact of previously unrecognized deferred tax or write-down of deferred tax assets on tax charge Current tax benefit relating to the utilization of previously unrecognized deferred tax assets Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets Deferred tax benefit relating to the recognition of previously unrecognized deferred tax assets Deferred tax expense arising from the write-down of a previously recognized deferred tax asset 2018 83 — 112 169 2017 22 — 436 78 $ million 2016 40 269 394 55 162 BP Annual Report and Form 20-F 2018 10. Dividends The quarterly dividend paid on 29 March 2019 in respect of the fourth quarter 2018 was 10.25 cents per ordinary share ($0.615 per American Depositary Share (ADS)). The corresponding amount in sterling was announced on 18 March 2019. 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 2018 2017 2016 2018 2017 2016 2018 2017 $ million 2016 Dividends announced and paid in cash Preference shares Ordinary shares March June September December Dividend announced, paid in March 2019 1 1 1 7.1691 7.4435 7.9296 8.0251 30.5673 8.1587 7.7563 7.6213 7.4435 30.9798 7.0125 6.9167 7.5578 7.9313 29.4183 10.00 10.00 10.00 10.00 40.00 10.00 10.00 10.00 10.00 40.00 10.00 10.00 10.25 10.25 40.50 10.25 1,828 1,727 1,409 1,734 6,699 1,435 1,303 1,546 1,676 1,627 6,153 1,099 1,168 1,161 1,182 4,611 The details of the scrip dividends issued are shown in the table below. Number of shares issued (thousand) Value of shares issued ($ million) 2018 2017 2016 195,305 1,381 289,789 1,714 548,005 2,858 The financial statements for the year ended 31 December 2018 do not reflect the dividend announced on 5 February 2019 and paid in March 2019; this will be treated as an appropriation of profit in the year ending 31 December 2019. 11. Earnings per share Per ordinary share Basic earnings per share Diluted earnings per share Per American Depositary Share (ADS) Basic earnings per share Diluted earnings per share 2018 46.98 46.67 2018 2.82 2.80 2017 17.20 17.10 2017 1.03 1.03 Cents per share 2016 0.61 0.60 Dollars per share 2016 0.04 0.04 Basic earnings per ordinary share amounts are calculated by dividing the profit (loss) for the year attributable to BP ordinary shareholders by the weighted average number of ordinary shares outstanding during the year. The average number of shares outstanding includes certain shares that will be issuable in the future under employee share-based payment plans and excludes treasury shares, which includes shares held by the Employee Share Ownership Plan trusts (ESOPs). For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the average number of shares that are potentially issuable in connection with employee share-based payment plans. If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share. Profit (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 diluted earnings per share 2018 9,383 1 9,382 2017 3,389 1 3,388 $ million 2016 115 1 114 2018 2017 2016 19,970,215 19,692,613 18,744,800 Shares thousand 132,278 123,829 110,519 20,102,493 19,816,442 18,855,319 2018 2017 2016 3,328,369 3,282,102 3,124,133 Shares thousand 22,046 20,638 18,420 3,350,415 3,302,740 3,142,553 BP Annual Report and Form 20-F 2018 163 11. Earnings per share – continued The number of ordinary shares outstanding at 31 December 2018, excluding treasury shares, and including certain shares that will be issuable in the future under employee share-based payment plans was 20,101,658,664. Between 31 December 2018 and 11 March 2019, the latest practicable date before the completion of these financial statements, there was a net increase of 143,038,241 in the number of ordinary shares outstanding primarily as a result of share issues in relation to employee share-based payment plans. Employee share-based payment plans The group operates share and share option plans for directors and certain employees to obtain ordinary shares and ADSs in the company. Information on these plans for directors is shown in the Directors remuneration report on pages 87-109. 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 2018 Number of optionsab thousand 19,437 481 6,123 Weighted average exercise price $ 4.28 4.69 n/a Number of optionsab thousand 22,399 1,112 5,145 2017 Weighted average exercise price $ 4.34 4.46 n/a a Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares). b At 31 December 2018 the quoted market price of one BP ordinary share was £4.96 (2017 £5.23). 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 Over 4 years Dilutive effect 2018 2017 Number of sharesa Number of sharesa thousand 108,934 106,337 71,407 588 799 288,065 127,165 thousand 101,550 108,373 85,878 413 166 296,380 126,122 a Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares). There has been a net decrease of 56,796,490 in the number of potential ordinary shares relating to employee share-based payment plans between 31 December 2018 and 11 March 2019. 164 BP Annual Report and Form 20-F 2018  12. Property, plant and equipment Cost At 1 January 2018 Exchange adjustments Additions Acquisitions Remeasurements Transfers from intangible assets Deletions At 31 December 2018 Depreciation At 1 January 2018 Exchange adjustments Charge for the year Impairment losses Impairment reversals Deletions At 31 December 2018 Net book amount at 31 December 2018 Cost At 1 January 2017 Exchange adjustments Additions Acquisitions Transfers from intangible assets Deletions At 31 December 2017 Depreciation At 1 January 2017 Exchange adjustments Charge for the year Impairment losses Impairment reversals Deletions At 31 December 2017 Net book amount at 31 December 2017 Assets held under finance leases at net book amount included above At 31 December 2018 At 31 December 2017 Assets under construction included above At 31 December 2018 At 31 December 2017 Land and land improvements Buildings Oil and gas propertiesa Plant, machinery and equipment Fittings, fixtures and office equipment Transportationb Oil depots, storage tanks and service stations 3,474 (168) 233 163 — — (140) 3,562 683 (25) 92 2 — (126) 626 1,573 (58) 40 4 — — (45) 1,514 818 (24) 52 — — (139) 707 226,054 — 9,712 10,882 17 901 (14,699) 232,867 133,326 — 12,342 86 (564) (11,333) 133,857 46,662 (892) 2,323 9 — — (1,810) 46,292 20,996 (460) 1,820 253 (1) (1,733) 20,875 2,853 (73) 204 1 — — (238) 2,747 2,136 (52) 189 — — (232) 2,041 10,774 (43) (112) 2 — — (128) 10,493 7,523 (27) 252 178 (17) (75) 7,834 8,748 (501) 736 36 — — (146) 8,873 5,185 (279) 384 2 — (145) 5,147 $ million Total 300,138 (1,735) 13,136 11,097 17 901 (17,206) 306,348 170,667 (867) 15,131 521 (582) (13,783) 171,087 2,936 807 99,010 25,417 706 2,659 3,726 135,261 3,066 264 264 — — (120) 3,474 584 33 90 3 — (27) 683 2,235 42 94 — — (798) 1,573 1,062 27 94 35 — (400) 818 215,564 — 12,366 — 451 (2,327) 226,054 122,428 — 12,385 624 (135) (1,976) 133,326 43,725 1,251 1,890 41 — (245) 46,662 18,686 647 1,764 35 — (136) 20,996 2,670 91 240 — — (148) 2,853 2,022 67 185 — — (138) 2,136 14,000 28 347 228 — (3,829) 10,774 9,823 19 381 479 (72) (3,107) 7,523 7,623 772 575 1 — (223) 8,748 4,521 466 350 17 — (169) 5,185 288,883 2,448 15,776 270 451 (7,690) 300,138 159,126 1,259 15,249 1,193 (207) (5,953) 170,667 2,791 755 92,728 25,666 717 3,251 3,563 129,471 — — 2 2 12 16 207 238 — — 295 233 6 7 522 496 22,522 23,789 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 Includes adjustments to decommissioning provisions see Note 1 for further information. 13. Capital commitments Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been signed at 31 December 2018 amounted to $8,319 million (2017 $11,340 million). BP has capital commitments amounting to $1,227 million (2017 $1,451 million) in relation to associates. BP’s share of capital commitments of joint ventures amounted to $619 million (2017 $483 million). BP Annual Report and Form 20-F 2018 165 14. Goodwill and impairment review of goodwill Cost At 1 January Exchange adjustments Acquisitions and other additionsa 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 2018 12,163 (210) 1,046 (184) 12,815 612 — (1) 611 12,204 11,551 a 2018 principally relates to the purchase of an additional 16.5% share in the Clair field in the North Sea. See Note 3 - Other significant transactions for further information. Impairment review of goodwill Goodwill at 31 December Upstream Downstream Other businesses and corporate 2018 8,346 3,802 56 12,204 $ million 2017 11,805 336 83 (61) 12,163 611 1 — 612 11,551 11,194 $ million 2017 7,728 3,758 65 11,551 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, intangible assets and goodwill in Note 1. Upstream Goodwill Excess of recoverable amount over carrying amount 2018 8,346 53,391 $ million 2017 7,728 27,705 The table above shows the carrying amount of goodwill for the segment and the excess of the recoverable amount, based upon a post-tax value-in-use calculation, over the carrying amount (headroom) at the date of the test. The increase in headroom principally arises from acquisitions, new activity and changes in US tax. In the prior year, the recoverable amount was estimated using a fair value less costs of disposal calculation and was based on cash flows estimated for the impairment test performed in 2016 as permitted by IAS 36. The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates of cessation of production of each producing field, based on current estimates of reserves and resources, appropriately risked. Midstream and supply and trading activities and equity-accounted entities are generally not included in the impairment review of goodwill, 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. As the production profile and related cash flows can be estimated from BP’s past experience, management believes that the cash flows generated over the estimated life of field is the appropriate basis upon which to assess goodwill and individual assets for impairment. The estimated date of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons, production costs, the contractual duration of the production concession and the selling price of the hydrocarbons produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of the fields are computed using appropriate individual economic models and key assumptions agreed by BP management. Capital expenditure, operating costs and expected hydrocarbon production profiles are derived from the business segment plan adjusted for assumptions reflecting the price environment at the time that the test was performed. Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis are 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. The most recent review for impairment was carried out in the fourth quarter. The key assumptions used in the value-in-use calculation are oil and natural gas prices, production volumes and the discount rate. Oil and gas price assumptions for the first five years are based on management’s best estimate of prices over those five years, with the long-term price applied from year 6 onwards. Price assumptions and discount rate assumptions used were as disclosed in Note 1. The value-in-use calculation has been prepared solely for the purposes of determining whether the goodwill balance was impaired. Estimated future cash flows were prepared on the basis of certain assumptions prevailing at the time of the test. The actual outcomes may differ from the assumptions made. For example, reserves and resources estimates and production forecasts are subject to revision as further technical information becomes available and economic conditions change, and future commodity prices may differ from the forecasts used in the calculations. Sensitivities to different variables have been estimated using certain simplifying assumptions. For example, lower oil and gas price 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. 166 BP Annual Report and Form 20-F 2018 14. Goodwill and impairment review of goodwill – continued It is estimated that if the oil price assumption for all future years was approximately $14 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 no reasonable fall in the gas price assumption 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 829mmboe per year (2017 889mmboe per year). It is estimated that if production volumes were to be reduced by approximately 13% 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 11% for the entire portfolio, an increase of 5% for all countries not considered ‘higher risk’ and 3% 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 2,692 Other 1,110 2018 Total 3,802 Lubricants 2,849 Other 909 $ million 2017 Total 3,758 Cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of up to five years. To determine the value in use for each of the cash-generating units, cash flows for a period of 10 years are discounted and aggregated with a terminal value. Lubricants As permitted by IAS 36, the detailed calculations of Lubricants’ recoverable amount performed in the most recent detailed calculation in 2013 were used as the basis for the tests in 2014-2017 as the criteria of IAS 36 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 is remote. IAS 36 does not specify for how many years such an approach is appropriate and management determined that a re-performance of the test was appropriate in 2018 given the passage of time since 2013. There was no significant change in the outcome of this test compared to that in 2013. The key assumptions to which the calculation of value in use for the Lubricants unit is most sensitive are operating unit margins, sales volumes, and discount rate. Operating margin and sales volumes assumptions used in the detailed impairment review of goodwill calculation are consistent with the assumptions used in the Lubricants unit’s business plan and values assigned to these key assumptions reflect past experience. No reasonably possible change in any of these key assumptions would cause the unit’s carrying amount to exceed its recoverable amount. Cash flows beyond the plan period are extrapolated using a nominal 2.8% growth rate (2013 3%). 15. Intangible assets Cost At 1 January Exchange adjustments Acquisitions Additions Transfers to property, plant and equipment Deletions At 31 December Amortization At 1 January Exchange adjustments Charge for the year Impairment losses Deletions At 31 December Net book amount at 31 December Net book amount at 1 January a For further information see Intangible assets within Note 1 and Note 8. Exploration and appraisal expenditurea Other intangibles 17,886 — — 1,095 (901) (1,027) 17,053 860 — 1,085 137 (1,018) 1,064 15,989 17,026 4,488 (128) 25 318 — (199) 4,504 3,159 (77) 326 — (199) 3,209 1,295 1,329 2018 Total 22,374 (128) 25 1,413 (901) (1,226) 21,557 4,019 (77) 1,411 137 (1,217) 4,273 17,284 18,355 Exploration and appraisal expenditurea Other intangibles 18,524 — — 2,128 (451) (2,315) 17,886 1,564 — 1,603 — (2,307) 860 17,026 16,960 4,035 197 41 310 — (95) 4,488 2,812 107 335 — (95) 3,159 1,329 1,223 $ million 2017 Total 22,559 197 41 2,438 (451) (2,410) 22,374 4,376 107 1,938 — (2,402) 4,019 18,355 18,183 BP Annual Report and Form 20-F 2018 167 16. Investments in joint ventures The following table provides aggregated summarized financial information relating to the group’s share of joint ventures. Sales and other operating revenues Profit before interest and taxation Finance costs Profit before taxation Taxation 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 Group investment in joint ventures Group share of net assets (as above) Loans made by group companies to joint ventures 2018 13,258 1,396 85 1,311 414 897 6 903 10,399 2,935 13,334 1,715 3,017 4,732 8,602 8,602 45 8,647 Transactions between the group and its joint ventures are summarized below. Sales to joint ventures Product LNG, crude oil and oil products, natural gas Purchases from joint ventures Sales 4,603 2018 Amount receivable at 31 December 251 2018 Sales 3,578 2017 Amount receivable at 31 December 352 2017 2017 11,380 1,394 100 1,294 117 1,177 8 1,185 10,139 2,419 12,558 1,687 2,927 4,614 7,944 7,944 50 7,994 Sales 3,327 $ million 2016 10,081 1,612 156 1,456 490 966 5 971 $ million 2016 Amount receivable at 31 December 291 $ million 2016 Amount payable at 31 December Product LNG, crude oil and oil products, natural gas, refinery operating costs, plant processing fees Amount payable at 31 December Purchases Amount payable at 31 December Purchases Purchases 1,336 300 1,257 176 943 120 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. 17. Investments in associates The following table provides aggregated summarized financial information for the group’s associates as it relates to the amounts recognized in the group income statement and on the group balance sheet. Rosneft Other associates Income statement Earnings from associates - after interest and tax 2018 2,283 573 2,856 2017 922 408 1,330 2016 647 347 994 2018 10,074 7,599 17,673 $ million Balance sheet Investments in associates 2017 10,059 6,932 16,991 The associate that is material to the group at both 31 December 2018 and 2017 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 2018. BP classifies its investment in Rosneft as an associate because, in management’s judgement, BP has significant influence over Rosneft; see Interests in other entities within Note 1 for further information. The group’s investment in Rosneft is a foreign operation whose functional currency is the Russian rouble. The increase in the group's equity-accounted investment balance for Rosneft at 31 December 2018 compared with 31 December 2017 principally relates to earnings from Rosneft offset by dividends distribution and foreign exchange effects which have been recognized in other comprehensive income. 168 BP Annual Report and Form 20-F 2018 17. Investments in associates – continued The value of BP’s 19.75% shareholding in Rosneft based on the quoted market share price of $6.18 per share (2017 $4.99 per share) was $12,934 million at 31 December 2018 (2017 $10,444 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 2018, as shown in the table below, compared with the amounts reported in Rosneft's IFRS financial statements. In particular, in 2018 these adjustments resulted in BP reporting a lower amount relating to impairment charges of downstream goodwill than the equivalent amounts reported by Rosneft. 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 2016 74,380 7,094 1,747 5,347 1,797 273 3,277 4,203 7,480 2018 131,322 18,886 2,785 16,101 2,957 1,585 11,559 2,086 13,645 137,038 43,438 180,476 41,311 78,754 120,065 60,411 9,403 51,008 2017 103,028 9,949 2,228 7,721 1,742 1,311 4,668 2,810 7,478 158,719 39,737 198,456 66,506 70,704 137,210 61,246 10,314 50,932 The group received dividends, net of withholding tax, of $620 million from Rosneft in 2018 (2017 $314 million and 2016 $332 million). Summarized financial information for the group’s share of associates is shown below. $ million BP share 2016 Total 20,067 1,926 367 1,559 511 54 994 828 1,822 Rosnefta 14,690 1,401 345 1,056 355 54 647 830 1,477 Other 5,377 525 22 503 156 — 347 (2) 345 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 25,936 3,730 550 3,180 584 313 2,283 412 2,695 27,065 8,579 35,644 8,159 15,554 23,713 11,931 1,857 10,074 Other 9,134 1,150 78 1,072 499 — 573 (1) 572 10,787 2,398 13,185 2,232 3,817 6,049 7,136 — 7,136 2018 Total 35,070 4,880 628 4,252 1,083 313 2,856 411 3,267 37,852 10,977 48,829 10,391 19,371 29,762 19,067 1,857 17,210 Rosnefta 20,348 1,965 440 1,525 344 259 922 555 1,477 31,347 7,848 39,195 13,135 13,964 27,099 12,096 2,037 10,059 Other 7,600 626 54 572 164 — 408 1 409 9,261 2,645 11,906 2,501 3,308 5,809 6,097 — 6,097 2017 Total 27,948 2,591 494 2,097 508 259 1,330 556 1,886 40,608 10,493 51,101 15,636 17,272 32,908 18,193 2,037 16,156 10,074 7,136 17,210 10,059 6,097 16,156 — 463 463 — 835 835 10,074 7,599 17,673 10,059 6,932 16,991 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. BP Annual Report and Form 20-F 2018 169 17. 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 Sales 2,064 2018 Amount receivable at 31 December 393 2018 Sales 1,612 2017 Amount receivable at 31 December 216 2017 Sales 3,643 Amount payable at 31 December Purchases Amount payable at 31 December Purchases Purchases $ million 2016 Amount receivable at 31 December 765 $ million 2016 Amount payable at 31 December Crude oil and oil products, natural gas, transportation tariff 14,112 2,069 11,613 1,681 8,873 2,000 In addition to the transactions shown in the table above, in 2018 BP acquired a 49% stake in LLC Kharampurneftegaz, a Rosneft subsidiary, which will develop subsoil resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets Autonomous Okrug in northern Russia. BP’s interest in LLC Kharampurneftegaz is accounted for as an associate. The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above. The majority of the sales to and purchases from associates relate to crude oil and oil products transactions with Rosneft. BP has commitments amounting to $11,303 million (2017 $13,932 million), primarily in relation to contracts with its associates for the purchase of transportation capacity. For information on capital commitments in relation to associates see Note 13. 18. Other investments Equity investmentsa Other a The majority of equity investments are unlisted. 2018 $ million 2017 Current Non-current Current Non-current 1 221 222 482 859 1,341 15 110 125 418 827 1,245 Other investments includes $893 million relating to contingent consideration amounts arising on disposals (2017 $237 million) which are financial assets classified as measured at fair value through profit or loss. The fair value is determined using an estimate of discounted future cash flows that are expected to be received and is considered a level 3 valuation under the fair value hierarchy. Future cash flows are estimated based on inputs including oil and natural gas prices, production volumes and operating costs related to the disposed operations. The discount rate used is based on a risk-free rate adjusted for asset-specific risks. 19. Inventories Crude oil Natural gas Refined petroleum and petrochemical products Trading inventories Supplies Cost of inventories expensed in the income statement 2018 4,878 322 10,419 15,619 282 15,901 2,087 17,988 229,878 $ million 2017 5,692 119 10,694 16,505 295 16,800 2,211 19,011 179,716 The inventory valuation at 31 December 2018 is stated net of a provision of $1,009 million (2017 $474 million) to write down inventories to their net realizable value, of which $604 million (2017 $62 million) relates to hydrocarbon inventories. The net charge to the income statement in the year in respect of inventory net realizable value provisions was $552 million (2017 $27 million credit), of which $553 million (2017 $31 million credit) related to hydrocarbon inventories. Trading inventories are valued using quoted benchmark prices adjusted as appropriate for location and quality differentials. They are predominantly categorized within level 2 of the fair value hierarchy. 170 BP Annual Report and Form 20-F 2018 20. 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 asset Sales taxes and production taxes Other receivables 2018 $ million 2017 Current Non-current Current Non-current 19,414 642 3,275 23,331 214 790 143 1,147 24,478 7 2 740 749 — 482 603 1,085 1,834 18,912 566 4,206 23,684 252 746 167 1,165 24,849 4 2 671 677 — 276 481 757 1,434 In both 2018 and 2017 the group entered into non-recourse arrangements to discount certain receivables in support of supply and trading activities and the management of credit risk. Trade and other receivables are predominantly non-interest bearing. See Note 29 for further information. 21. Valuation and qualifying accounts 2018 2017 $ million 2016 Not credit- impaired Credit impaired Trade and other receivables Fixed asset investments Trade and other receivables Fixed asset investments Trade and other receivables Fixed asset investments — 115 115 (26) — — 89 335 — 335 56 (12) (52) 327 335 115 450 30 (12) (52) 416 314 (85) 229 10 (1) (3) 235 392 — 392 68 13 (138) 335 335 — 335 47 3 (71) 314 447 — 447 120 (7) (168) 392 435 — 435 55 (2) (153) 335 At 1 January – IAS 39 Adjustment on adoption of IFRS 9 At 1 January – IFRS 9 Charged to costs and expenses Charged to other accountsa Deductions At 31 December a Principally exchange adjustments. Valuation and qualifying accounts relating to trade and other receivables comprise expected credit loss allowances in 2018 and impairment provisions recognized on an incurred loss basis in comparative periods. The adjustment on adoption of IFRS 9 relates to the additional loss allowance required by the new standard's expected credit loss model. There were no significant changes to the gross carrying amounts of trade and other receivables during the year that affected the estimation of the loss allowance at 31 December 2018. Valuation and qualifying accounts relating to fixed asset investments comprise impairment provisions for investments in equity-accounted entities in 2018. This includes expected credit loss allowances of $44 million (1 January 2018 $43 million) relating to loans that form part of the net investment in equity-accounted entities. The adjustment on adoption of IFRS 9 primarily relates to amounts provided against investments in equity instruments that were held at cost less impairment losses under IAS 39 but that are classified as measured at fair value through profit or loss under IFRS 9. In addition to the amounts presented above, expected loss allowances on cash and cash equivalents classified as measured at amortized cost totalled $11 million (1 January 2018 $11 million). For further information on the group's credit risk management policies and how the group recognizes and measures expected losses see Note 29. Valuation and qualifying accounts are deducted in the balance sheet from the assets to which they apply. For further information on the adjustments on adoption of IFRS 9 see Note 1. BP Annual Report and Form 20-F 2018 171 22. Trade and other payables Financial liabilities Trade payables Amounts payable to joint ventures and associates Payables for capital expenditure and acquisitionsa Payables related to the Gulf of Mexico oil spillb Other payables Non-financial liabilities Sales taxes, customs duties, production taxes and social security Other payables 2018 $ million 2017 Current Non-current Current Non-current 26,252 2,369 7,325 2,279 4,980 43,205 2,272 788 3,060 46,265 — — 1,345 11,922 318 13,585 35 210 245 13,830 26,983 1,857 3,810 2,089 5,733 40,472 2,586 1,151 3,737 44,209 — — 1,269 12,253 60 13,582 50 257 307 13,889 a Includes $3,514 million deferred consideration relating to the acquisition of Petrohawk Energy Corporation from BHP Billiton Petroleum (North America) Inc. See Note 3 for further information. b See Note 2 for further information. Materially all of BP's trade payables have payment terms in the range of 30 to 60 days and give rise to operating cash flows. The active management of supplier payment terms within this range enables BP to optimize and reduce volatility in cash flow. Trade and other payables, other than those relating to the Gulf of Mexico oil spill, are predominantly interest free. See Note 29 (c) for further information. 23. Provisions At 1 January 2018 Exchange adjustments Acquisitions Increase (decrease) in existing provisions Write-back of unused provisions Unwinding of discount Change in discount ratea Utilization Reclassified to other payables Deletions At 31 December 2018 Of which – current – non-current Of which – Gulf of Mexico oil spillb Decommissioning Environmental Litigation and claims 16,100 (135) 295 137 (2) 162 (2,377) (9) (270) (288) 13,613 257 13,356 — 1,516 (9) 12 428 (115) 22 (38) (245) (4) — 1,567 300 1,267 — 3,334 (3) 24 1,492 (21) 9 (31) (1,034) (2,051) (1) 1,718 798 920 345 $ million Total 23,944 (231) 336 3,360 (393) 210 (2,463) (1,816) (2,362) (289) 20,296 2,564 17,732 345 Other 2,994 (84) 5 1,303 (255) 17 (17) (528) (37) — 3,398 1,209 2,189 — a Includes the impact of changing from a real to nominal discount rate. See Note 1 for further information. b Further information on the financial impacts of the Gulf of Mexico oil spill is provided in Note 2. The decommissioning provision comprises the future cost of decommissioning oil and natural gas wells, facilities and related pipelines. The environmental provision includes provisions for costs related to the control, abatement, clean-up or elimination of environmental pollution relating to soil, groundwater, surface water and sediment contamination. The litigation and claims category includes provisions for matters related to, for example, commercial disputes, product liability, and allegations of exposures of third parties to toxic substances. Included within the other category at 31 December 2018 are provisions for deferred employee compensation of $338 million (2017 $391 million). For information on significant estimates and judgements made in relation to provisions, see Provisions and contingencies within Note 1. 24. Pensions and other post-retirement benefits Most group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned. Pension benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and other types of schemes with committed pension benefit payments). For defined contribution plans, retirement benefits are determined by the value of funds arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such factors as an employee’s pensionable salary and length of service. Defined benefit plans may be funded or unfunded. The assets of funded plans are generally held in separately administered trusts. For information on significant estimates and judgements made in relation to accounting for these plans see Pensions and other post-retirement benefits in Note 1. The primary pension arrangement in the UK is a funded final salary pension plan under which retired employees draw the majority of their benefit as an annuity. This pension plan is governed by a corporate trustee whose board is composed of four member-nominated directors, four company-nominated directors, 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. 172 BP Annual Report and Form 20-F 2018 24. Pensions and other post-retirement benefits – continued In the US, all pension benefits now accrue under a cash balance formula. Benefits previously accrued under final salary formulas are legally protected. Retiring US employees typically take their pension benefit in the form of a lump sum payment upon retirement. The plan is funded and its assets are overseen by a fiduciary Investment Committee 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 2018 the aggregate level of contributions was $610 million (2017 $637 million and 2016 $651 million). The aggregate level of contributions in 2019 is expected to be approximately $700 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 is agreed covering the next five years. Contractually committed funding amounted to $1,275 million at 31 December 2018, all of which relates to future service. This amount is included in the group’s committed cash flows relating to pensions and other post-retirement benefit plans as set out in the table of contractual obligations on page 278. 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. No contributions were made into the primary US pension plan in 2018 and no statutory funding requirement is expected in the next 12 months. The surplus relating to the primary US fund is recognized on the balance sheet on the basis that economic benefit can be gained from the surplus through a reduction in future contributions. There was no minimum funding requirement for the US plan, and no significant minimum funding requirements in other countries at 31 December 2018. 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 2018. The UK plans are subject to a formal actuarial valuation every three years; valuations are required more frequently in many other countries. The most recent formal actuarial valuation of the UK pension plans was as at 31 December 2017. A valuation of the US plan and largest Eurozone plans are carried out annually. The material financial assumptions used to estimate the benefit obligations of the various plans are set out below. The assumptions are reviewed by management at the end of each year, and are used to evaluate the accrued benefit obligation at 31 December and pension expense for the following year. Financial assumptions used to determine benefit obligation Discount rate for plan liabilities Rate of increase in salaries Rate of increase for pensions in payment Rate of increase in deferred pensions Inflation for plan liabilities Financial assumptions used to determine benefit expense Discount rate for plan service cost Discount rate for plan other finance expense Inflation for plan service cost 2018 2.9 3.8 3.0 3.0 3.1 2018 2.6 2.5 3.1 2017 2.5 4.1 2.9 2.9 3.1 2017 2.7 2.7 3.2 UK 2016 2.7 4.6 3.0 3.0 3.2 UK 2016 4.0 3.9 3.1 2018 4.1 3.9 — — 1.5 2018 3.6 3.5 1.7 2017 3.5 4.1 — — 1.7 2017 4.1 3.9 1.8 US 2016 3.9 4.2 — — 1.8 US 2016 4.2 4.0 1.5 2018 2.0 3.1 1.5 0.5 1.7 2018 2.4 1.9 1.6 % Eurozone 2016 1.7 3.0 1.5 0.5 1.6 % Eurozone 2016 2.7 2.4 1.8 2017 1.9 3.0 1.4 0.6 1.6 2017 2.1 1.7 1.6 The discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and the Eurozone we use yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans are based on the difference between the yields on index-linked and fixed-interest long-term government bonds. In other countries, including the Eurozone, we use this approach, or advice from the local actuary depending on the information available. The inflation assumptions are used to determine the rate of increase for pensions in payment and the rate of increase in deferred pensions where there is such an increase. The assumptions for the rate of increase in salaries are based on the inflation assumption plus an allowance for expected long-term real salary growth. These include an allowance for promotion-related salary growth, of up to 0.8% depending on country. BP Annual Report and Form 20-F 2018 173 24. Pensions and other post-retirement benefits – continued In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best practice in the countries in which we provide pensions, and have been chosen with regard to applicable published tables adjusted where appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. BP’s most substantial pension liabilities are in the UK, the US and the Eurozone where our mortality assumptions are as follows: Mortality assumptions 2018 2017 UK 2016 2018 2017 US 2016 Years Eurozone 2018 2017 2016 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 27.4 27.4 28.0 25.1 25.1 25.7 25.6 25.1 25.0 28.9 29.0 30.0 26.9 26.8 27.5 28.1 27.6 27.6 28.8 28.8 29.5 28.5 28.4 29.3 29.0 29.0 28.9 30.6 30.5 31.9 30.1 30.0 31.0 31.2 31.4 31.3 Pension plan assets are generally held in trusts, the primary objective of which is to accumulate assets sufficient to meet the obligations of the plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management. A significant proportion of the assets are held in equities, which are expected to generate a higher level of return over the long term, with an acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment portfolios are highly diversified. The trustee’s long-term investment objective for the primary UK plan as it matures is to invest in assets whose value changes in the same way as the plan liabilities, in order to reduce the level of funding risk. To move towards this objective, the UK plan uses a liability driven investment (LDI) approach for part of the portfolio, investing primarily in government bonds to achieve this matching effect for the most significant plan liability assumptions of interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements, whereby the plan borrows money using existing bonds as security and which will be bought back at a specified price at an agreed future date. The funds raised are used to invest in further bonds to increase the proportion of assets which match the plan liabilities. The borrowings are shown separately in the analysis of pension plan assets in the table below. For the primary UK pension plan there is an agreement with the trustee to increase the proportion of assets with liability matching characteristics over time primarily by reducing the proportion of plan assets held as equities and increasing the proportion held as bonds. There is a similar agreement in place for the primary US plan. During 2018, the UK and the US plans switched 12.5% and 10% of plan assets respectively from equities to bonds. The current asset allocation policy for the major plans at 31 December 2018 was as follows: Asset category Total equity (including private equity) Bonds/cash (including LDI) Property/real estate UK % 30 63 7 US % 40 60 — The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2018 were $4,197 million (2017 $2,588 million) of government-issued nominal bonds and $17,491 million (2017 $16,177 million) of index-linked bonds. Some of the group’s pension plans in the Eurozone and other countries use derivative financial instruments as part of their asset mix to manage the level of risk. The fair value of these instruments are included in other assets in the table below. The UK and US plans do not use derivative financial instruments. 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 176. 174 BP Annual Report and Form 20-F 2018 24. Pensions and other post-retirement benefits – continued UKa USb Eurozone Other Fair value of pension plan assets At 31 December 2018 Listed equities – developed markets    – emerging markets Private equityc Government issued nominal bondsd Government issued index-linked bondsd Corporate bondsd Propertye Cash Other Debt (repurchase agreements) used to fund liability driven investments At 31 December 2017 Listed equities – developed markets    – emerging markets Private equityc Government issued nominal bondsd Government issued index-linked bondsd Corporate bondsd Propertye Cash Other Debt (repurchase agreements) used to fund liability driven investments At 31 December 2016 Listed equities – developed markets    – emerging markets Private equityc Government issued nominal bondsd Government issued index-linked bondsd Corporate bondsd Propertye Cash Other Debt (repurchase agreements) used to fund liability driven investments 5,191 950 2,792 4,263 17,491 4,606 2,311 376 116 (6,011) 32,085 9,548 2,220 2,679 2,663 16,177 4,682 2,211 390 104 (5,583) 35,091 11,494 2,549 2,754 489 9,384 4,042 1,970 547 (68) (2,981) 30,180 1,238 63 1,495 2,072 — 2,184 6 73 64 — 7,195 2,158 220 1,461 1,777 — 2,024 6 80 53 — 7,779 2,283 220 1,442 1,438 — 1,732 6 105 90 — 7,316 413 65 — 895 102 506 57 42 32 — 2,112 537 83 — 941 2 546 71 21 23 — 2,224 436 54 1 821 4 427 45 17 74 — 1,879 306 56 4 533 — 243 25 83 40 — 1,290 376 53 — 545 — 272 30 98 45 — 1,419 363 46 — 448 — 259 28 83 83 — 1,310 $ million Total 7,148 1,134 4,291 7,763 17,593 7,539 2,399 574 252 (6,011) 42,682 12,619 2,576 4,140 5,926 16,179 7,524 2,318 589 225 (5,583) 46,513 14,576 2,869 4,197 3,196 9,388 6,460 2,049 752 179 (2,981) 40,685 a Bonds held by the UK pension plans are denominated in sterling. Property held by the UK pension plans is in the United Kingdom. b Bonds held by the US pension plans are denominated in US dollars. c Private equity is valued at fair value based on the most recent third-party net asset valuation. d Bonds held by pension plans are valued using quoted prices in active markets. Where quoted prices are not available, quoted prices for similar instruments in active markets are used. e Properties are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party valuers. BP Annual Report and Form 20-F 2018 175 24. Pensions and other post-retirement benefits – continued Analysis of the amount charged to profit or loss Current service costa Past service costb Settlementb Operating charge relating to defined benefit plans Payments to defined contribution plans Total operating charge Interest income on plan assetsa Interest on plan liabilities Other finance (income) expense Analysis of the amount recognized in other comprehensive income Actual asset return less interest income on plan assets Change in financial assumptions underlying the present value of the plan liabilities Change in demographic assumptions underlying the present value of the plan liabilities Experience gains and losses arising on the plan liabilities Remeasurements recognized in other comprehensive income Movements in benefit obligation during the year Benefit obligation at 1 January Exchange adjustments Operating charge relating to defined benefit plans Interest cost Contributions by plan participantsc Benefit payments (funded plans)d Benefit payments (unfunded plans)d 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 295 15 — 310 38 348 (868) 774 (94) (722) 1,770 123 520 1,691 31,513 (1,589) 310 774 21 (1,780) (6) — (2,413) 26,830 35,091 (1,883) 868 21 490 (1,780) — (722) 32,085 5,255 5,473 (218) 5,255 5,473 (218) 5,255 299 — — 299 178 477 (262) 369 107 (256) 945 (9) 41 721 10,820 — 299 369 — (597) (218) — (977) 9,696 7,779 — 262 — 7 (597) — (256) 7,195 (2,501) 84 9 17 110 5 115 (44) 136 92 (69) 14 (42) (43) (140) 7,275 (303) 110 136 2 (84) (301) — 71 6,906 2,224 (93) 44 2 88 (84) — (69) 2,112 (4,794) 418 (2,919) (2,501) 29 (4,823) (4,794) 396 (2,897) (2,501) (152) (4,642) (4,794) 43 4 — 47 40 87 (45) 67 22 (36) 65 7 9 45 1,873 (113) 47 67 7 (83) (17) (14) (81) 1,686 1,419 (73) 45 7 25 (83) (14) (36) 1,290 (396) 35 (431) (396) (97) (299) (396) $ million 2018 Total 721 28 17 766 261 1,027 (1,219) 1,346 127 (1,083) 2,794 79 527 2,317 51,481 (2,005) 766 1,346 30 (2,544) (542) (14) (3,400) 45,118 46,513 (2,049) 1,219 30 610 (2,544) (14) (1,083) 42,682 (2,436) 5,955 (8,391) (2,436) 5,620 (8,056) (2,436) (26,612) (218) (26,830) (6,799) (2,897) (9,696) (2,264) (4,642) (6,906) (1,387) (299) (1,686) (37,062) (8,056) (45,118) a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation. b Past service costs and settlements have arisen from restructuring programmes and represent charges for special termination benefits 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 $3,046 million benefits and $2 million settlements, plus $38 million of plan expenses incurred in the administration of the benefit. e The benefit obligation for the US is made up of $7,290 million for pension liabilities and $2,406 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical liabilities). The benefit obligation for the Eurozone includes $4,328 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 174. 176 BP Annual Report and Form 20-F 2018 24. Pensions and other post-retirement benefits – continued Analysis of the amount charged to profit or loss Current service costa Past service costb Settlementb Operating charge relating to defined benefit plans Payments to defined contribution plans Total operating charge Interest income on plan assetsa Interest on plan liabilities Other finance (income) expense Analysis of the amount recognized in other comprehensive income Actual asset return less interest income on plan assets Change in financial assumptions underlying the present value of the plan liabilities Change in demographic assumptions underlying the present value of the plan liabilities Experience gains and losses arising on the plan liabilities Remeasurements recognized in other comprehensive income Movements in benefit obligation during the year Benefit obligation at 1 January Exchange adjustments Operating charge relating to defined benefit plans Interest cost Contributions by plan participantsc Benefit payments (funded plans)d Benefit payments (unfunded plans)d 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 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 357 12 — 369 31 400 (845) 831 (14) 2,396 (236) 734 91 2,985 29,908 2,886 369 831 16 (1,903) (5) — — (589) 31,513 30,180 3,048 845 16 509 (1,903) 2,396 35,091 3,578 3,838 (260) 3,578 3,838 (260) 3,578 292 — — 292 191 483 (266) 393 127 826 (514) 72 (40) 344 10,533 — 292 393 — (641) (239) 1 (1) 482 10,820 7,316 — 266 — 12 (641) 826 7,779 (3,041) 260 (3,301) (3,041) 238 (3,279) (3,041) 85 5 13 103 7 110 (37) 121 84 30 336 — (36) 330 6,820 915 103 121 2 (75) (302) — (9) (300) 7,275 1,879 264 37 2 87 (75) 30 2,224 (5,051) 43 (5,094) (5,051) (106) (4,945) (5,051) 46 (1) — 45 38 83 (48) 71 23 43 (47) (23) 14 (13) 1,715 89 45 71 6 (89) (20) — — 56 1,873 1,310 72 48 6 29 (89) 43 1,419 (454) 28 (482) (454) (101) (353) (454) $ million 2017 Total 780 16 13 809 267 1,076 (1,196) 1,416 220 3,295 (461) 783 29 3,646 48,976 3,890 809 1,416 24 (2,708) (566) 1 (10) (351) 51,481 40,685 3,384 1,196 24 637 (2,708) 3,295 46,513 (4,968) 4,169 (9,137) (4,968) 3,869 (8,837) (4,968) (31,253) (260) (31,513) (7,541) (3,279) (10,820) (2,330) (4,945) (7,275) (1,520) (353) (1,873) (42,644) (8,837) (51,481) a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation. b Past service costs and settlements have arisen from restructuring programmes and represent charges for special termination benefits 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 $3,235 million benefits and $2 million settlements, plus $37 million of plan expenses incurred in the administration of the benefit. e The benefit obligation for the US is made up of $8,085 million for pension liabilities and $2,735 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical liabilities). The benefit obligation for the Eurozone includes $4,586 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 174. BP Annual Report and Form 20-F 2018 177 24. Pensions and other post-retirement benefits – continued Analysis of the amount charged to profit or loss 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 (income) expense Analysis of the amount recognized in other comprehensive income Actual asset return less interest income on plan assets Change in financial assumptions underlying the present value of the plan liabilities Change in demographic assumptions underlying the present value of the plan liabilities Experience gains and losses arising on the plan liabilities Remeasurements recognized in other comprehensive income UK US Eurozone Other 333 17 — 350 30 380 (1,086) 1,005 (81) 4,422 (6,932) 430 55 (2,025) 310 (24) — 286 194 480 (287) 417 130 330 (239) 9 (62) 38 76 7 9 92 7 99 (47) 159 112 53 (622) 12 26 (531) 71 1 (1) 71 33 104 (51) 80 29 8 4 (5) 15 22 $ million 2016 Total 790 1 8 799 264 1,063 (1,471) 1,661 190 4,813 (7,789) 446 34 (2,496) 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. 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 2018 for the group’s plans would have had the effects shown in the table below. The effects shown for the expense in 2019 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 2019 Effect on pension and other post-retirement benefit obligation at 31 December 2018 Inflation rateb Effect on pension and other post-retirement benefit expense in 2019 Effect on pension and other post-retirement benefit obligation at 31 December 2018 Salary growth Effect on pension and other post-retirement benefit expense in 2019 Effect on pension and other post-retirement benefit obligation at 31 December 2018 $ million One percentage point Increase Decrease (337) (6,179) 227 4,919 64 653 295 8,153 (187) (4,225) (55) (595) 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 2019 pension and other post-retirement benefit expense by $52 million and the pension and other post-retirement benefit obligation at 31 December 2018 by $1,432 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 2028 and the weighted average duration of the defined benefit obligations at 31 December 2018 are as follows: Estimated future benefit payments 2019 2020 2021 2022 2023 2024-2028 Weighted average duration UK 1,030 1,036 1,056 1,088 1,120 5,777 17.8 US Eurozone Other 787 755 806 749 741 3,476 350 339 331 326 317 1,501 101 97 97 100 98 498 9.5 14.2 13.0 $ million Total 2,268 2,227 2,290 2,263 2,276 11,252 Years 178 BP Annual Report and Form 20-F 2018 25. Cash and cash equivalents Cash Term bank deposits Cash equivalents (excluding term bank deposits) 2018 6,148 13,105 3,215 22,468 $ million 2017 4,592 17,324 3,670 25,586 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 2018 includes $1,350 million (2017 $1,488 million) that is restricted. The restricted cash balances include amounts required to cover initial margin on trading exchanges and certain cash balances which are subject to exchange controls. The group holds $4,693 million (2017 $3,638 million) of cash and cash equivalents outside the UK and it is not expected that any significant tax will arise on repatriation. 26. Finance debt Borrowings Net obligations under finance leases Current Non-current 9,329 44 9,373 55,803 623 56,426 2018 Total 65,132 667 65,799 Current 7,701 38 7,739 Non-current 54,873 618 55,491 $ million 2017 Total 62,574 656 63,230 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 $7,175 million (2017 $6,849 million) and issued commercial paper of $2,040 million (2017 $744 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 4 7 4 6 4 18 4 16 Weighted average interest rate % 4 8 3 3 Amount $ million 17,593 657 18,250 18,090 895 18,985 Amount $ million 47,465 84 47,549 44,212 33 44,245 Amount $ million 2018 65,058 741 65,799 2017 62,302 928 63,230 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 2018, whereas in the group balance sheet the amount is reported within current finance debt. The carrying amount of the group’s short-term borrowings, comprising mainly of commercial paper, approximates their fair value. The fair values of the 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 analysis 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 2018 Carrying amount 2,153 62,979 667 65,799 Fair value 852 63,182 1,131 65,165 Fair value 2,153 63,106 1,087 66,346 $ million 2017 Carrying amount 852 61,722 656 63,230 BP Annual Report and Form 20-F 2018 179 27. 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 and maintain a significant liquidity buffer. At 31 December 2018, the net debt ratio was 30.3% (2017 27.4%). 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 2018 65,799 (813) 66,612 22,468 44,144 101,548 30.3% $ million 2017 63,230 (175) 63,405 25,586 37,819 100,404 27.4 % 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 $827 million (2017 liability of $634 million, 2016 liability of $1,962 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments. The movement in the year is attributable to a net cash flow of $nil (2017 net cash outflow $242 million) and fair value losses of $193 million (2017 fair value gains of $1,086 million). An analysis of changes in net debt is provided below. Movement in net debt At 1 January Adjustment on adoption of IFRS 9 Exchange adjustments Net financing cash flow Fair value gains (losses) Other movements At 31 December Finance debt Hedge- accounted derivatives Cash and cash equivalents Net debt Finance debt Hedge- accounted derivatives Cash and cash equivalents (63,230) (175) 25,586 (37,819) (58,300) (697) 23,484 2018 — 259 (3,505) 856 (179) (65,799) — — 360 (998) — (813) (11) (330) (2,777) — — 22,468 (11) (71) (5,922) (142) (179) (44,144) — (1,324) (2,236) (1,314) (56) (63,230) — — (284) 1,282 (476) (175) — 544 1,558 — — 25,586 $ million 2017 Net debt (35,513) — (780) (962) (32) (532) (37,819) a The adjustment on adoption of IFRS 9 reflects the creation of a credit loss allowance for cash and cash equivalents as a result of the new standard`s expected credit loss impairment model. 28. Operating leases The cost recognized in relation to minimum lease payments for the year was $3,514 million (2017 $4,423 million and 2016 $5,113 million). The future minimum lease payments at 31 December 2018, before deducting related rental income from operating sub-leases of $120 million (2017 $188 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 2018 2,511 5,359 4,109 11,979 $ million 2017 2,969 6,387 4,614 13,970 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 ten years for leases of plant and machinery, up to fifteen years for leases of ships and commercial vehicles and up to forty years for leases of land and buildings. The most significant items of plant and machinery hired under operating leases are drilling rigs used in the Upstream segment. At 31 December 2018, the future minimum lease payments relating to these amounted to $1,378 million (2017 $2,088 million). 180 BP Annual Report and Form 20-F 2018 28. Operating leases – continued 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 future minimum lease payments relating to operating leases for international oil and gas ships managed by the BP Shipping function amounted to $3,032 million (2017 $3,172 million). Commercial vehicles hired under operating leases are primarily railcars. Retail service station sites and office accommodation are the main items in the land and buildings category. At 31 December 2018, the future minimum lease payments relating to land and buildings amounted to $1,914 million (2017 $2,167 million). The terms and conditions of these operating leases do not impose any significant financial restrictions on the group. Some of the leases of rigs, ships and buildings allow for renewals at BP’s option, and some of the group’s operating leases contain escalation clauses. BP will adopt IFRS 16 'Leases' in the financial reporting period commencing 1 January 2019. See Note 1 for further details. 29. Financial instruments and financial risk factors The accounting classification of each category of financial instruments and their carrying amounts are set out below. Current year amounts are presented based on the classification, measurement and impairment requirements of IFRS 9. Comparatives are presented based on the classification, measurement and impairment requirements of IAS 39. At 31 December 2018 Financial assets Other investments Loans Trade and other receivables Derivative financial instruments Cash and cash equivalents Financial liabilities Trade and other payables Derivative financial instruments Accruals Finance debt Measured at amortized cost Note Mandatorily measured at fair value through profit or loss Derivative hedging instruments Total carrying amount $ million 18 20 30 25 22 30 26 — 839 24,080 — 20,366 (56,790) — (5,201) (65,799) (82,505) 1,563 124 — 8,564 2,102 — (7,685) — — 4,668 — — — 427 — — (1,248) — — (821) 1,563 963 24,080 8,991 22,468 (56,790) (8,933) (5,201) (65,799) (78,658) $ million At 31 December 2017 Financial assets Other investments – equity shares  – other Loans Trade and other receivables Derivative financial instruments Cash and cash equivalents Financial liabilities Trade and other payables Derivative financial instruments Accruals Finance debt Note Loans and receivables Available-for- sale financial assets Held-to- maturity investments At fair value through profit or loss Derivative hedging instruments Financial liabilities measured at amortized cost Total carrying amount 18 18 20 30 25 22 30 26 — — 836 24,361 — 21,916 — — — — 47,113 433 275 — — — 2,270 — — — — 2,978 — — — — — 1,400 — — — 1,400 — 662 — — 6,454 — — (5,705) — — 1,411 — — — — 688 — — (864) — — (176) — — — — — — (54,054) — (5,465) (63,230) (122,749) 433 937 836 24,361 7,142 25,586 (54,054) (6,569) (5,465) (63,230) (70,023) The fair value of finance debt is shown in Note 26. For all other financial instruments, the carrying amount is either the fair value, or approximates the fair value. Information on gains and losses on derivative financial assets and financial liabilities classified as measured at fair value through profit or loss is provided in the derivative gains and losses section of Note 30. Fair value gains and losses related to other assets and liabilities classified as measured at fair value through profit or loss totalled a net loss of $78 million. Dividend income of $8 million from investments in equity instruments classified as measured at fair value through profit or loss is presented within other income - see Note 7. Interest income and expenses arising on financial instruments are disclosed in Note 7. BP Annual Report and Form 20-F 2018 181 29. Financial instruments and financial risk factors – continued Financial risk factors The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments including market risks relating to commodity prices, foreign currency exchange rates and interest rates; credit risk; and liquidity risk. The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The GFRC is chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the group finance, tax and the integrated supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk governance framework for the group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to the board, that the group’s financial risk-taking activity is governed by appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with group policies and group risk appetite. The group’s trading activities in the oil, natural gas, LNG and power markets are managed within the integrated supply and trading function. Treasury holds foreign exchange and interest-rate products in the financial markets to hedge group exposures related to debt issuance; the compliance, control, and risk management processes for these activities are managed within the treasury function. All other foreign exchange and interest rate activities within financial markets are performed within the integrated supply and trading function and are also underpinned by the compliance, control and risk management infrastructure common to the activities of BP’s integrated supply and trading function. All derivative activity is carried out by specialist teams that have the appropriate skills, experience and supervision. These teams are subject to close financial and management control. The integrated supply and trading function maintains formal governance processes that provide oversight of market risk, credit risk and operational risk associated with trading activity. A policy and risk committee approves value-at-risk delegations, reviews incidents and validates risk-related policies, methodologies and procedures. A commitments committee approves the trading of new products, instruments and strategies and material commitments. In addition, the integrated supply and trading function undertakes derivative activity for risk management purposes under a control framework as described more fully below. (a) Market risk Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The primary commodity price risks that the group is exposed to include oil, natural gas and power prices that could adversely affect the value of the group’s financial assets, liabilities or expected future cash flows. The group enters into derivatives in a well-established entrepreneurial trading operation. In addition, the group has developed a control framework aimed at managing the volatility inherent in certain of its natural business exposures. In accordance with the control framework the group enters into various transactions using derivatives for risk management purposes. The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed below. (i) Commodity price risk The group’s integrated supply and trading function 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 Since BP has global operations, fluctuations in foreign currency exchange rates can have a significant effect on the group’s reported results and future expenditure commitments. The effects of most exchange rate fluctuations are absorbed in business operating results through changing cost competitiveness, lags in market adjustment to movements in rates and translation differences accounted for on specific transactions. For this reason, the total effect of exchange rate fluctuations is not identifiable separately in the group’s reported results. The main underlying economic currency of the group’s cash flows is the US dollar. This is because BP’s major product, oil, is priced internationally in US dollars. BP’s foreign currency exchange management policy is to limit economic and material transactional exposures arising from currency movements against the US dollar. The group co-ordinates the handling of foreign currency exchange risks centrally, by netting off naturally-occurring opposite exposures wherever possible and then managing any material residual foreign currency exchange risks. Most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2018, the total foreign currency borrowings not swapped into US dollars amounted to $741 million (2017 $928 million). The group manages the net residual foreign currency exposures by constantly reviewing the foreign currency economic value at risk and aims to manage such risk to keep the 12-month foreign currency value at risk below $400 million. At no point over the past three years did the value at risk exceed the maximum risk limit. A continuous assessment is made in respect to the group’s foreign currency exposures to capture hedging requirements. During the year, hedge accounting was applied to foreign currency exposure to highly probable forecast capital expenditure commitments. The group fixes the US dollar cost of non-US dollar supplies by using currency forwards for the highly probable forecast capital expenditure; the exposures are in sterling, euro, Australian dollar, Norwegian krone and Korean won. At 31 December 2018 the most significant open contracts in place were for $434 million sterling (2017 $437 million sterling). Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading value-at-risk techniques as explained in (i) commodity price risk above. 182 BP Annual Report and Form 20-F 2018 29. Financial instruments and financial risk factors – continued (iii) Interest rate risk BP is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial instruments, principally finance debt. While the group issues debt 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 2018 was 72% of total finance debt outstanding (2017 70%). The weighted average interest rate on finance debt at 31 December 2018 was 4% (2017 3%) and the weighted average maturity of fixed rate debt was five years (2017 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 changed by one percentage point on 1 January 2019, it is estimated that the group’s finance costs for 2019 would change by approximately $475 million (2017 $442 million). (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 2018 was $696 million (2017 $656 million) in respect of liabilities of joint ventures and associates and $432 million (2017 $382 million) in respect of liabilities of other third parties. The group has a credit policy, approved by the CFO that is designed to ensure that consistent processes are in place throughout the group to measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business contract the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy include segregation of credit approval authorities from any sales, marketing or trading teams authorized to incur credit risk; the establishment of credit systems and processes to ensure that all counterparty exposure is rated and that all counterparty exposure and limits can be monitored and reported; and the timely identification and reporting of any non-approved credit exposures and credit losses. While each segment is responsible for its own credit risk management and reporting consistent with group policy, the treasury function holds group-wide credit risk authority and oversight responsibility for exposure to banks and financial institutions. For the purposes of financial reporting the group calculates expected loss allowances based on the maximum contractual period over which the group is exposed to credit risk. Since this is typically less than 12 months for the group's in-scope financial assets there is no significant difference between the measurement of 12-month and lifetime expected credit losses. The group has no significant financial guarantee liabilities measured on an expected loss basis. Financial assets are considered to be credit-impaired when there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset have occurred. This includes observable data concerning significant financial difficulty of the counterparty; a breach of contract; concession being granted to the counterparty for economic or contractual reasons relating to the counterparty’s financial difficulty, that would not otherwise be considered; it becoming probable that the counterparty will enter bankruptcy or other financial re-organization or an active market for the financial asset disappearing because of financial difficulties. The group also applies a rebuttable presumption that an asset is credit-impaired when contractual payments are more than 30 days past due. Where the group has no reasonable expectation of recovering a financial asset in its entirety or a portion thereof for example where all legal avenues for collection of amounts due have been exhausted, the financial asset (or relevant portion) is written off. The measurement of expected credit losses is a function of the probability of default, loss given default (i.e. the magnitude of the loss after recovery if there is a default) and the exposure at default (i.e. the asset's carrying amount). The group allocates a credit risk rating to exposures based on data that is determined to be predictive of the risk of loss, including but not limited to external ratings. Probabilities of default derived from historical, current and future-looking market data are assigned by credit risk rating with a loss given default based on historical experience and relevant market and academic research applied by exposure type. Experienced credit judgement is applied to ensure probabilities of default are reflective of the credit risk associated with the group's exposures. Credit enhancements that would reduce the group's credit losses in the event of default are reflected in the calculation when they are considered integral to the related asset. The maximum credit exposure associated with financial assets is equal to the carrying amount. The group does not aim to remove credit risk entirely but expects to experience a certain level of credit losses. As at 31 December 2018, the group had in place credit enhancements designed to mitigate approximately $7.3 billion of credit risk, of which $6.7 billion relates to assets in the scope of IFRS 9's impairment requirements. Credit enhancements include standby and documentary letters of credit, bank guarantees, insurance and liens which are typically taken out with financial institutions who have investment grade credit ratings, or are liens over assets held by the counterparty of the related receivables. Reports are regularly prepared and presented to the GFRC that cover the group’s overall credit exposure and expected loss trends, exposure by segment, and overall quality of the portfolio. Management information used to monitor credit risk, which reflects the impact of credit enhancements, indicates that the risk profile of financial assets which are subject to review for impairment under IFRS 9 is as set out below. As at 31 December AAA to AA- A+ to A- BBB+ to BBB- BB+ to BB- B+ to B- CCC+ and below For the comparative period an analysis of the ageing of trade and other receivables reported under IAS 39 is provided. % 2018 22% 41% 16% 8% 11% 2% BP Annual Report and Form 20-F 2018 183 29. Financial instruments and financial risk factors – continued 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 $ million 2017 22,858 53 637 130 114 569 24,361 Movements in the impairment provision for trade and other receivables are shown in Note 21. Financial instruments subject to offsetting, enforceable master netting arrangements and similar agreements The following table shows the amounts recognized for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the balance sheet. Amounts which cannot be offset under IFRS, but which could be settled net under the terms of master netting agreements if certain conditions arise, and collateral received or pledged, are also presented in the table to show the total net exposure of the group. At 31 December 2018 Derivative assets Derivative liabilities Trade and other receivables Trade and other payables At 31 December 2017 Derivative assets Derivative liabilities Trade and other receivables Trade and other payables Gross amounts of recognized financial assets (liabilities) 11,502 (11,337) 11,296 (10,797) 8,522 (7,818) 11,648 (12,543) Related amounts not set off in the balance sheet $ million Net amounts presented on the balance sheet Master netting arrangements Cash collateral (received) pledged Net amount 8,991 (8,826) 5,906 (5,407) 7,142 (6,438) 6,337 (7,232) (2,079) 2,079 (1,020) 1,020 (1,554) 1,554 (2,156) 2,156 (299) — (169) — (321) — (114) — 6,613 (6,747) 4,717 (4,387) 5,267 (4,884) 4,067 (5,076) Amounts set off (2,511) 2,511 (5,390) 5,390 (1,380) 1,380 (5,311) 5,311 (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. BP utilizes various arrangements in order to manage its working capital including discounting of receivables and, in the supply and trading business, the active management of supplier payment terms, inventory and collateral. In line with normal industry practice some supplier arrangements utilize letter of credit (LC) facilities. In certain of those arrangements BP’s payments are made to the provider of the LC rather than the supplier. Standard & Poor’s Ratings long-term credit rating for BP is A- (stable outlook) and Moody’s Investors Service rating is A1 (stable outlook). During 2018, $9 billion of long-term taxable bonds were issued with terms ranging from four to ten 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 $22.5 billion at 31 December 2018 (2017 $25.6 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate and short notice. At 31 December 2018, the group had substantial amounts of undrawn borrowing facilities available, consisting of $7,625 million of standby facilities, all of which is available to draw and repay up to the first half of 2022. These facilities are with 25 international banks, and borrowings under them would be at pre-agreed rates. The group has committed LC facilities totalling $12,175 million with a number of banks, allowing LCs to be issued for a maximum 24-month duration. There were also uncommitted secured LC facilities in place at 31 December 2018 for $4,190 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. 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. 184 BP Annual Report and Form 20-F 2018 29. Financial instruments and financial risk factors – continued 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 43,230 2,232 1,662 1,484 1,406 6,058 5,001 61,073 Accruals 4,626 146 95 64 89 113 68 5,201 2018 Interest on finance debt 2,404 1,955 1,700 1,422 1,138 2,390 320 11,329 Finance debt 9,301 6,788 6,805 8,057 7,058 25,356 1,243 64,608 Trade and other payablesa 40,472 1,693 1,413 1,378 1,368 6,181 6,125 58,630 Accruals 4,960 135 83 70 54 115 48 5,465 Finance debt 7,626 7,331 7,068 6,766 7,986 24,162 2,089 63,028 $ million 2017 Interest on finance debt 1,757 1,537 1,321 1,114 894 1,951 390 8,964 a 2018 includes $18,360 million (2017 $18,918 million) in relation to the 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 30. 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 finance 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 $22,453 million at 31 December 2018 (2017 $21,484 million) to be received on the same day as the related cash outflows. For further information on our derivative financial instruments, see Note 30. 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 2018 1,700 1,678 2,384 2,838 2,906 11,475 724 23,705 $ million 2017 1,505 1,700 1,678 2,384 2,838 11,238 724 22,067 30. Derivative financial instruments In the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate debt, consistent with risk management policies and objectives. An outline of the group’s financial risks and the objectives and policies pursued in relation to those risks is set out in Note 29. Additionally, the group has a well-established entrepreneurial trading operation that is undertaken in conjunction with these activities using a similar range of contracts. For information on significant estimates and judgements made in relation to the valuation of derivatives see Derivative financial instruments within Note 1. The fair values of derivative financial instruments at 31 December are set out below. Exchange traded derivatives are valued using closing prices provided by the exchange as at the balance sheet date. These derivatives are categorized within level 1 of the fair value hierarchy. Exchange traded derivatives are typically considered settled through the (normally daily) payment or receipt of variation margin. Over-the-counter (OTC) financial swaps and physical commodity sale and purchase contracts are generally valued using readily available information in the public markets and quotations provided by brokers and price index developers. These quotes are corroborated with market data and are categorized within level 2 of the fair value hierarchy. In certain less liquid markets, or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC financial swaps and physical commodity sale and purchase contracts are valued using internally developed methodologies that consider historical relationships between various commodities, and that result in management’s best estimate of fair value. These contracts are categorized within level 3 of the fair value hierarchy. 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. BP Annual Report and Form 20-F 2018 185 30. Derivative financial instruments – continued 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 Gas price futures Fair value hedges Currency forwards, futures and swaps Interest rate swaps Of which – current – non-current Fair value asset 2018 Fair value liability 69 2,361 4,787 1,240 107 8,564 — — — 5 2 7 158 262 420 8,991 3,846 5,145 (898) (1,849) (3,888) (943) — (7,578) — (107) (107) (14) — (14) (789) (445) (1,234) (8,933) (3,308) (5,625) Fair value asset 237 1,637 3,580 885 115 6,454 — — — 35 — 35 460 193 653 7,142 3,032 4,110 $ million 2017 Fair value liability (756) (1,281) (2,844) (693) — (5,574) (16) (115) (131) (35) — (35) (523) (306) (829) (6,569) (2,808) (3,761) Derivatives held for trading The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective, and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of contract types in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of these exposures is monitored using market value-at-risk techniques as described in Note 29. The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes. Derivative assets held for trading have the following fair values and maturities. 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 48 1,916 1,333 540 — 3,837 Less than 1 year 186 1,280 1,122 420 — 3,008 1-2 years 2-3 years 3-4 years 4-5 years 12 363 708 276 — 1,359 9 53 542 158 — 762 — 25 452 79 — 556 — 4 352 55 107 518 1-2 years 2-3 years 3-4 years 4-5 years 31 177 609 188 — 1,005 8 99 428 81 — 616 5 66 328 60 — 459 3 14 288 38 — 343 $ million 2018 Total 69 2,361 4,787 1,240 107 8,564 $ million 2017 Total 237 1,637 3,580 885 115 6,454 Over 5 years — — 1,400 132 — 1,532 Over 5 years 4 1 805 98 115 1,023 186 BP Annual Report and Form 20-F 2018 30. Derivative financial instruments – continued Derivative liabilities held for trading have the following fair values and maturities. Currency derivatives Oil price derivatives Natural gas price derivatives Power price derivatives Currency derivatives Oil price derivatives Natural gas price derivatives Power price derivatives Less than 1 year (299) (1,560) (1,030) (401) (3,290) Less than 1 year (92) (1,120) (973) (337) (2,522) 1-2 years 2-3 years 3-4 years 4-5 years (71) (232) (557) (213) (1,073) (256) (43) (391) (95) (785) (171) (12) (338) (54) (575) (3) (2) (285) (47) (337) 1-2 years 2-3 years 3-4 years 4-5 years (232) (118) (410) (134) (894) (66) (33) (334) (63) (496) (188) (4) (224) (39) (455) (99) (6) (194) (29) (328) $ million 2018 Total (898) (1,849) (3,888) (943) (7,578) $ million 2017 Total (756) (1,281) (2,844) (693) (5,574) Over 5 years (98) — (1,287) (133) (1,518) Over 5 years (79) — (709) (91) (879) The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by methodology of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty. Fair value of derivative assets Level 1 Level 2 Level 3 Less: netting by counterparty Fair value of derivative liabilities Level 1 Level 2 Level 3 Less: netting by counterparty Net fair value Fair value of derivative assets Level 2 Level 3 Less: netting by counterparty Fair value of derivative liabilities Level 2 Level 3 Less: netting by counterparty Net fair value Less than 1 year 111 5,000 491 5,602 (1,765) 3,837 (156) (4,562) (337) (5,055) 1,765 (3,290) 547 Less than 1 year 3,663 386 4,049 (1,041) 3,008 (3,338) (225) (3,563) 1,041 (2,522) 486 1-2 years 2-3 years 3-4 years 4-5 years 14 1,362 385 1,761 (402) 1,359 (11) (1,161) (303) (1,475) 402 (1,073) 286 3 504 353 860 (98) 762 (2) (576) (305) (883) 98 (785) (23) — 262 331 593 (37) 556 (2) (308) (302) (612) 37 (575) (19) — 120 427 547 (29) 518 — (67) (299) (366) 29 (337) 181 1-2 years 2-3 years 3-4 years 4-5 years 1,003 258 1,261 (256) 1,005 (953) (197) (1,150) 256 (894) 111 438 231 669 (53) 616 (358) (191) (549) 53 (496) 120 244 226 470 (11) 459 (289) (177) (466) 11 (455) 4 140 211 351 (8) 343 (163) (173) (336) 8 (328) 15 $ million 2018 Total 128 7,320 3,627 11,075 (2,511) 8,564 (171) (6,837) (3,081) (10,089) 2,511 (7,578) 986 $ million 2017 Total 5,623 2,211 7,834 (1,380) 6,454 (5,267) (1,687) (6,954) 1,380 (5,574) 880 Over 5 years — 72 1,640 1,712 (180) 1,532 — (163) (1,535) (1,698) 180 (1,518) 14 Over 5 years 135 899 1,034 (11) 1,023 (166) (724) (890) 11 (879) 144 BP Annual Report and Form 20-F 2018 187 30. Derivative financial instruments – continued Level 3 derivatives The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair value hierarchy. Fair value contracts at 1 January 2018 Gains (losses) recognized in the income statement Settlements Transfers out of level 3 Net fair value of contracts at 31 December 2018 Deferred day-one gains (losses) Derivative asset (liability) Fair value contracts at 1 January 2017 Gains (losses) recognized in the income statement Settlements Transfers out of level 3 Net fair value of contracts at 31 December 2017 Deferred day-one gains (losses) Derivative asset (liability) Oil price 67 58 (107) 5 23 Natural gas price 65 (26) (32) (20) (13) Oil price 68 76 (68) (9) 67 Natural gas price 145 161 (35) (206) 65 Power price (226) 209 (97) (34) (148) Power price (147) 61 (113) (27) (226) Other 115 (8) — — 107 Other 231 15 (131) — 115 $ million Total 21 233 (236) (49) (31) 577 546 $ million Total 297 313 (347) (242) 21 503 524 The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2018 was a $123-million gain (2017 $234-million gain related to derivatives still held at 31 December 2017). Derivative gains and losses The group enters into derivative contracts including futures, options, swaps and certain forward sales and forward purchases contracts, relating to both currency and commodity trading activities. Gains or losses arise on contracts entered into for risk management purposes, optimization activity and entrepreneurial trading. They also arise on certain contracts that are for normal procurement or sales activity for the group but that are required to be fair valued under accounting standards. These gains and losses are included within sales and other operating revenues in the income statement. Also included within this line item are gains and losses on inventory held for trading purposes. The total amount relating to all these items (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 $2,504 million (2017 $1,983 million net gain and 2016 $1,435 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 amounts for actual gains and losses relating to these derivative contracts and all related items therefore differ significantly from the amounts disclosed above. The group also enters into derivative contracts including futures, options, swaps and certain forward sales and forward purchase contracts primarily relating to foreign currency risk management activities. Gains and losses on these contracts are included within production and manufacturing expenses in the income statement. The change in the unrealized value of these contracts was a net loss of $351 million (2017 $1,420 million net gain and 2016 $154 million net loss), however the gains and losses in each year are largely offset by opposing net foreign exchange differences on retranslation of the associated non-US dollar debt. The net amounts for actual gains and losses relating to these derivative contracts and all related items therefore differ significantly from the amounts disclosed above. Cash flow hedges (i) Foreign currency risk of highly probable forecast capital expenditure At 31 December 2018, the group held currency forwards designated as hedging instruments in cash flow hedge relationships of highly probable forecast non-US dollar capital expenditure. Note 29 outlines the group’s approach to foreign currency exchange risk management. When the highly probable forecast capital expenditure designated as a hedged item occurs, a non-financial asset is recognized and is presented within the fixed asset section of the balance sheet. The group claims hedge accounting only for the spot value of the currency exposure in line with the strategy to fix the volatility in the spot exchange rate element. The fair value on the instrument attributable to forward points is taken immediately to the income statement. The group applies hedge accounting where there is an economic relationship between the hedged item and hedging instrument. The existence of an economic relationship is determined at inception and prospectively by comparing the critical terms of the hedging instrument and those of the hedged item. The group enters into hedging derivatives that match the currency and notional of the hedged items on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional amount of the derivative with the notional designated on the forecast transaction. The group determines the extent to which it hedges highly probable forecast capital expenditures on a project by project basis. The group has identified the following sources of ineffectiveness, which are not expected to be material: • counterparty's credit risk, the group mitigates counterparty credit risk by entering into derivative transactions with high credit quality counterparties; and • differences in settlement timing between the derivative and hedged items. The latter impacts the discount factor used in the calculation of the hedge ineffectiveness. The group mitigates differences in timing between the derivatives and hedged items by applying a rolling strategy and by hedging currency pairs from stable economies (i.e. sterling/US dollar, Euro/US dollar, Norwegian krone/US dollar, Korean won/US dollar). The group's cash flow hedge designations are highly effective as the sources of ineffectiveness identified are expected to result in minimal hedge ineffectiveness. The group has not designated any net positions as hedged items in cash flow hedges of foreign currency risk. 188 BP Annual Report and Form 20-F 2018 30. Derivative financial instruments – continued (ii) Commodity price risk of highly probable forecast sales At 31 December 2018, the group held Henry Hub NYMEX futures designated as hedging instruments in cash flow hedge relationships of certain highly probable forecast future sales. The group is exposed to the variability in the gas price, but only applies hedge accounting to the risk of Henry Hub price movements for a percentage of future gas sales from its BPX Energy business (previously known as US Lower 48 business). Hedge accounting may be applied to such sales for up to the following two calendar years. The group applies hedge accounting in relation to these highly probable future sales where there is an economic relationship between the hedged item and hedging instrument. The existence of an economic relationship is determined at inception and prospectively by comparing the critical terms of the hedging instrument and those of the hedged item. The group enters into hedging derivatives that match the notional amounts of the hedged items on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional amount of the derivative with the notional amount designated on the forecast transaction. The hedge is expected to be highly effective due to the price index of the hedging instruments matching the price index of the hedged item and the derivative assets or liabilities recognized in respect of exchange-traded instruments reflect the impact of daily margin payments and receipts. The group has not designated any net positions as hedged items in cash flow hedges of commodity price risk. The table below summarizes the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the period. At 31 December 2018 Cash flow hedges Foreign exchange risk Highly probable forecast capital expenditure Commodity price risk Highly probable forecast sales Change in fair value of hedging instrument used to calculate ineffectiveness Change in fair value of hedged item used to calculate ineffectiveness $ million Hedge ineffectiveness recognized in profit or (loss) (5) (126) 5 126 — — The table below summarizes the carrying amount and nominal amount of the derivatives designated as hedging instruments in cash flow hedge relationships at 31 December 2018. At 31 December 2018 Cash flow hedges Foreign exchange risk Highly probable forecast capital expenditure Commodity price risk Highly probable forecast sales Carrying amount of hedging instrument Assets Liabilities Nominal amounts of hedging instruments $ million $ million $ million mmBtu 5 2 (14) — 386 145 All hedging instruments are presented within derivative financial instruments on the group balance sheet. Of the nominal amount of hedging instruments relating to highly probable forecast capital expenditure $304 million matures in 2019 and $82 million matures in 2020. All of the hedging instruments relating to highly probable forecast sales mature in 2019. The table below summarizes the weighted average exchange rates and the weighted average sales price in relation to the derivatives designated as hedging instruments in cash flow hedge relationships at 31 December 2018. At 31 December 2018 Sterling/US dollar Euro/US dollar Australian dollar/US dollar Norwegian krone/US dollar Korean won/US dollar Henry Hub $/mmBtu Weighted average price/rate Forecast capital expenditure 1.34 1.14 0.72 8.67 1,107.90 Forecast sales 2.86 BP Annual Report and Form 20-F 2018 189 30. Derivative financial instruments – continued Fair value hedges At 31 December 2018, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk and foreign currency risk arising from group fixed rate debt issuances. The interest rate swaps are used to convert US dollar denominated fixed rate borrowings into floating rate debt. The cross-currency interest rate swaps are used to convert sterling, euro, Swiss franc, Australian dollar, Canadian dollar and Norwegian krone denominated fixed rate borrowings into US dollar floating rate debt. The group manages all risks derived from debt issuance, such as credit risk, however, the group applies hedge accounting only to certain components of interest rate and foreign currency risk in order to minimize hedge ineffectiveness. Note 29 outlines the group’s approach to interest rate and foreign currency exchange risk management. The interest rate and foreign currency exposures are identified and hedged on an instrument-by-instrument basis. For interest rate exposures, the group designates as a fair value hedge the benchmark interest rate component only. This is an observable and reliably measurable component of interest rate risk. For foreign currency exposures, the group excludes from the designation the foreign currency basis spread component implicit in the cross-currency interest rate swaps. This is separately calculated at hedge designation, is recognized in other comprehensive income over the life of the hedge and amortized to the income statement on a straight-line basis, in accordance with the group’s policy on costs of hedging. The group applies hedge accounting where there is an economic relationship between the hedged item and the hedging instrument. The existence of an economic relationship is determined initially by comparing the critical terms of the hedging instrument and those of the hedged item and it is prospectively assessed using linear regression analysis. The group issues fixed rate debt and enters into interest rate and cross- currency interest rate swaps with critical terms that match those of the debt and on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional amount of the derivative with the notional amount of the debt. The hedge relationship is designated for the full term and notional value of the debt. Both the hedging instrument and the hedged item are expected to be held to maturity. The group has identified the following sources of ineffectiveness, which are not expected to be material: • derivative counterparty’s credit risk which is not offset by the hedged item. This risk is mitigated by entering into derivative transactions only with high credit quality counterparties; and • sensitivity to interest rate between the hedged item and the derivatives. This is driven by differences in payment frequencies between the instrument and the bond. The table below summarizes the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the period. At 31 December 2018 Fair value hedges Interest rate risk on finance debt Interest rate and foreign currency risk on finance debt Change in fair value of hedging instrument used to calculate ineffectiveness Change in fair value of hedged item used to calculate ineffectiveness $ million Hedge ineffectiveness recognized in profit or (loss) (70) 812 69 (809) (1) 3 The table below summarizes the carrying amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31 December 2018. At 31 December 2018 Fair value hedges Interest rate risk on finance debt Interest rate and foreign currency risk on finance debt $ million Carrying amount of hedging instrument Assets Liabilities Nominal amounts of hedging instruments 262 158 (445) (789) 24,513 16,580 All hedging instruments are presented within derivative financial instruments on the group balance sheet. Ineffectiveness arising on fair value hedges is included within the production and manufacturing expenses section of the income statement. The table below summarizes the profile by tenor of the nominal amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31 December 2018. The weighted average floating interest rate of these interest rate swaps and cross-currency interest rate swaps was 3.04% and 4.07% respectively. At 31 December 2018 Fair value hedges Interest rate risk on finance debt Interest rate and foreign currency risk on finance debt Less than 1 year 1-2 years 2-3 years 3-4 years 4-5 years 5-10 years Over 10 years Total $ million 2,694 — 2,324 1,245 2,597 1,167 4,923 1,700 10,275 707 2,921 10,254 — 286 24,513 16,580 190 BP Annual Report and Form 20-F 2018 30. Derivative financial instruments – continued The table below summarizes the carrying amount, and the accumulated fair value adjustments included within the carrying amount, of the hedged items designated in fair value hedge relationships at 31 December 2018. At 31 December 2018 Fair value hedges Carrying amount of hedged item Accumulated fair value adjustment included in the carrying amount of hedged items $ million Assets Liabilities Assets Liabilities Discontinued hedges Interest rate risk on finance debt Interest rate and foreign currency risk on finance debt — — (24,747) (16,883) 175 — — (62) (360) — The hedged item for all fair value hedges is presented within finance debt on the group balance sheet. Movement in reserves related to hedge accounting The table below provides a reconciliation of the cash flow hedge and costs of hedging reserves on a pre-tax basis by risk category. The signage convention of this table is consistent with that presented in Note 32. Cash flow hedge reserve Highly probable forecast capital expenditure Highly probable forecast sales Purchase of equitya At 31 December 2017 Adjustment on adoption of IFRS 9 At 1 January 2018 Recognized in other comprehensive income Cash flow hedges marked to market Cash flow hedges reclassified to the income statement - hedged item affected profit or loss Costs of hedging marked to market Costs of hedging reclassified to the income statement Cash flow hedges transferred to the balance sheet At 31 December 2018 a See Note 32 for further information on the cash flow hedge reserve relating to the purchase of equity (10) — (10) (37) — — — (37) 26 (21) — — — (126) 120 — — (6) — (6) (651) — (651) — — — — — — (651) Costs of hedging reserve Interest rate and foreign currency risk on finance debt — (37) (37) — — (244) 58 (186) — (223) $ million Total (661) (37) (698) (163) 120 (244) 58 (229) 26 (901) Substantially all of the cash flow hedge reserve balances and all of the amounts reclassified into profit or loss during the year relate to continuing hedge relationships. Amounts deferred in the cash flow hedge reserve that have been reclassified to profit or loss are presented in sales and other operating revenues in the income statement. Costs of hedging relates to the foreign currency basis spreads of hedging instruments used to hedge the group's interest rate and foreign currency risk on debt which is a time-period related item. BP Annual Report and Form 20-F 2018 191 31. Called-up share capital The allotted, called up and fully paid share capital at 31 December was as follows: Issued 8% cumulative first preference shares of £1 eacha 9% cumulative second preference shares of £1 eacha Ordinary shares of 25 cents each At 1 January Issue of new shares for the scrip dividend programme Issue of new shares for employee share-based payment plans Issue of new shares – otherb Repurchase of ordinary share capital At 31 December Shares thousand 7,233 5,473 2018 $ million 12 9 21 Shares thousand 7,233 5,473 2017 $ million 12 9 21 Shares thousand 7,233 5,473 21,288,193 195,305 5,322 49 21,049,696 289,789 5,263 72 20,108,771 548,005 92,168 — (50,202) 21,525,464 — — (51,292) 21,288,193 23 — (13) 5,381 5,402 — 392,920 — 21,049,696 — — (13) 5,322 5,343 2016 $ million 12 9 21 5,028 137 — 98 — 5,263 5,284 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 2016 relates to the issue of new ordinary shares in consideration for a 10% interest in the Abu Dhabi onshore oil concession. See Note 32 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. During 2018 the company repurchased 50 million ordinary shares for a total consideration of $355 million, including transaction costs of $2 million, as part of the share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The repurchased shares represented 0.2% of ordinary share capital. Treasury sharesa At 1 January Purchases for settlement of employee share plans Issue of new shares for employee share-based payment plans Shares re-issued for employee share-based payment plans At 31 December Of which – shares held in treasury by BP – shares held in ESOP trusts – shares held by BP’s US share plan administratorb 2018 Shares thousand 1,482,072 757 Nominal value $ million 370 — Shares thousand 1,614,657 4,423 2017 Nominal value $ million 403 1 Shares thousand 1,756,327 9,631 2016 Nominal value $ million 439 2 92,168 23 — — — (148,732) (37) (137,008) (34) (151,301) 1,426,265 1,264,732 161,518 15 356 316 40 — 1,482,072 1,472,343 9,705 24 370 368 2 — 1,614,657 1,576,411 21,432 16,814 — (38) 403 394 5 4 a See Note 32 for definition of treasury shares. b Held in the form of ADSs to meet the requirements of employee share-based payment plans in the US. For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by BP during the year, representing 6.9% (2017 7.5% and 2016 8.6%) of the called-up ordinary share capital of the company. During 2018, the movement in shares held in treasury by BP represented less than 1.0% (2017 less than 0.5% and 2016 less than 0.8%) of the ordinary share capital of the company. 192 BP Annual Report and Form 20-F 2018 THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY BP Annual Report and Form 20-F 2018 193 32. Capital and reserves At 31 December 2017 Adjustment on adoption of IFRS 9, net of tax At 1 January 2018 Profit (loss) for the year Items that may be reclassified subsequently to profit or loss Currency translation differences (including reclassifications) Cash flow hedges and costs of hedging (including reclassifications) Share of items relating to equity-accounted entities, net of taxa Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Cash flow hedges that will subsequently be transferred to the balance sheet Total comprehensive income Dividends Cash flow hedges transferred to the balance sheet, net of tax Repurchases of ordinary share capital Share-based payments, net of taxb Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests, net of tax At 31 December 2018 At 1 January 2017 Profit (loss) for the year Items that may be reclassified subsequently to profit or loss Currency translation differences (including reclassifications) Available-for-sale investments (including reclassifications) Cash flow hedges (including reclassifications) Share of items relating to equity-accounted entities, net of taxa Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Total comprehensive income Dividends Repurchases of ordinary share capital Share-based payments, net of taxb Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests, net of taxc At 31 December 2017 At 1 January 2016 Profit (loss) for the year Items that may be reclassified subsequently to profit or loss Currency translation differences (including reclassifications)a Available-for-sale investments (including reclassifications) Cash flow hedges (including reclassifications) Share of items relating to equity-accounted entities, net of taxa Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Total comprehensive income Dividends Share-based payments, net of taxb d Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests, net of tax At 31 December 2016 a Principally foreign exchange effects relating to the Russian rouble. b Movements in treasury shares relate to employee share-based payment plans. 194 BP Annual Report and Form 20-F 2018 Share capital Share premium account Capital redemption reserve Merger reserve — 5,343 12,147 — 5,343 12,147 — — — 1,426 27,206 — 1,426 27,206 — — — — — — — — — — — — — 49 — (13) 23 — — — — — (49) — — 207 — — 5,402 12,305 — — — — — — — — — — — — — 13 — — — — — — — — — — — — 1,439 27,206 Total share capital and capital reserves 46,122 — 46,122 — — — — — — — — — — — 230 — — 46,352 Share capital Share premium account Capital redemption reserve Merger reserve 5,284 12,219 — — 1,413 27,206 — — Total share capital and capital reserves 46,122 — — — — — — — — — — — — — 72 (13) — — — — — (72) — — — — 5,343 12,147 — — — — — — — — — — — — — 13 — — — — — — — — — — 1,426 27,206 — — — — — — — — — — — — 46,122 Share capital Share premium account Capital redemption reserve Merger reserve 5,049 10,234 — — 1,413 27,206 — — Total share capital and capital reserves 43,902 — — — — — — — — — — — — — — — — — — — — — — — 137 98 — — — — (137) 2,122 — — 5,284 12,219 — — — — — — — — — — — — 1,413 27,206 — — — — — — — — 2,220 — — 46,122 32. Capital and reserves – continued Treasury shares (16,958) — (16,958) — — — — — — — — — — — 1,191 — — (15,767) Treasury shares (18,443) — — — — — — — — — — 1,485 — — (16,958) Treasury shares (19,964) — — — — — — — — — 1,521 — — (18,443) Foreign currency translation reserve (5,156) — (5,156) — (3,746) — — — — — (3,746) — — — — — — (8,902) Foreign currency translation reserve (6,878) — 1,722 — — — — — 1,722 — — — — — (5,156) Foreign currency translation reserve (7,267) — 389 — — — — — 389 — — — — (6,878) Available- for-sale investments Cash flow hedges Costs of hedging Total fair value reserves Profit and loss account BP shareholders’ equity Non- controlling interests 17 (17) — — — — — — — — — — — — — — — — Available- for-sale investments 3 — — 14 — — — — 14 — — — — — 17 (760) — (760) — — (6) — — — (37) (43) — 26 — — — — (777) Cash flow hedges (1,156) — — — 396 — — — 396 — — — — — (760) — (37) (37) — — (173) — — — — (173) — — — — — — (210) Costs of hedging — — — — — — — — — — — — — — — Available- for-sale investments Cash flow hedges Costs of hedging 2 — — 1 — — — — 1 — — — — 3 (825) — — — (331) — — — (331) — — — — (1,156) — — — — — — — — — — — — — — (743) (54) (797) — — (179) — — — (37) (216) — 26 — — — — (987) Total fair value reserves (1,153) — — 14 396 — — — 410 — — — — — (743) Total fair value reserves (823) — — 1 (331) — — — (330) — — — — (1,153) 75,226 (126) 75,100 9,383 — — 417 7 1,599 — 11,406 (6,699) — (355) (718) 14 — 78,748 Profit and loss account 75,638 3,389 (3) — — 564 (72) 2,343 6,221 (6,153) (343) (798) 215 446 75,226 Profit and loss account 81,368 115 — — — 833 (96) (1,757) (905) (4,611) (750) 106 430 75,638 98,491 (180) 98,311 9,383 (3,746) (179) 417 7 1,599 (37) 7,444 (6,699) 26 (355) 703 14 — 99,444 1,913 — 1,913 195 (41) — — — — — 154 (170) — — — — 207 2,104 BP shareholders’ equity 95,286 3,389 Non- controlling interests 1,557 79 1,719 14 396 564 (72) 2,343 8,353 (6,153) (343) 687 215 446 98,491 52 — — — — — 131 (141) — — — 366 1,913 BP shareholders’ equity 97,216 115 Non- controlling interests 1,171 57 389 1 (331) 833 (96) (1,757) (846) (4,611) 2,991 106 430 95,286 (27) — — — — — 30 (107) — — 463 1,557 $ million Total equity 100,404 (180) 100,224 9,578 (3,787) (179) 417 7 1,599 (37) 7,598 (6,869) 26 (355) 703 14 207 101,548 Total equity 96,843 3,468 1,771 14 396 564 (72) 2,343 8,484 (6,294) (343) 687 215 812 100,404 Total equity 98,387 172 362 1 (331) 833 (96) (1,757) (816) (4,718) 2,991 106 893 96,843 c Principally relates to the initial public offering of common units in BP Midstream Partners LP for which net proceeds of $811 million were received. d 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. BP Annual Report and Form 20-F 2018 195 32. Capital and reserves – continued Share capital The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury shares. Share premium account The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares. Capital redemption reserve The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled. Merger reserve The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in an acquisition made by the issue of shares. Treasury shares Treasury shares represent BP shares repurchased and available for specific and limited purposes. For accounting purposes shares held in Employee Share Ownership Plans (ESOPs) and BP’s US share plan administrator to meet the future requirements of the employee share- based payment plans are treated in the same manner as treasury shares and are, therefore, included in the financial statements as treasury shares. The ESOPs are funded by the group and have waived their rights to dividends in respect of such shares held for future awards. Until such time as the shares held by the ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders’ equity. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group. Foreign currency translation reserve The foreign currency translation reserve records exchange differences arising from the translation of the financial statements of foreign operations. Upon disposal of foreign operations, the related accumulated exchange differences are reclassified to the income statement. Available-for-sale investments This reserve recorded the changes in fair value of investments classified as available-for-sale under IAS 39 except for impairment losses, foreign exchange gains or losses, or changes arising from revised estimates of future cash flows. On adoption of IFRS 9 the balance in this reserve was transferred to the profit and loss account reserve. Under the new standard the group recognizes fair value gains and losses on these investments in profit or loss. Cash flow hedges This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. It includes $651 million relating to the acquisition of an 18.5% interest in Rosneft in 2013 which will only be reclassified to the income statement if the investment in Rosneft is either sold or impaired. For further information on the accounting for cash flow hedges see Note 1 - Derivative financial instruments and hedging activities. Costs of hedging This reserve records the change in fair value of the foreign currency basis spread of financial instruments to which cost of hedge accounting has been applied. The accumulated amount relates to time-period related hedged items and is amortized to profit or loss over the term of the hedging relationship. Prior to the group’s adoption of IFRS 9 changes in the fair value of such foreign currency basis spreads were recognized in profit or loss. On adoption of the new standard a transfer from the profit and loss account reserve to the costs of hedging reserve was made in order to reflect the opening reserves position for relevant hedging instruments existing on transition. For further information on the accounting for costs of hedging see Note 1 - Derivative financial instruments and hedging activities. Profit and loss account The balance held on this reserve is the accumulated retained profits of the group. 196 BP Annual Report and Form 20-F 2018 32. Capital and reserves – continued The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below. Items that may be reclassified subsequently to profit or loss Currency translation differences (including reclassifications) Cash flow hedges (including reclassifications) Costs of hedging (including reclassifications) Share of items relating to equity-accounted entities, net of tax Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Cash flow hedges that will subsequently be transferred to the balance sheet Other comprehensive income Items that may be reclassified subsequently to profit or loss Currency translation differences (including reclassifications) Available-for-sale investments (including reclassifications) Cash flow hedges (including reclassifications) Share of items relating to equity-accounted entities, net of tax Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Other comprehensive income Items that may be reclassified subsequently to profit or loss Currency translation differences (including reclassifications) Available-for-sale investments (including reclassifications) Cash flow hedges (including reclassifications) Share of items relating to equity-accounted entities, net of tax Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Other comprehensive income 33. Contingent liabilities Pre-tax Tax Net of tax $ million 2018 (3,771) (6) (186) 417 — 2,317 (37) (1,266) (16) — 13 — 7 (718) — (714) (3,787) (6) (173) 417 7 1,599 (37) (1,980) $ million 2017 Pre-tax Tax Net of tax 1,866 14 425 564 — 3,646 6,515 (95) — (29) — (72) (1,303) (1,499) 1,771 14 396 564 (72) 2,343 5,016 $ 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) 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 2018 in respect of guarantees and indemnities entered into as part of the ordinary course of the group’s business. No material losses are likely to arise from such contingent liabilities. Further information on financial guarantees is included in Note 29. In the normal course of the group’s business, legal and regulatory 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 health, safety and 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 and regulatory proceedings on the group‘s results of operations, liquidity or financial position will not be material. The group files tax returns in many jurisdictions 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 including the tax deductibility of certain intercompany charges. The resolution of tax positions through negotiations with relevant tax authorities, or through litigation, can take several years to complete and the amounts could be significant and could be material to the group’s results of operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, 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 2018 197 33. Contingent liabilities – continued The group is subject to numerous national and local health, safety and environmental laws and regulations concerning its products, operations and other activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of prior disposal or release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites including refineries, chemical plants, oil fields, commodities extraction sites, service stations, terminals and waste disposal sites. In addition, the group may have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its 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 impact on the group’s results of operations, financial position or liquidity. If oil and natural gas production facilities and pipelines are sold to third parties and the subsequent owner is unable to meet their decommissioning obligations it is possible that, in certain circumstances, BP could be partially or wholly responsible for decommissioning. While the amounts associated with decommissioning provisions reverting to the group could be significant and could be material, BP is not currently aware of any such 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. See also Legal proceedings on pages 296-298. 34. Remuneration of senior management and non-executive directors Remuneration of directors Total for all directors Emoluments Amounts received under incentive schemesa Total a Excludes amounts relating to past directors. 2018 2017 8 16 24 9 9 18 $ million 2016 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. Pension contributions During 2018 one executive director participated in a UK final salary pension plan in respect of service prior to 1 April 2011. During 2018, one executive director participated in retirement savings plans established for US employees and in a US defined benefit pension plan in respect of service prior to 1 September 2016. Further information Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 87. See also Related-party transactions on page 300. 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 2018 2017 25 2 32 59 29 2 29 60 $ million 2016 28 3 39 70 Senior management comprises members of the executive team, see pages 63-65 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 $nil in 2018 (2017 $nil and 2016 $2.2 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’. 198 BP Annual Report and Form 20-F 2018 35. Employee costs and numbers Employee costs Wages and salariesa Social security costs Share-based paymentsb Pension and other post-retirement benefit costs 2018 7,931 743 669 1,154 10,497 2017 7,572 711 624 1,296 10,203 Average number of employeesc US Non-US Upstream Downstreamd e Other businesses and corporatee f 5,900 6,000 1,900 13,800 11,500 36,300 12,100 59,900 2018 Total 17,400 42,300 14,000 73,700 US Non-US 6,200 6,100 1,900 14,200 12,200 35,900 12,400 60,500 2017 Total 18,400 42,000 14,300 74,700 US Non-US 6,700 6,600 1,900 15,200 13,500 36,600 12,100 62,200 $ million 2016 8,456 760 764 1,253 11,233 2016 Total 20,200 43,200 14,000 77,400 a Includes termination costs of $493 million (2017 $189 million and 2016 $545 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 17,100 (2017 16,500 and 2016 15,800) service station staff. e Around 800 centralized function employees were reallocated from Upstream and Downstream to Other businesses and corporate during 2016. f Includes 4,000 (2017 4,700 and 2016 4,900) agricultural, operational and seasonal workers in Brazil. 36. Auditor’s remuneration Fees The audit of the company annual accountsa The audit of accounts of subsidiaries of the company Total audit Audit-related assurance servicesb Total audit and audit-related assurance services Taxation compliance services Non-audit and other assurance services Total non-audit or non-audit-related assurance services Services relating to BP pension plans 2018 2017 $ million 2016 25 10 35 4 39 — 2 2 1 42 26 11 37 7 44 — 3 3 — 47 25 12 37 7 44 1 1 2 1 47 a Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements. b Includes interim reviews and audit of internal control over financial reporting and non-statutory audit services. With effect from 2018, following a competitive tender process, Deloitte LLP (Deloitte) was appointed as auditor of the Company, replacing Ernst & Young LLP (EY). In the table above, auditor’s remuneration for services provided during the year ended 31 December 2018 thus relates to Deloitte and for the years ended 31 December 2017 and 31 December 2016 to EY. In addition to the amounts shown in the table above, in 2018 $0.75 million of additional fees were paid to EY in respect of their audit for 2017. 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 Deloitte to render audit and certain assurance and other services. The audit fees payable to Deloitte were considered as part of the audit tender process in 2016 and challenged by the audit committee through comparison with the audit pricing proposals of the other bidding firms, before being approved. Deloitte performed further assurance services that were not prohibited by regulatory or other professional requirements and were pre-approved by the Committee. Deloitte is engaged for these services when its expertise and experience of BP are important. Most of this work is of an audit- related or assurance nature. Under SEC regulations, the remuneration of the auditor of $42 million (2017 $47 million and 2016 $47 million) is required to be presented as follows: audit $35 million (2017 $37 million and 2016 $37 million); other audit-related $4 million (2017 $7 million and 2016 $7 million); tax $nil (2017 $nil and 2016 $1 million); and all other fees $3 million (2017 $3 million and 2016 $2 million). BP Annual Report and Form 20-F 2018 199 37. Subsidiaries, joint arrangements and associates The more important subsidiaries and associates of the group at 31 December 2018 and the group percentage of ordinary share capital (to nearest whole number) are set out below. There are no individually significant incorporated joint arrangements. The group's share of the assets and liabilities of the more important unincorporated joint arrangements are held by subsidiaries listed in the table below. Those subsidiaries held directly by the parent company are marked with an asterisk (*), the percentage owned being that of the group unless otherwise indicated. A complete list of undertakings of the group is included in Note 14 in the parent company financial statements of BP p.l.c. which are filed with the Registrar of Companies in the UK, along with the group’s annual report. Subsidiaries International BP Corporate Holdings BP Exploration Operating Company *BP Global Investments *BP International BP Oil International *Burmah Castrol Angola BP Exploration (Angola) Azerbaijan BP Exploration (Caspian Sea) BP Exploration (Azerbaijan) Canada *BP Holdings Canada Egypt BP Exploration (Delta) Germany BP Europa SE India BP Exploration (Alpha) Trinidad & Tobago BP Trinidad and Tobago UK BP Capital Markets US *BP Holdings North America Atlantic Richfield Company BP America BP America Production Company BP Company North America BP Corporation North America BP Exploration (Alaska) BP Products North America Standard Oil Company BP Capital Markets America Associates Russia Country of incorporation % Principal activities 100 England & Wales 100 England & Wales 100 England & Wales 100 England & Wales 100 England & Wales 100 Scotland Investment holding Exploration and production Investment holding Integrated oil operations Integrated oil operations Lubricants 100 England & Wales Exploration and production 100 England & Wales 100 England & Wales Exploration and production Exploration and production 100 England & Wales Investment holding 100 England & Wales Exploration and production 100 Germany Refining and marketing 100 England & Wales Exploration and production 70 US Exploration and production 100 England & Wales Finance 100 England & Wales 100 US 100 US 100 US 100 US 100 US 100 US 100 US 100 US 100 US Investment holding Exploration and production, refining and marketing Finance Country of incorporation % Principal activities Rosneft Oil Company 19.75 Russia Integrated oil operations 200 BP Annual Report and Form 20-F 2018 38. 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 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 Issuer Guarantor BP Exploration (Alaska) Inc. 4,315 — — — 42 — 4,357 1,507 1,015 282 377 66 — 22 1,088 8 — 1,080 164 916 916 — 916 Other subsidiaries Eliminations and reclassifications 298,620 897 2,856 — 2,081 456 304,910 232,550 21,990 1,254 15,080 794 1,445 11,673 20,124 2,759 222 17,143 6,922 10,221 10,026 195 10,221 (4,179) — — (10,942) (1,723) — (16,844) (4,179) — — — — — (158) (12,507) (1,565) — (10,942) — (10,942) (10,942) — (10,942) BP p.l.c. — — — 10,942 373 — 11,315 — — — — — — 642 10,673 1,326 (95) 9,442 59 9,383 9,383 — 9,383 $ million 2018 BP group 298,756 897 2,856 — 773 456 303,738 229,878 23,005 1,536 15,457 860 1,445 12,179 19,378 2,528 127 16,723 7,145 9,578 9,383 195 9,578 BP Annual Report and Form 20-F 2018 201 38. Condensed consolidating information on certain US subsidiaries – continued Statement of comprehensive income Profit (loss) for the year Other comprehensive income Items that may be reclassified subsequently to profit or loss Currency translation differences Cash flow hedges (including reclassifications) Costs of hedging (including reclassifications) Share of items relating to equity-accounted entities, net of tax Income tax relating to items that may be reclassified Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Cash flow hedges that will subsequently be transferred to the balance sheet Income tax relating to items that will not be reclassified Other comprehensive income Equity-accounted other comprehensive income of subsidiaries Total comprehensive income Attributable to BP shareholders Non-controlling interests Income statement continued 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 taxesa 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 Issuer Guarantor BP Exploration (Alaska) Inc. 916 Other subsidiaries Eliminations and reclassifications 10,221 (10,942) BP p.l.c. 9,383 — — — — — — — — — — — — 916 916 — 916 (296) — — — — (296) 1,689 — (511) 1,178 882 (2,821) 7,444 7,444 — 7,444 (3,475) (6) (186) 417 4 (3,246) 628 (37) (207) 384 (2,862) — 7,359 7,205 154 7,359 — — — — — — — — — — — 2,821 (8,121) (8,121) — (8,121) Issuer Guarantor BP Exploration (Alaska) Inc. BP p.l.c. Other subsidiaries Eliminations and reclassifications 3,264 — — — 11 71 3,346 1,010 1,156 (18) 735 — — 19 444 6 — 438 (392) 830 830 — 830 — — — 4,436 369 9 4,814 — — — — — — 616 4,198 826 (15) 3,387 (11) 3,398 3,398 — 3,398 240,177 1,177 1,330 — 1,470 1,139 245,293 181,939 23,073 1,793 14,849 1,216 2,080 10,022 10,321 2,286 235 7,800 4,115 3,685 3,606 79 3,685 (3,233) — — (4,436) (1,193) (9) (8,871) (3,233) — — — — — (149) (5,489) (1,044) — (4,445) — (4,445) (4,445) — (4,445) $ million 2018 BP group 9,578 (3,771) (6) (186) 417 4 (3,542) 2,317 (37) (718) 1,562 (1,980) — 7,598 7,444 154 7,598 $ million 2017 BP group 240,208 1,177 1,330 — 657 1,210 244,582 179,716 24,229 1,775 15,584 1,216 2,080 10,508 9,474 2,074 220 7,180 3,712 3,468 3,389 79 3,468 a Includes revised non-cash provision adjustments; actual cash payments for Production and similar taxes remain in line with prior year. 202 BP Annual Report and Form 20-F 2018 38. Condensed consolidating information on certain US subsidiaries – continued Statement of comprehensive income continued Profit (loss) for the year Other comprehensive income Items that may be reclassified subsequently to profit or loss Currency translation differences Exchange (gains) losses on translation of foreign operations transferred to gain or loss on sale of businesses and fixed assets Available-for-sale investments marked to market 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 Income tax relating to items that will not be reclassified Other comprehensive income Equity-accounted other comprehensive income of subsidiaries Total comprehensive income Attributable to BP shareholders Non-controlling interests Income statement continued 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 Issuer Guarantor BP Exploration (Alaska) Inc. 830 BP p.l.c. 3,398 Other subsidiaries Eliminations and reclassifications 3,685 (4,445) — — — — — — — — — — — — — — 830 830 — 830 166 — — — — — — — 166 2,984 (1,169) 1,815 1,981 2,983 8,362 8,362 — 8,362 1,820 (120) 14 197 116 112 564 (196) 2,507 662 (134) 528 3,035 — 6,720 6,589 131 6,720 — — — — — — — — — — — — — (2,983) (7,428) (7,428) — (7,428) Issuer Guarantor BP Exploration (Alaska) Inc. 2,740 — — — 94 — 2,834 888 1,171 102 673 (147) — — 147 103 — 44 (41) 85 85 — 85 BP p.l.c. — — — 862 343 — 1,205 — — — — — — 808 397 311 (82) 168 53 115 115 — 115 Other subsidiaries 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 Eliminations and reclassifications (2,731) — — (862) (830) — (4,423) (2,731) — — — — — (110) (1,582) (720) 272 (1,645) (2,479) 834 777 57 834 — (862) — (862) (862) — (862) BP Annual Report and Form 20-F 2018 $ million 2017 BP group 3,468 1,986 (120) 14 197 116 112 564 (196) 2,673 3,646 (1,303) 2,343 5,016 — 8,484 8,353 131 8,484 $ 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 57 172 203 38. Condensed consolidating information on certain US subsidiaries – continued Statement of comprehensive income continued Profit (loss) for the year Other comprehensive income Items that may be reclassified subsequently to profit or loss Currency translation differences Exchange (gains) losses on translation of foreign operations transferred to gain or loss on sale of businesses and fixed assets Available-for-sale investments marked to market 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 Income tax relating to items that will not be reclassified 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. 85 — — — — — — — — — — — — — — 85 85 — 85 BP p.l.c. 115 Other subsidiaries Eliminations and reclassifications 834 (862) (236) — — — — — — — (236) (2,019) 750 (1,269) (1,505) 544 (846) (846) — (846) 490 30 1 (639) 196 81 833 13 1,005 (477) (11) (488) 517 — 1,351 1,321 30 1,351 — — — — — — — — — — — — — (544) (1,406) (1,406) — (1,406) $ million 2016 BP group 172 254 30 1 (639) 196 81 833 13 769 (2,496) 739 (1,757) (988) — (816) (846) 30 (816) 204 BP Annual Report and Form 20-F 2018 38. Condensed consolidating information on certain US subsidiaries – continued Balance sheet Non-current assets Property, plant and equipment Goodwill Intangible assets Investments in joint ventures Investments in associates Other investments Subsidiaries - equity-accounted basis Fixed assets Loans Trade and other receivables Derivative financial instruments Prepayments Deferred tax assets Defined benefit pension plan surpluses Current assets Loans Inventories Trade and other receivables Derivative financial instruments Prepayments Current tax receivable Other investments Cash and cash equivalents Total assets Current liabilities Trade and other payables Derivative financial instruments Accruals Finance debt Current tax payable Provisions Non-current liabilities Other payables Derivative financial instruments Accruals Finance debt Deferred tax liabilities Provisions Defined benefit pension plan and other post-retirement benefit plan deficits Total liabilities Net assets Equity BP shareholders’ equity Non-controlling interests Issuer Guarantor BP Exploration (Alaska) Inc. BP p.l.c. Other subsidiaries Eliminations and reclassifications 4,445 — 598 — — — — 5,043 — — — — — — 5,043 — 302 2,536 — 7 — — — 2,845 7,888 413 — 89 — 310 1 813 — — — — 586 670 — 1,256 2,069 5,819 5,819 — 5,819 — — — — 2 — 166,311 166,313 — 2,600 — — — 5,473 174,386 — — 151 — — — — 13 164 174,550 14,634 — 31 — — — 14,665 31,800 — — — 1,907 — 184 33,891 48,556 125,994 125,994 — 125,994 130,816 12,204 16,686 8,647 17,671 1,341 — 187,365 32,402 1,834 5,145 1,179 3,706 482 232,113 326 17,686 38,931 3,846 956 1,019 222 22,455 85,441 317,554 48,358 3,308 4,506 9,373 1,791 2,563 69,899 16,395 5,625 575 56,426 7,319 17,062 8,207 111,609 181,508 136,046 133,942 2,104 136,046 — — — — — — (166,311) (166,311) (31,765) (2,600) — — — — (200,676) — — (17,140) — — — — — (17,140) (217,816) (17,140) — — — — — (17,140) (34,365) — — — — — — (34,365) (51,505) (166,311) (166,311) — (166,311) $ million 2018 BP group 135,261 12,204 17,284 8,647 17,673 1,341 — 192,410 637 1,834 5,145 1,179 3,706 5,955 210,866 326 17,988 24,478 3,846 963 1,019 222 22,468 71,310 282,176 46,265 3,308 4,626 9,373 2,101 2,564 68,237 13,830 5,625 575 56,426 9,812 17,732 8,391 112,391 180,628 101,548 99,444 2,104 101,548 BP Annual Report and Form 20-F 2018 205 38. Condensed consolidating information on certain US subsidiaries – continued Balance sheet continued 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 payablesa Derivative financial instruments Accruals Finance debt Current tax payable Provisions Non-current liabilities Other payablesa Derivative financial instruments Accruals Finance debt Deferred tax liabilities Provisions Defined benefit pension plan and other post-retirement benefit plan deficits Total liabilities Net assets Equity BP shareholders’ equity Non-controlling interests Issuer Guarantor BP Exploration (Alaska) Inc. BP p.l.c. Other subsidiaries Eliminations and reclassifications BP group $ million 2017 6,973 — 585 — — — — 7,558 1 — — — — — 7,559 — 274 2,206 — 2 — — — 2,482 10,041 673 — 115 — — 1 789 — — — — 838 1,222 — 2,060 2,849 7,192 7,192 — 7,192 — — — — 2 — 161,840 161,842 — 2,623 — — — 3,838 168,303 — — 293 — — — — 10 303 168,606 10,143 — 60 — — — 10,203 31,804 — — — 1,337 — 221 33,362 43,565 125,041 125,041 — 125,041 122,498 11,551 17,770 7,994 16,989 1,245 — 178,047 32,401 1,434 4,110 1,112 4,469 331 221,904 190 18,737 34,991 3,032 1,412 761 125 25,576 84,824 306,728 46,034 2,808 4,785 7,739 1,686 3,323 66,375 16,464 3,761 505 55,491 5,807 19,398 8,916 110,342 176,717 130,011 128,098 1,913 130,011 — — — — — — (161,840) (161,840) (31,756) (2,623) — — — — (196,219) — — (12,641) — — — — — (12,641) (208,860) (12,641) — — — — — (12,641) (34,379) — — — — — — (34,379) (47,020) (161,840) (161,840) — (161,840) 129,471 11,551 18,355 7,994 16,991 1,245 — 185,607 646 1,434 4,110 1,112 4,469 4,169 201,547 190 19,011 24,849 3,032 1,414 761 125 25,586 74,968 276,515 44,209 2,808 4,960 7,739 1,686 3,324 64,726 13,889 3,761 505 55,491 7,982 20,620 9,137 111,385 176,111 100,404 98,491 1,913 100,404 a For BP plc, an amount of $2,300 million has been reclassified from non-current other payables to current trade and other payables, with consequential amendments to the eliminations and reclassifications column. 206 BP Annual Report and Form 20-F 2018 38. Condensed consolidating information on certain US subsidiaries – continued Cash flow statement 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 Equity accounted income of subsidiaries - after interest and tax Dividends received from subsidiaries 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 (used in) operating activities Investing activities Expenditure on property, plant and equipment, intangible and other assets Acquisitions, net of cash acquired Investment in joint ventures Investment in associates Total cash capital expenditure Proceeds from disposals of fixed assets Proceeds from disposals of businesses, net of cash disposed Proceeds from loan repayments Net cash provided by (used in) investing activities Financing activities Repurchase of shares Proceeds from long-term financing Repayments of long-term financing Net increase (decrease) in short-term debt 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 Issuer Guarantor BP Exploration (Alaska) Inc. BP p.l.c. Other subsidiaries Eliminations and reclassifications $ million 2018 BP group 1,080 9,442 17,143 (10,942) 16,723 — 377 66 — — — — (42) 42 8 (8) — — — 33 (62) (72) (491) (133) 798 (273) — — — (273) — 1,475 — 1,202 — — — — (2,000) — (2,000) — — — — — — — — — (10,942) 3,490 (215) 215 1,326 (1,326) (95) 671 (183) — — 165 4,509 — 7,057 — — — — — — — — — (355) — — — (6,699) — (7,054) — 3 10 13 1,085 15,080 338 (3,753) 1,535 — — (1,776) 1,656 2,759 (2,159) 222 19 (203) 953 734 (951) (6,595) (5,579) 20,508 (16,434) (6,986) (382) (1,013) (24,815) 940 436 666 (22,773) — 9,038 (7,210) 1,317 (3,490) (170) (515) (330) (3,110) 25,565 22,455 — — — — — 10,942 (3,490) 1,565 (1,565) (1,565) 1,565 — — — — — (2,000) — — (5,490) — — — — — — — — — — — — — 5,490 — 5,490 — — — — 1,085 15,457 404 (3,753) 1,535 — — (468) 348 2,528 (1,928) 127 690 (386) 986 672 (2,858) (2,577) (5,712) 22,873 (16,707) (6,986) (382) (1,013) (25,088) 940 1,911 666 (21,571) (355) 9,038 (7,210) 1,317 (6,699) (170) (4,079) (330) (3,107) 25,575 22,468 BP Annual Report and Form 20-F 2018 207 38. Condensed consolidating information on certain US subsidiaries – continued Cash flow statement continued 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 Equity accounted income of subsidiaries - after interest and tax Dividends received from subsidiaries Interest receivable Interest received Finance costs Interest paid Net finance expense relating to pensions and other post- retirement benefits Share-based payments Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans Net charge for provisions, less payments (Increase) decrease in inventories (Increase) decrease in other current and non-current assets Increase (decrease) in other current and non-current liabilities Income taxes paid Net cash provided by operating activities Investing activities Expenditure on property, plant and equipment, intangible and other assets Acquisitions, net of cash acquired Investment in joint ventures Investment in associates Total cash capital expenditure Proceeds from disposals of fixed assets Proceeds from disposals of businesses, net of cash disposed Proceeds from loan repayments Net cash provided by (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 $ million 2017 Issuer Guarantor BP Exploration (Alaska) Inc. BP p.l.c. Other subsidiaries Eliminations and reclassifications BP group 438 3,387 7,800 (4,445) 7,180 — 735 (71) — — — — (11) 11 6 (6) — — — (128) (25) 108 (830) — 227 (321) — — — (321) 94 — — (227) — — — — — — — — — — — — — — (9) — — (4,436) 3,183 (220) 220 826 (826) (15) 595 (145) — — 522 3,374 — 6,456 — — — — — — — — — (343) — — — — (6,153) — (6,496) — (40) 50 10 1,603 14,849 77 (2,507) 1,253 — — (1,117) 1,188 2,286 (1,784) 235 66 (249) 2,234 (823) (5,478) (200) (4,002) 15,431 (16,241) (327) (50) (901) (17,519) 2,842 478 349 (13,850) — 8,712 (6,276) (158) 1,063 (3,183) (141) 17 544 2,142 23,434 25,576 — — 9 — — 4,436 (3,183) 1,044 (1,044) (1,044) 1,044 — — — — — — — — (3,183) — — — — — — — — — — — — — — 3,183 — 3,183 — — — — 1,603 15,584 6 (2,507) 1,253 — — (304) 375 2,074 (1,572) 220 661 (394) 2,106 (848) (4,848) 2,344 (4,002) 18,931 (16,562) (327) (50) (901) (17,840) 2,936 478 349 (14,077) (343) 8,712 (6,276) (158) 1,063 (6,153) (141) (3,296) 544 2,102 23,484 25,586 208 BP Annual Report and Form 20-F 2018 38. Condensed consolidating information on certain US subsidiaries – continued Cash flow statement continued 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 Equity accounted income of subsidiaries - after interest and tax Dividends received from (paid to) subsidiaries Interest receivable Interest received Finance costs Interest paid Net finance expense relating to pensions and other post- retirement benefits Share-based payments Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans Net charge for provisions, less payments (Increase) decrease in inventories (Increase) decrease in other current and non-current assets Increase (decrease) in other current and non-current liabilities Income taxes paid Net cash provided by operating activities Investing activities Expenditure on property, plant and equipment, intangible and other assets Acquisitions, net of cash acquired Investment in joint ventures Investment in associates Total cash capital expenditure Proceeds from disposals of fixed assets Proceeds from disposals of businesses, net of cash disposed Proceeds from loan repayments Net cash provided by (used in) investing activities Financing activities 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 Issuer Guarantor BP Exploration (Alaska) Inc. BP p.l.c. Other subsidiaries Eliminations and reclassifications BP group $ million 2016 44 168 (1,645) (862) (2,295) — 673 (148) — — — (7,000) (94) 94 103 (103) — — — 77 (3) 6,985 (33) 104 699 (699) — — — (699) — — — (699) — — — — — — — — — — — — — — — — (862) 372 (233) 233 311 (311) (82) 780 (192) — — (156) 4,634 (1) 4,661 — — — — — — — — — — — — — (4,611) — (4,611) — 50 — 50 1,274 13,832 (2,648) (1,960) 1,105 — — (593) 660 1,981 (1,443) 272 (1) (275) 4,410 (3,678) (1,001) (2,946) (1,641) 5,703 (16,002) (1) (50) (700) (16,753) 1,372 1,259 68 (14,054) 12,442 (6,685) 51 887 (372) (107) 6,216 (820) (2,955) 26,389 23,434 — — — — — 862 6,628 720 (720) (720) 720 — — — — — (7,000) — — (372) — — — — — — — — — — — — — 372 — 372 — — — — 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 (16,701) (1) (50) (700) (17,452) 1,372 1,259 68 (14,753) 12,442 (6,685) 51 887 (4,611) (107) 1,977 (820) (2,905) 26,389 23,484 BP Annual Report and Form 20-F 2018 209 Supplementary information on oil and natural gas (unaudited) The regional analysis presented below is on a continent basis, with separate disclosure for countries that contain 15% or more of the total proved reserves (for subsidiaries plus equity-accounted entities), in accordance with SEC and FASB requirements. Oil and gas reserves – certain definitions Unless the context indicates otherwise, the following terms have the meanings shown below: Proved oil and gas reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any; and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favourable than in the reservoir as a whole, the operation of an installed programme in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or programme was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Undeveloped oil and gas reserves Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. Developed oil and gas reserves Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) (ii) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. For details on BP’s proved reserves and production compliance and governance processes, see pages 285-290. 210 BP Annual Report and Form 20-F 2018 Oil and natural gas exploration and production activities Europe Rest of Europe UK North America South America Rest of North America US Africa Asia Australasia Total Russia Rest of Asia $ million 2018 29,730 451 30,181 16,809 13,372 — 89,069 — 3,602 — 92,671 — 47,051 — 45,620 3,385 2,667 6,052 420 5,632 14,269 2,742 17,011 8,517 8,494 51,980 3,870 55,850 38,324 17,526 — 38,315 — 3,153 — 41,468 — 20,173 — 21,295 568 6,119 232,867 17,053 6,687 249,920 3,626 134,920 3,061 115,000 Subsidiaries Capitalized costs at 31 Decembera b Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs Costs incurred for the year ended 31 Decembera b Acquisition of properties Proved Unproved Exploration and appraisal costsc Development Total costs 1,933 — 1,933 238 817 2,988 Results of operations for the year ended 31 Decembera Sales and other operating revenuesd 619 2,255 2,874 105 646 (269) (331) 1,199 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 — 10,650 — 35 — 10,685 — 216 — 3,429 — 14,330 — 1,306 — 11,656 — 12,962 — 509 — 2,729 — 369 (2) 2,379 — 3,921 (226) — 203 1,124 1,750 446 1,304 (2) 10,110 2,852 2 — 454 2,398 2 420 (314) (95) (219) — — — 139 46 185 105 1 106 146 120 — 43 101 10 — 100 100 245 591 936 (1) 50 49 283 2,340 2,672 36 — (5) — 31 — 5 148 — 2,458 2,637 5 — 12,618 — 180 — 12,798 1,298 24 9,917 236 24,013 260 2,074 195 2,269 252 430 357 165 1,023 3,228 3,928 7,156 405 1,066 — 133 3,635 — (141) 2,227 42 314 (272) 5,098 2,058 1,184 874 — 1,430 — 7,793 — 9,223 20 5 951 — — 1,010 42 94 — 2,165 — 47 (47) 13 (60) 21 4,261 4,962 3,509 1,453 1,410 665 2,075 3 138 69 223 298 136 867 1,208 508 700 10,172 26,493 36,665 1,445 6,080 1,536 2,746 12,342 3 24,152 12,513 6,333 6,180 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 j Total replacement cost profit (loss) before interest and tax 1,750 2 2,852 (314) 42 2,058 (47) 4,962 1,208 12,513 (20) (2) 265 130 188 28 (111) — 135 209 (58) 5 207 2,346 463 245 6 — 873 3,163 1,728 397 3,068 (425) 386 2,207 2,304 5,670 1,214 16,549 a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes 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, Asia and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia, Australia and Angola. b Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year. c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. d Presented net of transportation costs, purchases and sales taxes. e Includes property taxes, other government take and the fair value gain on embedded derivatives of $17 million. The UK region includes a $384-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance programme. f Excludes the unwinding of the discount on provisions and payables amounting to $208 million which is included in finance costs in the group income statement. g US region includes the deferred tax impact of the reduction in the US Federal corporate income tax rate from 35% to 21% enacted in December 2017. h Midstream and other activities excludes inventory holding gains and losses. i The profits of equity-accounted entities are included after interest and tax. j From 16 December 2017, BP entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by BP and 40% by Bridas Corporation. BP Annual Report and Form 20-F 2018 211 Oil and natural gas exploration and production activities – continued Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Total Russiaa Rest of Asia $ million 2018 Equity-accounted entities (BP share) Capitalized costs at 31 Decemberb c Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs — 3,439 — 657 — 4,096 670 — — 3,426 Costs incurred for the year ended 31 Decemberb d e Acquisition of propertiesc Proved Unproved Exploration and appraisal costsd Development Total costs — — — — — — — 137 137 67 251 455 Results of operations for the year ended 31 Decemberb Sales and other operating revenuesf Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income) Depreciation, depletion and amortization Net impairments and losses on sale of businesses and fixed assets Profit (loss) before taxation Allocable taxes Results of operationsg — 1,114 — — — 1,114 89 — 207 — — — 21 — 290 — — — — — — 6 613 501 350 151 — — — — — — — — — — — — — — — — — — — — — — — — — 9,643 — 86 — 9,729 — 4,665 — 5,064 — 24,052 — 828 — 24,880 — 6,749 — 18,131 3,646 26 3,672 3,672 — — — — — — — — — — 25 575 600 — 1,792 — — — 1,792 7 — 438 — 361 — 127 — 416 — 425 — 148 — 573 — — 207 — 3,255 — 4,035 — — — 15,901 — 15,901 — 112 — 1,487 — 7,634 — 638 — 1,627 — — — 47 — 1,349 443 — 279 — 164 — — 11,545 — 4,356 — 849 — 3,507 — — — — 212 212 353 — 353 — 39 94 — 212 1 346 7 — 7 — 40,780 — 1,597 — 42,377 — 15,756 — 26,621 425 — 285 — 710 — — 299 — 4,293 — 5,302 — 3,259 — 15,901 — 19,160 — 208 — 2,171 — 8,089 — 786 — 2,545 — 54 — 13,853 — 5,307 — 1,478 — 3,829 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 — (2) (2) 151 (21) 130 — 28 28 — — — 164 45 209 — 3,507 207 (1,161) 207 2,346 7 238 245 — 3,829 — (666) — 3,163 a Amounts reported for Russia in this table include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. The amounts reported include the corresponding amounts for their equity-accounted entities. b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations as well as downstream activities of Rosneft and Pan American Energy Group are excluded. c Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year. d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. e The amounts shown reflect BP’s share of equity-accounted entities’ costs incurred, and not the costs incurred by BP in acquiring an interest in equity-accounted entities. f Presented net of transportation costs and sales taxes. g From 16 December 2017, BP entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by BP and 40% by Bridas Corporation. h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses. 212 BP Annual Report and Form 20-F 2018 Oil and natural gas exploration and production activities – continued Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Russia Rest of Asia $ million 2017 Total 34,208 481 34,689 21,793 12,896 — 83,449 — 3,957 — 87,406 — 48,462 — 38,944 3,518 2,561 6,079 367 5,712 13,581 2,905 16,486 7,495 8,991 49,795 4,013 53,808 34,870 18,938 — 35,519 — 3,407 — 38,926 — 18,007 — 20,919 562 5,984 226,054 17,886 6,546 243,940 3,192 134,186 3,354 109,754 Subsidiaries Capitalized costs at 31 Decembera b Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs Costs incurred for the year ended 31 Decembera b Acquisition of properties Proved Unproved Exploration and appraisal costsc Development Total costs — 13 13 336 995 1,344 Results of operations for the year ended 31 Decembera Sales and other operating revenuesd Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income)e Depreciation, depletion and amortization Net impairments and (gains) losses on sale of businesses and fixed assets Profit (loss) before taxationf Allocable taxesg Results of operations 204 1,745 1,949 331 629 (37) (272) 1,190 133 1,974 (25) (104) 79 22 — 13 — 35 — — 102 — 2,776 — 2,913 724 — — 9,117 — 9,841 — 282 — 2,256 52 — 2 1,655 — 4,258 — — — 52 58 110 171 2 173 39 116 — 34 96 (12) 87 8,590 (10) 10 1,251 — (1,811) 3,062 10 (1) 284 (111) (28) (83) — 330 330 264 911 1,505 1,134 327 1,461 83 573 86 71 742 (31) 1,524 (63) 155 (218) 564 374 938 682 2,972 4,592 2,211 4,022 6,233 1,346 979 — 280 3,586 — 6,191 42 788 (746) — 1,187 — 228 — 1,415 11 190 — 2,760 4,365 11 — — — 18 223 241 1,773 958 2,731 1,655 10,695 15,081 — 1,276 — 6,394 — 7,670 (29) 11 904 — — 1,618 39 311 — 2,147 — 50 (50) (19) (31) (10) 4,941 2,729 1,505 1,224 967 487 1,454 17 157 56 349 366 13 958 496 146 350 6,687 22,094 28,781 2,080 5,614 1,775 2,469 12,385 179 24,502 4,279 632 3,647 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 j Total replacement cost profit (loss) before interest and tax (25) 10 1,251 (111) (63) 42 (50) 2,729 496 4,279 (185) — 97 71 (176) (111) 25 — (210) 178 1,100 (222) 140 381 458 (80) 205 3 837 315 245 11 — 14 1,764 167 790 3,289 507 6,057 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, Asia and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the South Caucasus Pipeline, the Forties Pipeline System and the Baku- Tbilisi-Ceyhan pipeline. The Forties Pipeline System was divested on 31 October 2017. Major LNG activities are located in Trinidad, Indonesia, Australia and Angola. b Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year. c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. d Presented net of transportation costs, purchases and sales taxes. e Includes property taxes, other government take and the fair value gain on embedded derivatives of $32 million. The UK region includes a $343-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 $120 million which is included in finance costs in the group income statement. g US region includes the deferred tax impact of the reduction in the US Federal corporate income tax rate from 35% to 21% enacted in December 2017. h Midstream and other activities excludes inventory holding gains and losses. i The profits of equity-accounted entities are included after interest and tax. j From 16 December 2017, BP entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by BP and 40% by Bridas Corporation. Of BP's initial 60% interest in PAE, 10% was classified as held for sale on 9 September 2017. For September, only 9 days of income was reported for the full 60%. After this equity accounting continued for the 50% not classified as held for sale. BP accounted for 50% of the enlarged entity from 16 December 2017. BP Annual Report and Form 20-F 2018 213 Oil and natural gas exploration and production activities – continued Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Russiaa Rest of Asia $ million 2017 Total Equity-accounted entities (BP share) Capitalized costs at 31 Decemberb c Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs — 3,187 — 481 — 3,668 400 — — 3,268 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 operationsg — — — — — — — — — — — — — 323 152 475 49 199 723 773 — 773 68 157 — 67 328 6 626 147 54 93 — — — — — — — — — — — — — — — — — — — — — — — — — 9,096 — 68 — 9,164 — 4,249 — 4,915 — 24,686 — 907 — 25,593 — 6,207 — 19,386 3,434 26 3,460 3,460 — — — — — — — — 20 20 43 576 639 653 — — 416 — 1,069 — 194 — 3,361 — 4,624 — 1,750 — — — 1,750 — — 592 — 336 — 11 — 458 — — — — 11,537 — 11,537 — 59 — 1,424 — 5,712 — 409 — 1,539 — 27 — 54 — 1,424 326 — (18) — 344 — — 9,197 — 2,340 — 457 — 1,883 — — — — 446 446 988 — 988 — 117 426 (5) 446 — 984 4 — 4 — 40,403 — 1,482 — 41,885 — 14,316 — 27,569 976 — — 588 — 1,564 — 286 — 4,582 — 6,432 — 3,511 — 11,537 — 15,048 — 127 — 2,290 — 6,474 — 482 — 2,771 — 87 — 12,231 — 2,817 — 493 — 2,324 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 — — — 93 (22) 71 — 25 25 — — — 344 37 381 — 1,883 205 (1,046) 205 837 4 241 245 — 2,324 — (560) — 1,764 a Amounts reported for Russia in this table include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. The amounts reported include the corresponding amounts for their equity-accounted entities. b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations as well as downstream activities of Rosneft and Pan American Energy Group are excluded. c Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year. d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. e The amounts shown reflect BP’s share of equity-accounted entities’ costs incurred, and not the costs incurred by BP in acquiring an interest in equity-accounted entities. f Presented net of transportation costs and sales taxes. g From 16 December 2017, BP entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by BP and 40% by Bridas Corporation. Of BP's initial 60% interest in PAE, 10% was classified as held for sale on 9 September 2017. For September, only 9 days of income was reported for the full 60%. After this equity accounting continued for the 50% not classified as held for sale. BP accounted for 50% of the enlarged entity from 16 December 2017. h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses. 214 BP Annual Report and Form 20-F 2018 Oil and natural gas exploration and production activities – continued Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Total Russia Rest of Asia $ million 2016 34,171 483 34,654 21,745 12,909 — 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 — 19,060 562 5,752 215,564 18,524 6,314 234,088 2,826 123,993 3,488 110,095 Subsidiaries Capitalized costs at 31 Decembera b Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs 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 8 314 38 352 391 2,372 3,115 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 244 1,387 1,631 133 619 (351) (215) 1,002 (809) 379 1,252 (286) 1,538 26 421 447 3 208 — 37 209 (345) 112 335 (287) 622 640 6,204 6,844 693 2,524 155 1,687 3,940 (627) 8,372 (1,528) (402) (1,126) — 10 10 70 28 108 74 2 76 61 114 — 25 66 — 10 10 123 1,519 1,652 747 103 850 672 476 38 115 591 — 181 181 297 2,957 3,435 1,215 3,391 4,606 87 1,220 — 597 2,937 (5) 261 (185) (40) (145) (77) (765) 1,815 (965) (194) (771) 4,076 530 670 (140) — 703 — 1,728 — 2,431 10 252 — 2,788 5,471 10 207 — 207 89 194 490 1,439 1,967 3,406 1,402 11,145 15,953 97 — — 3,908 — 4,005 (27) 10 691 — 800 — 34 115 — 2,179 — 44 (44) (10) (34) (182) 3,576 429 (74) 503 1,042 309 1,351 89 154 41 153 289 63 789 562 288 274 4,085 15,725 19,810 1,721 6,006 683 2,548 11,213 (2,747) 19,424 386 (335) 721 Upstream and Rosneft segments replacement cost profit (loss) before interest and tax Exploration and production activities – 1,252 335 (1,528) (185) (965) 530 (44) 429 562 386 subsidiaries (as above) Midstream and other activities – subsidiariesi Equity-accounted entitiesj k Total replacement cost profit (loss) before interest and tax (417) — 54 (1) (14) 20 (137) — 187 447 (142) (2) (12) 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, Asia 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 Costs of decommissioning 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. BP Annual Report and Form 20-F 2018 215 Oil and natural gas exploration and production activities – continued Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Total Russiaa Rest of Asia $ million 2016 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 — — — — — — 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 — — — — — — — — — — — — — — — — 18 54 72 162 — 162 13 36 — (13) 48 — 84 78 75 3 — — — — — — — — — — — — — — — — — — — — — — — — — 10,211 — 6 — 10,217 — 4,615 — 5,602 — 19,558 — 383 — 19,941 — 4,401 — 15,540 3,009 26 3,035 3,035 — — — — — — — — — — 7 559 566 — 1,576 — 69 — 1,645 — 118 — 2,070 — 3,833 — 1,865 — — — 1,865 — — 559 — 335 — (429) — 499 — — — — 8,088 — 8,088 — 50 — 1,085 — 3,393 — 345 — 1,082 — 164 — 59 — 1,128 737 — 319 — 418 — — 6,014 — 2,074 — 435 — 1,639 — — — 1 371 372 876 16 892 — 145 352 3 386 — 886 6 3 3 — 35,480 — 711 — 36,191 — 12,099 — 24,092 — 1,576 — 69 — 1,645 — 144 — 3,054 — 4,843 — 2,903 — 8,104 — 11,007 — 63 — 1,825 — 4,080 — (94) — 2,015 — 223 — 8,112 — 2,895 — 832 — 2,063 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 29 447 — 1,639 (12) (1,042) (12) 597 3 263 266 — 2,063 — (746) — 1,317 a Amounts reported for Russia in this table include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. The amounts reported include the corresponding amounts for their equity-accounted entities. Amounts also include certain adjustments, mainly related to purchase price allocations for 2016 acquisitions. 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. c Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year. d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. e The amounts shown reflect BP’s share of equity-accounted entities’ costs incurred, and not the costs incurred by BP in acquiring an interest in equity-accounted entities. f Presented net of 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. 216 BP Annual Report and Form 20-F 2018 Movements in estimated net proved reserves Crude oila b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiond Sales of reserves-in-place At 31 Decembere Developed Undeveloped Equity-accounted entities (BP share)f At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberg Developed Undeveloped Europe UK Rest of Europe North America South America Rest of North America USc 245 164 409 22 — 93 15 (37) (37) 57 223 243 466 — — — — — — — — — — — — — 245 164 409 932 — — 492 — 1,423 — — — — — — — 116 51 412 17 (137) (118) 341 — 962 802 — — 1,764 56 89 145 11 13 — — (13) — 12 57 100 157 56 89 145 — — — — — — — — — — — — — 932 492 1,423 962 802 1,764 54 195 248 (6) — — — (9) — (15) 43 190 234 — — — — — — 19 — — 19 — 19 19 54 195 249 43 209 253 10 6 16 1 — — — (3) — (2) 8 5 14 285 263 548 7 — — 21 (25) — 4 293 259 552 295 269 564 302 264 566 Africa Asia Australasia Total million barrels 2018 Russia Rest of Asia — 1,040 — 642 — 1,682 — — — — — — — 40 — — — (114) — (74) — 1,126 482 — — 1,608 281 28 309 11 1 — 13 (75) — (50) 223 36 259 3,124 1 — 2,251 5,374 1 — — — — — — (1) 150 — 89 326 (335) — 229 1 3,190 — 2,414 5,604 1 6 — 6 — — — — (6) — (6) — — — 282 28 310 224 36 260 3,124 2,251 5,374 3,190 2,414 5,604 1,047 642 1,688 1,126 482 1,608 31 11 42 (2) — — — (6) — (8) 30 5 34 2,592 1,537 4,129 183 52 504 46 (381) (155) 249 2,615 1,763 4,378 — 3,473 — 2,603 — 6,076 — — — — — — — 168 13 89 366 (379) — 257 — 3,541 — 2,792 — 6,333 31 11 42 30 5 34 6,064 4,140 10,205 6,156 4,555 10,711 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped At 31 December Developed Undeveloped 223 243 466 57 100 157 a Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Includes 4 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Includes 344 million barrels of crude oil in respect of the 6.28% non-controlling interest in Rosneft, including 24 mmbbl held through BP's interests in Russia other than Rosneft. g Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,539 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 58 million barrels in Venezuela and 5,481 million barrels in Russia. BP Annual Report and Form 20-F 2018 217 Movements in estimated net proved reserves - continued Europe North America South America Africa Asia Australasia Total million barrels 2018 Rest of Europe Rest of North America US Russia Rest of Asia 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 UK 11 3 14 1 — — 3 (2) (3) — 8 6 14 — — — — — — — — — — — — — Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 11 3 14 At 31 December Developed Undeveloped 8 6 14 — — — — — — — — — — — — — 4 4 8 — — — — (1) — (1) 4 3 7 4 4 8 4 3 7 177 69 246 20 16 253 1 (25) — 265 266 246 511 — — — — — — — — — — — — — 177 69 246 266 246 511 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 2 28 30 — — — — (3) — (3) 2 25 27 — — — — — — — — — — — — — 2 28 30 2 25 27 21 — 21 (3) 2 — 3 (3) — (2) 14 4 18 10 — 10 (1) — — — (1) — (3) 7 — 7 31 — 31 22 4 26 — — — — — — — — — — — — — 82 49 131 25 — — — (2) — 23 103 51 154 82 49 131 103 51 154 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 5 1 6 — — — — (1) — (1) 5 — 5 — — — — — — — — — — — — — 5 1 6 5 — 5 216 102 318 17 18 253 7 (34) (3) 258 295 280 576 97 53 149 23 — — — (4) — 19 114 54 169 313 154 467 409 335 744 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. d Includes 8 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Includes 12 million barrels of NGLs in respect of the 7.82% non-controlling interest in Rosneft. f Total proved NGL reserves held as part of our equity interest in Rosneft is 154 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 154 million barrels in Russia. 218 BP Annual Report and Form 20-F 2018 Movements in estimated net proved reserves - continued Total liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiond Sales of reserves-in-place At 31 Decembere Developed Undeveloped Equity-accounted entities (BP share)f At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberg h Developed Undeveloped Europe UK Rest of Europe North America South America Rest of North America USc 256 167 424 23 — 93 18 (39) (40) 56 231 249 480 — — — — — — — — — — — — — 256 167 424 — 1,108 — 561 — 1,669 — — — — — — — 136 67 665 18 (162) (118) 606 — 1,228 — 1,048 — 2,276 60 93 153 11 13 — — (13) — 11 60 104 164 60 93 153 — — — — — — — — — — — — — 1,108 561 1,669 1,228 1,048 2,276 54 195 248 (6) — — — (9) — (15) 43 190 234 — — — — — — 19 — — 19 — 19 19 54 195 249 44 209 253 12 34 46 1 — — — (6) — (5) 10 30 41 285 263 548 7 — — 21 (25) — 4 293 259 552 297 297 594 303 289 593 million barrels 2018 Africa Asia Australasia Total Russia Rest of Asia — 1,040 — 642 — 1,682 — — — — — — — 40 — — — (114) — (74) — 1,126 482 — — 1,608 301 28 329 8 3 — 16 (79) — (52) 237 40 277 3,206 11 — 2,300 5,505 12 (2) — — — (2) — (3) 175 — 89 326 (337) — 253 8 3,293 — 2,465 5,758 8 6 — 6 — — — — (6) — (6) — — — 313 28 341 245 40 285 3,206 2,300 5,505 3,293 2,465 5,758 1,047 642 1,688 1,126 482 1,608 36 12 48 (2) — — — (7) — (9) 35 5 39 2,808 1,639 4,447 200 70 758 52 (415) (158) 507 2,910 2,044 4,954 — 3,569 — 2,656 — 6,225 — — — — — — — 191 13 89 366 (383) — 277 — 3,655 — 2,846 — 6,502 36 12 48 35 5 39 6,377 4,295 10,672 6,565 4,890 11,456 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped At 31 December Developed Undeveloped 231 249 480 60 104 164 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. e Also includes 12 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. g Includes 356 million barrels in respect of the non-controlling interest in Rosneft, including 24 mmboe held through BP’s interests in Russia other than Rosneft. h Total proved liquid reserves held as part of our equity interest in Rosneft is 5,693 million barrels, comprising less than 1 million barrels in Canada, 58 million barrels in Venezuela, less than 1 million barrels in Vietnam and 5,635 million barrels in Russia. BP Annual Report and Form 20-F 2018 219 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 UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Total billion cubic feet 2018 Russia Rest of Asia 523 320 843 84 — 40 60 (66) (178) (61) 439 343 782 — — — — — — — — — — — — — 523 320 843 — 5,238 — 3,086 — 8,323 10 — — 1,315 — 2,655 11 — (751) — — (237) — 3,003 — 6,270 — 5,056 — 11,326 (1) 2,862 — 3,330 6,193 (1) 1,159 1,510 2,670 — 2,755 — 4,245 — 7,000 2,730 1,505 4,235 15,266 13,997 29,263 3 — — — (3) — 1 (195) — — 31 (788) — (951) (444) — — 578 (423) — (290) — — — — — — — 140 — — — (324) — (184) (123) (524) — 1,315 — 2,695 680 — (2,658) (303) (416) — 1,092 (426) — 2,168 — 3,073 — 5,241 1,313 1,067 2,380 — 3,599 — 3,218 — 6,817 2,630 1,179 3,809 16,420 13,936 30,355 112 69 180 2 — — — (22) — (19) 107 55 161 112 69 180 — — — — — — — — — — — — — 5,238 3,086 8,323 — 1,274 — 450 — 1,724 476 146 622 6,077 7,173 13,250 — — — 4 — — 3 (50) 1 — 122 (145) — (71) (39) 805 — — — 2,413 512 — (464) (48) — — 3,267 (87) — 1,207 4 446 1,653 4 391 143 534 7,798 8,719 16,517 17 3 20 2 — — — (6) — (5) 12 4 15 — 7,955 — 7,841 — 15,796 — 719 1 — — 2,413 638 — (685) — — — — 3,087 — 9,515 — 9,369 — 18,884 — 4,136 — 3,781 — 7,917 — 3,375 3,519 4 6,894 4 1,635 1,656 3,291 1,704 1,210 2,914 6,077 7,173 13,250 7,798 8,719 16,517 2,771 4,249 7,020 3,610 3,221 6,832 2,730 1,505 4,235 2,630 1,179 3,809 23,221 21,838 45,060 25,934 23,305 49,239 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped At 31 December Developed Undeveloped 439 343 782 107 55 161 6,270 5,056 11,326 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes 181 billion cubic feet of natural gas consumed in operations, 139 billion cubic feet in subsidiaries, 42 billion cubic feet in equity-accounted entities. d Includes 1,573 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Includes 1,211 billion cubic feet of natural gas in respect of the 8.60% non-controlling interest in Rosneft including 480 billion cubic feet held through BP’s interests in Russia other than Rosneft. g Total proved gas reserves held as part of our equity interest in Rosneft is 14,325 billion cubic feet, comprising 0 billion cubic feet in Canada, 26 billion cubic feet in Venezuela, 15 billion cubic feet in Vietnam, 200 billion cubic feet in Egypt and 14,084 billion cubic feet in Russia. 220 BP Annual Report and Form 20-F 2018 Movements in estimated net proved reserves – continued Total hydrocarbonsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione f Sales of reserves-in-place At 31 Decemberg Developed Undeveloped Equity-accounted entities (BP share)h At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione Sales of reserves-in-place At 31 Decemberi j Developed Undeveloped Europe North America South America UK Rest of Europe USd Rest of North America million barrels of oil equivalentc 2018 Africa Asia Australasia Total Russia Rest of Asia 347 222 569 38 — 100 29 (50) (70) 46 307 308 615 — — — — — — — — — — — — — 347 222 569 — 2,011 — 1,093 — 3,104 138 — — 294 — 1,123 — 20 (292) — — (159) — 1,124 — 2,309 — 1,919 — 4,228 80 105 184 11 13 — — (17) — 8 79 113 192 80 105 184 — — — — — — — — — — — — — 2,011 1,093 3,104 2,309 1,919 4,228 54 195 248 (5) — — — (9) — (15) 43 190 234 — — — — — — 20 — — 19 — 20 20 54 195 249 44 210 253 505 608 1,114 (33) — — 5 (142) — (169) 384 560 944 505 341 846 (1) — — 42 (50) — (9) 501 336 837 1,010 949 1,959 885 896 1,781 501 288 790 (69) 3 — 116 (152) — (102) 464 224 687 93 25 119 (8) — — — (10) — (18) 76 25 101 595 314 908 539 249 788 — 1,515 — 1,374 — 2,889 507 272 779 5,440 4,052 9,492 — — — — — — — 64 — — — (170) — (106) 110 (23) — 297 — 1,222 169 — (874) (59) (229) — 696 (82) — 1,746 — 1,037 — 2,783 488 208 696 5,741 4,447 10,188 4,254 3,536 7,790 313 — 505 414 (417) — 816 4,638 3,968 8,605 4,254 3,536 7,790 4,638 3,968 8,605 9 1 10 — — — — (7) — (7) 2 1 3 1,524 1,374 2,899 1,749 1,037 2,786 — 4,941 — 4,008 — 8,949 — — — — — — — 315 14 505 476 (501) — 809 — 5,296 — 4,462 — 9,757 507 272 779 488 208 696 10,381 8,060 18,441 11,037 8,908 19,945 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped At 31 December Developed Undeveloped 307 308 615 79 113 192 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent. d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. f Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 24 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted entities. g Includes 283 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. h Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. i Includes 565 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 107 mmboe held through BP’s interests in Russia other than Rosneft. j Total proved reserves held as part of our equity interest in Rosneft is 8,163 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 62 million barrels of oil equivalent in Venezuela, 3 million barrels of oil equivalent in Vietnam, 35 million barrels of oil equivalent in Egypt and 8,063 million barrels of oil equivalent in Russia. BP Annual Report and Form 20-F 2018 221 Movements in estimated net proved reserves – continued Crude oila b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiond Sales of reserves-in-place At 31 Decembere Developed Undeveloped Equity-accounted entities (BP share)f At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberg Developed Undeveloped Europe North America South America Africa Asia Australasia UK Rest of Europe USc Rest of North America Russia Rest of Asia million barrels 2017 Total 155 274 429 15 — 3 — (29) (9) (20) 245 164 409 — — — — — — — — — — — — — 155 274 429 826 — — 497 — 1,322 42 209 251 — — — — — — — 208 12 1 12 (131) — 101 5 — — — (7) — (2) — 932 492 — — 1,423 54 195 248 45 69 114 2 11 34 1 (11) (5) 31 56 89 145 45 69 114 — — — — — — — — — — — — — 826 497 1,322 932 492 1,423 — — — — — — — — — — — — — 42 209 251 54 195 249 9 11 20 1 — — — (5) — (4) 10 6 16 321 325 646 1 4 — 22 (28) (98) (98) 285 263 548 330 336 666 295 269 564 317 42 358 35 2 1 — (88) — (50) 281 28 309 — 1,107 — 245 — 1,352 — — — — — — — 407 — — 42 (119) — 330 — 1,040 642 — — 1,682 3,162 1 — 2,134 5,296 1 — — — — — — — 102 — 37 264 (325) — 78 1 3,124 — 2,251 5,374 1 43 1 44 (1) — — — (36) — (37) 6 — 6 318 42 360 282 28 310 3,162 2,134 5,296 3,124 2,251 5,374 1,150 246 1,395 1,047 642 1,688 32 14 46 2 — — — (6) — (4) 31 11 42 2,487 1,291 3,778 673 14 5 53 (384) (9) 351 2,592 1,537 4,129 — 3,573 — 2,529 — 6,101 — — — — — — — 104 16 71 288 (401) (103) (25) — 3,473 — 2,603 — 6,076 32 14 46 31 11 42 6,060 3,819 9,879 6,064 4,140 10,205 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped At 31 December Developed Undeveloped 245 164 409 56 89 145 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 Includes 5 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Includes 337 million barrels of crude oil in respect of the 6.31% non-controlling interest in Rosneft, including 6 mmbbl held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha. g Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,402 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 59 million barrels in Venezuela and 5,342 million barrels in Russia. 222 BP Annual Report and Form 20-F 2018 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 2017 Total UK 13 3 16 2 — — — (3) (1) (2) 11 3 14 — — — — — — — — — — — — — Rest of Europe — — — — — — — — — — — — — 3 2 5 — 1 2 — (1) — 3 4 4 8 3 2 5 4 4 8 Rest of North America Russia Rest of Asia — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 5 28 33 — — — — (3) — (3) 2 28 30 — — — — — — — — — — — — — 5 28 33 2 28 30 13 1 14 11 — — — (4) — 7 21 — 21 11 — 11 1 — — — (1) — (1) 10 — 10 24 1 25 31 — 31 — — — — — — — — — — — — — 50 15 65 68 — — — (2) — 66 82 49 131 50 15 65 82 49 131 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — US 226 73 299 (44) 15 — 1 (24) — (52) 177 69 246 — — — — — — — — — — — — — 226 73 299 177 69 246 9 2 11 (4) — — — (1) — (5) 5 1 6 — — — — — — — — — — — — — 9 2 11 5 1 6 266 107 373 (36) 15 — 1 (35) (1) (55) 216 102 318 65 17 81 69 1 2 — (4) — 68 97 53 149 331 123 454 313 154 467 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped 13 3 16 At 31 December Developed Undeveloped 11 3 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 2 thousand barrels per day for equity-accounted entities. d Includes 9 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 131 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 131 million barrels in Russia. BP Annual Report and Form 20-F 2018 223 Movements in estimated net proved reserves – continued Total liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiond Sales of reserves-in-place At 31 Decembere Developed Undeveloped Equity-accounted entities (BP share)f At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberg h Developed Undeveloped Europe North America South America Africa Asia Australasia UK Rest of Europe USc Rest of North America Russia Rest of Asia million barrels 2017 Total 168 277 445 17 — 3 — (32) (10) (22) 256 167 424 — — — — — — — — — — — — — 168 277 445 — 1,051 — 569 — 1,621 42 209 251 — — — — — — — 164 27 1 12 (155) — 49 5 — — — (7) — (2) — 1,108 561 — — 1,669 54 195 248 48 71 119 2 13 36 1 (12) (6) 34 60 93 153 48 71 119 — — — — — — — — — — — — — 1,051 569 1,621 1,108 561 1,669 — — — — — — — — — — — — — 42 209 251 54 195 249 14 39 53 1 — — — (8) — (7) 12 34 46 321 325 646 1 4 — 22 (28) (98) (98) 285 263 548 335 364 699 297 297 594 330 43 372 45 2 1 — (92) — (43) 301 28 329 — 1,107 — 245 — 1,352 — — — — — — — 407 — — 42 (119) — 330 — 1,040 642 — — 1,682 3,213 12 — 2,148 5,361 12 1 — — — (2) — (1) 170 — 37 264 (327) — 144 11 3,206 — 2,300 5,505 12 43 1 44 (1) — — — (36) — (37) 6 — 6 342 43 385 313 28 341 3,213 2,148 5,361 3,206 2,300 5,505 1,150 246 1,395 1,047 642 1,688 42 16 57 (2) — — — (7) — (9) 36 12 48 2,753 1,398 4,151 637 29 5 54 (419) (10) 296 2,808 1,639 4,447 — 3,637 — 2,545 — 6,183 — — — — — — — 174 17 72 288 (405) (104) 43 — 3,569 — 2,656 — 6,225 42 16 57 36 12 48 6,390 3,943 10,333 6,377 4,295 10,672 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped At 31 December Developed Undeveloped 256 167 424 60 93 153 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 Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 2 thousand barrels per day for equity-accounted entities. e Also includes 14 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. g Includes 338 million barrels in respect of the non-controlling interest in Rosneft, including 6 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 5,533 million barrels, comprising less than 1 million barrels in Canada, 59 million barrels in Venezuela, less than 1 million barrels in Vietnam and 5,473 million barrels in Russia. 224 BP Annual Report and Form 20-F 2018 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 UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia 2017 Total billion cubic feet Russia Rest of Asia 499 350 848 50 — 25 — (77) (4) (5) 523 320 843 — — — — — — — — — — — — — 499 350 848 — 5,447 — 2,567 — 8,014 (38) — — 1,002 — — — 10 (664) — — — 309 — — 5,238 — 3,086 — 8,323 — 1,784 — 4,970 — 6,755 767 2,191 2,958 — 1,890 — 3,769 — 5,659 3,012 1,643 4,654 13,398 15,490 28,888 3 — — — (3) — — (677) — — 829 (714) — (562) (450) 1 527 14 (380) — (288) 258 — 6 — — — — 1,229 (152) — — — — 1,342 (129) (983) — 1,009 — 552 — 2,082 (2,281) (4) 376 (291) — (420) (1) 2,862 — 3,330 6,193 (1) 1,159 1,510 2,670 — 2,755 — 4,245 — 7,000 2,730 1,505 4,235 15,266 13,997 29,263 89 21 110 19 37 39 1 (19) (6) 70 112 69 180 89 21 110 — — — — — — — — — — — — — 5,447 2,567 8,014 5,238 3,086 8,323 — 1,546 534 — 2,080 1 — — — — — — — 47 55 — 67 (178) (347) (356) — 1,274 — 450 — 1,724 — 3,330 — 5,505 — 8,835 — 4,136 — 3,781 — 7,917 412 5,544 — 6,304 11,847 412 5 — 237 — (32) — 210 476 146 622 1,179 2,191 3,370 1,635 1,656 3,291 1,556 — 10 324 (488) — 1,403 6,077 7,173 13,250 5,544 6,304 11,847 6,077 7,173 13,250 26 4 30 (2) — — — (8) — (10) 17 3 20 — 7,617 — 6,863 — 14,480 — 1,625 92 — 286 — 392 — (726) — (353) — — 1,316 — 7,955 — 7,841 — 15,796 1,916 3,772 5,688 2,771 4,249 7,020 3,012 1,643 4,654 2,730 1,505 4,235 21,015 22,353 43,368 23,221 21,838 45,060 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped At 31 December Developed Undeveloped 523 320 843 112 69 180 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes 180 billion cubic feet of natural gas consumed in operations, 131 billion cubic feet in subsidiaries, 49 billion cubic feet in equity-accounted entities. d Includes 1,860 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 306 billion cubic feet of natural gas in respect of the 2.30% non-controlling interest in Rosneft including 2 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 13,522 billion cubic feet, comprising 0 billion cubic feet in Canada, 28 billion cubic feet in Venezuela, 19 billion cubic feet in Vietnam, 237 billion cubic feet in Egypt and 13,237 billion cubic feet in Russia. BP Annual Report and Form 20-F 2018 225 Movements in estimated net proved reserves – continued Total hydrocarbonsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione f Sales of reserves-in-place At 31 Decemberg Developed Undeveloped Equity-accounted entities (BP share)h At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione Sales of reserves-in-place At 31 Decemberi j Developed Undeveloped Europe North America South America UK Rest of Europe USd Rest of North America million barrels of oil equivalent c 2017 Africa Asia Australasia Total 254 338 592 25 — 8 — (45) (11) (23) 347 222 569 — — — — — — — — — — — — — 254 338 592 — 1,990 — 1,012 — 3,002 42 209 251 321 896 1,217 — — — — — — — 157 200 1 14 (270) — 102 5 — — — (8) — (2) (116) — — 143 (131) — (104) — 2,011 — 1,093 — 3,104 54 195 248 505 608 1,114 462 420 882 (32) 2 92 3 (157) — (93) 501 288 790 Russia Rest of Asia — 1,433 — 895 — 2,327 — — — — — — — 451 1 — 254 (145) — 562 — 1,515 — 1,374 — 2,889 63 75 138 5 19 42 1 (15) (7) 46 80 105 184 63 75 138 — — — — — — — — — — — — — 1,990 1,012 3,002 2,011 1,093 3,104 588 — — 417 — 1,005 4,168 83 — 3,235 7,404 83 — — — — — — — — — — 42 209 251 54 195 249 9 14 — 34 (58) (158) (159) 505 341 846 909 1,313 2,222 1,010 949 1,959 2 — 41 — (7) — 35 93 25 119 545 420 966 595 314 908 439 — 38 320 (411) — 386 4,254 3,536 7,790 4,168 3,235 7,404 4,254 3,536 7,790 47 1 49 (1) — — — (38) — (39) 9 1 10 1,480 896 2,376 1,524 1,374 2,899 561 299 860 (24) — — — (57) — (81) 507 272 779 5,063 4,068 9,131 467 203 100 413 (812) (11) 361 5,440 4,052 9,492 — 4,951 — 3,729 — 8,679 — — — — — — — 454 33 122 355 (530) (165) 269 — 4,941 — 4,008 — 8,949 561 299 860 507 272 779 10,014 7,797 17,810 10,381 8,060 18,441 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped At 31 December Developed Undeveloped 347 222 569 80 105 184 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 Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 2 thousand barrels per day for equity-accounted entities. f Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 23 million barrels of oil equivalent in subsidiaries, 8 million barrels of oil equivalent in equity-accounted entities. g Includes 335 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. h Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. i Includes 391 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 7 mmboe held through BP’s equity accounted interest in Taas-Yuryakh Neftegazodobycha. j Total proved reserves held as part of our equity interest in Rosneft is 7,864 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 64 million barrels of oil equivalent in Venezuela, 3 million barrels of oil equivalent in Vietnam, 41 million barrels of oil equivalent in Egypt and 7,755 million barrels of oil equivalent in Russia. 226 BP Annual Report and Form 20-F 2018 Movements in estimated net proved reserves – continued 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 UK Rest of Europe USc Rest of North America Russia Rest of Asiad million barrels 2016 Total 141 298 440 13 — 3 2 (29) — (11) 155 274 429 — — — — — — — — — — — — — 141 298 440 86 19 106 — — — — (9) (97) (106) 890 577 1,467 46 205 252 (30) 1 3 — (119) (1) (145) — — — 4 (5) — (1) — 826 497 — — 1,322 42 209 251 — — — — — 116 — (3) — 114 45 69 114 86 19 106 — — — — — — — — — — — — — 890 577 1,467 826 497 1,322 — — — — — — — — — — — — — 47 205 252 42 209 251 8 18 26 (2) — — — (4) — (6) 9 11 20 311 311 622 (2) 1 36 16 (28) — 24 321 325 646 319 329 648 330 336 666 340 89 429 22 3 — — (96) — (71) 317 42 358 — — — — — — — — — — 598 192 790 543 70 25 — (75) (1) 562 — 1,107 245 — — 1,352 2,844 2 — 1,981 4,825 2 — — — — — — — 33 4 456 285 (305) (2) 471 1 3,162 — 2,134 5,296 1 68 — 68 13 — — — (37) (1) (25) 43 1 44 342 89 431 318 42 360 2,844 1,981 4,825 3,162 2,134 5,296 666 192 858 1,150 246 1,395 35 16 51 2 — 1 — (6) (2) (5) 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 35 16 51 32 14 46 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 At 31 December Developed Undeveloped 155 274 429 45 69 114 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 6 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. BP Annual Report and Form 20-F 2018 227 Movements in estimated net proved reserves – continued Europe North America South America Africa Asia Australasia million barrels 2016 Total Rest of Europe Rest of North America US Russia Rest of Asia 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 UK 5 4 10 7 — 1 — (2) — 7 13 3 16 — — — — — — — — — — — — — 5 4 10 11 1 12 — — — — (1) (10) (12) — — — — — — — — 5 — — — 5 3 2 5 11 1 12 269 70 339 (24) 3 4 — (24) — (40) 226 73 299 — — — — — — — — — — — — — 269 70 339 226 73 299 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 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 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 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 Total subsidiaries and equity-accounted entities (BP share) At 1 January Developed Undeveloped At 31 December Developed Undeveloped 13 3 16 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. 228 BP Annual Report and Form 20-F 2018 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 UK Rest of Europe USc Rest of North America Russia Rest of Asia million barrels 2016 Total 147 303 449 20 — 5 2 (31) — (4) 168 277 445 — — — — — — — — — — — — — 147 302 449 98 20 117 — — — — (10) (108) (117) 1,159 647 1,806 46 205 252 (54) 5 7 — (143) (1) (185) — — — 4 (5) — (1) — 1,051 569 — — 1,621 42 209 251 — — — — — 122 — (3) — 119 48 71 119 98 20 117 — — — — — — — — — — — — — 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 — — — — — — — — — — 598 192 790 543 70 25 — (75) (1) 562 — 1,107 245 — — 1,352 2,876 14 — 1,996 4,872 14 (2) — — — — — (2) 51 4 456 285 (305) (2) 489 12 3,213 — 2,148 5,361 12 68 — 68 13 — — — (37) (1) (25) 43 1 44 360 99 459 342 43 385 2,876 1,996 4,872 3,213 2,148 5,361 666 192 858 1,150 246 1,395 45 18 63 3 — 1 — (7) (2) (5) 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 45 18 63 42 16 57 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 At 31 December Developed Undeveloped 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 6 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. BP Annual Report and Form 20-F 2018 229 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 UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia 2016 Total billion cubic feet Russia Rest of Asia 348 343 691 133 — 95 — (71) — 158 499 350 848 — — — — — — — — — — — — — 348 343 691 274 14 288 — — — — (33) (256) (288) 6,257 2,105 8,363 (231) 469 91 1 (676) (2) (348) — 2,071 — 5,989 — 8,060 847 2,305 3,152 — 1,803 — 3,455 — 5,257 3,408 1,343 4,751 15,009 15,553 30,563 (1,042) 3 42 — — — 355 — (624) (4) — (37) — (1,306) (19) 1 — 43 (219) — (194) — — — — — — — 548 22 — — (152) (17) 401 396 — 252 — (306) (439) (97) (211) 534 438 399 (2,085) (750) (1,675) — 5,447 — 2,567 — 8,014 — 1,784 — 4,970 — 6,755 767 2,191 2,958 — 1,890 — 3,769 — 5,659 3,012 1,643 4,654 13,398 15,490 28,888 — — — — — 115 — (4) — 110 89 21 110 274 14 288 — — — — — — — — — — — — — 6,257 2,105 8,363 5,447 2,567 8,014 1 — 1 — — — — — — — 1,463 598 2,061 62 1 19 128 (190) — 20 — 1,546 534 — 2,080 1 1 3,534 — 6,587 10,121 1 — 3,330 — 5,505 — 8,835 386 4,962 — 6,176 11,139 386 34 — — — (8) — 26 736 10 81 343 (461) (1) 709 412 5,544 — 6,304 11,847 412 44 4 48 5 — — — (15) (8) (18) 26 4 30 — 6,856 — 6,778 — 13,634 — — — — — — — 836 11 216 471 (680) (8) 846 — 7,617 — 6,863 — 14,480 1,233 2,305 3,538 1,179 2,191 3,370 4,962 6,176 11,139 5,544 6,304 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 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 At 31 December Developed Undeveloped 499 350 848 89 21 110 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 1 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. 230 BP Annual Report and Form 20-F 2018 Movements in estimated net proved reserves – continued Europe North America South America UK Rest of Europe USd Rest of North America million barrels of oil equivalentc 2016 Africa Asia Australasia Total 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 145 22 167 — — — — (16) (152) (167) 2,238 1,010 3,248 46 205 252 373 1,078 1,451 (94) 86 23 — (260) (1) (245) 1 — — 4 (5) — (1) (181) 7 — 61 (114) (7) (233) — 1,990 — 1,012 — 3,002 42 209 251 321 896 1,217 492 496 988 20 3 — 8 (136) — (105) 462 420 882 Russia Rest of Asia 909 — — 788 — 1,696 — — — — — — — 637 74 25 — (101) (4) 631 — 1,433 895 — — 2,327 — — — — — 142 — (3) — 138 63 75 138 — — — — — — — — — — — — — — — — — — — — — — — 563 415 978 9 1 39 38 (61) — 27 3,732 81 — 3,061 6,792 81 4 — — — (2) — 2 178 6 470 344 (385) (2) 611 588 — — 417 — 1,005 83 4,168 — 3,235 7,404 83 76 1 77 14 — — — (40) (2) (28) 47 1 49 207 362 568 43 — 21 2 (43) — 23 254 338 592 — — — — — — — — — — — — — 207 362 568 632 250 882 71 — 44 — (60) (78) (22) 561 299 860 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 — 8,679 632 250 882 561 299 860 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 At 31 December Developed Undeveloped 254 338 592 63 75 138 145 22 167 2,238 1,010 3,248 1,990 1,012 3,002 47 205 252 42 209 251 936 1,493 2,429 909 1,313 2,222 573 496 1,069 545 420 966 3,732 3,061 6,792 4,168 3,235 7,404 984 788 1,773 1,480 896 2,376 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 6 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. BP Annual Report and Form 20-F 2018 231 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 UK Rest of Europe Rest of North America US Russia Rest of Asia $ million 2018 Total At 31 December Subsidiaries Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd Standardized measure of discounted future net cash flowse f Equity-accounted entities (BP share)g Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd Standardized measure of discounted future net cash flowsh i 39,700 15,000 2,100 8,900 13,700 5,000 — 160,000 — 57,600 — 17,800 — 16,600 — 68,000 — 29,900 4,100 3,400 1,100 17,500 7,200 2,800 — 3,200 4,300 700 (400) (200) 30,400 8,500 2,600 5,300 14,000 3,300 — 147,500 — 55,800 — 16,400 — 51,100 — 24,200 9,400 — 30,000 429,200 7,600 155,100 45,300 2,500 92,000 6,900 13,000 136,800 53,900 5,800 8,700 — 38,100 (200) 3,600 10,700 — 14,800 7,200 82,900 — 12,800 — 4,200 — 800 — 5,900 — 1,900 600 — — 1,300 — — — — — — — — 38,500 — 16,100 — 3,600 — 4,400 — 14,400 — 8,500 — 356,800 — 232,100 — 19,300 — 24,000 — 81,400 — 48,100 — 5,900 — 33,300 — — — — — — — — 408,100 — 252,400 — 23,700 — 34,300 — 97,700 — 57,200 — 40,500 Total subsidiaries and equity-accounted entities Standardized measure of discounted future net cash flows 8,700 1,300 38,100 (200) 9,500 10,700 33,300 14,800 7,200 123,400 The following are the principal sources of change in the standardized measure of discounted future net cash flows: 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 Equity-accounted entities (BP share) (18,800) 8,500 5,800 41,000 (2,100) (17,000) 1,000 7,600 5,200 31,200 (8,000) 4,300 3,500 15,800 2,100 (7,600) (3,500) 400 3,100 10,100 $ million Total subsidiaries and equity-accounted entities (26,800) 12,800 9,300 56,800 — (24,600) (2,500) 8,000 8,300 41,300 a The marker prices used were Brent $71.43/bbl, Henry Hub $3.10/mmBtu. b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included. c Taxation is computed with reference to appropriate year-end statutory corporate income tax rates. d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. e In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and vice versa. This can result in the standardized measure of discounted future net cash flows being negative. f Non-controlling interests in BP Trinidad and Tobago LLC amounted to $1,100 million. g The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. h Non-controlling interests in Rosneft amounted to $2,500 million in Russia. i No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs. 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 changes to US dollars are included within ‘Net changes in prices and production cost’. 232 BP Annual Report and Form 20-F 2018 Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves – continued  Europe North America South America Africa Asia Australasia UK Rest of Europe Rest of North America US Russia Rest of Asia $ million 2017 Total 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 26,300 13,800 1,700 4,200 6,600 2,100 — 99,200 — 46,700 — 12,100 — 6,500 — 33,900 — 13,100 7,100 4,100 1,100 15,200 7,100 2,400 — 1,700 4,000 500 1,900 1,100 27,000 8,600 3,400 3,800 11,200 3,400 — 118,800 — 52,600 — 18,200 — 33,200 — 14,800 — 5,500 26,200 319,800 8,400 141,300 42,100 3,200 54,200 4,800 82,200 9,800 30,500 4,800 4,500 — 20,800 800 3,500 7,800 — 9,300 5,000 51,700 — 9,000 — 4,100 — 800 — 3,100 — 1,000 400 — — 600 — — — — — — — — 32,900 — 15,500 — 3,400 — 3,100 — 10,900 — 6,400 — 205,100 — 114,900 — 17,600 — 12,400 — 60,200 — 34,900 — 4,500 — 25,300 400 300 100 — — — — — 247,400 — 134,800 — 21,900 — 18,600 — 72,100 — 41,700 — 30,400 Total subsidiaries and equity-accounted entities Standardized measure of discounted future net cash flows 4,500 600 20,800 800 8,000 7,800 25,300 9,300 5,000 82,100 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 yeari Subsidiaries Equity-accounted entities (BP share) (12,800) 9,800 2,300 33,100 2,800 (12,500) 3,000 800 2,300 28,800 (5,500) 4,200 1,300 7,300 1,000 (1,500) (4,600) (600) 2,600 4,200 $ million Total subsidiaries and equity-accounted entities (18,300) 14,000 3,600 40,400 3,800 (14,000) (1,600) 200 4,900 33,000 a The marker prices used were Brent $54.36/bbl, Henry Hub $2.96/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 $1,100 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 $1,963 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 changes to US dollars are included within ‘Net changes in prices and production cost’. BP Annual Report and Form 20-F 2018 233 Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves – continued Europe North America South America Africa Asia Australasia UK Rest of Europe Rest of North America US Russia Rest of Asia $ million 2016 Total 21,600 13,900 3,000 1,700 3,000 900 — 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 — 78,100 — 42,600 — 15,400 — 17,800 — 2,300 (600) — 24,000 235,900 9,400 129,100 46,100 3,500 25,500 3,400 35,200 7,700 12,300 4,100 2,100 — 9,600 (100) 1,100 3,700 — 2,900 3,600 22,900 — 5,400 — 3,000 — 700 — 1,300 400 — 200 — — 200 — — — — — — — — 34,400 — 16,500 — 3,800 — 3,600 — 10,500 — 6,100 — 159,900 — 84,300 — 13,200 — 10,100 — 52,300 — 30,700 1,900 1,200 700 — — — — 201,600 — 105,000 — 18,400 — 15,000 — 63,200 — 37,000 — 4,400 — 21,600 — — 26,200 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 Total subsidiaries and equity-accounted entities Standardized measure of 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 Equity-accounted entities (BP share) (15,200) 13,100 700 (25,500) 12,200 (2,500) 4,900 1,800 3,000 (7,500) (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 to US dollars are included within ‘Net changes in prices and production cost’. 234 BP Annual Report and Form 20-F 2018 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 2018, 2017 and 2016. Production for the yeara b Europe North America South America Africa Asia Australasia Total UK Rest of Europe Subsidiariese Crude oilf 2018 2017 2016 Natural gas liquids 2018 2017 2016 Natural gasg 2018 2017 2016 Equity-accounted entities (BP share) Crude oilf 2018 2017 2016 Natural gas liquids 2018 2017 2016 Natural gasg 2018 2017 2016 101 80 79 5 6 6 152 182 170 — — — — — — — — — — — 24 — — 4 — — 82 34 31 7 2 2 — 59 53 12 US 385 370 335 60 56 56 1,900 1,659 1,656 — — — — — — — — — Rest of North America Russiac Rest of Asiad 24 20 13 — — — 7 9 10 — — — — — — — — — 7 12 10 9 10 8 204 241 263 11 10 5 2,136 1,936 1,689 1,061 949 513 55 63 65 — — 1 335 418 449 1 1 — 6 6 4 80 77 18 — — — — — — — — — 933 905 840 4 4 4 1,286 1,308 1,279 thousand barrels per day 17 17 16 1,051 1,064 943 thousand barrels per day 2 2 3 88 85 82 million cubic feet per day 819 783 820 6,900 5,889 5,302 thousand barrels per day — — — 1,040 1,099 1,015 thousand barrels per day — — — 12 12 8 million cubic feet per day — — — 1,760 1,855 1,773 313 325 204 — — — 826 371 363 16 99 102 — — — — — 15 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. BP Annual Report and Form 20-F 2018 235 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 2018. 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. Number of productive wells at 31 December 2018 Oil wellsc Gas wellsd Undevelopede – gross – net – gross – net – gross – net – gross – net Oil and natural gas acreage at 31 December 2018 Developed Europe UK Rest of Europe South America North America US Rest of North America 116 69 34 5 81 46 3,067 1,861 2,677 74 1,097 22 1 20,565 — 10,602 169 45 244 121 57 17 180 54 6,263 3,683 5,012 3,700 147 64 17,110 8,750 5,356 2,437 1,069 379 1,336 355 19,890 6,469 Africa Asia Australasia Totalb Russiaa 66,147 13,151 512 114 695 466 209 89 868 345 52,698 36,504 6,751 1,297 431,130 86,045 Rest of Asia 1,979 445 102 45 1,290 272 8,586 2,357 77,225 12 17,734 2 22,814 78 11,371 16 thousands of acres 173 41 4,022 1,889 16,966 6,120 541,695 147,629 a Based on information received from Rosneft as at 31 December 2018. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes approximately 7,381 gross (1,447 net) multiple completion wells (more than one formation producing into the same well bore). d Includes approximately 2,768 gross (1,407 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 2018 Exploratory Productive Dry Development Productive Dry 2017 Exploratory Productive Dry Development Productive Dry 2016 Exploratory Productive Dry Development Productive Dry UK Rest of Europe 0.3 — 1.4 — 2.8 2.4 2.5 — 0.3 1.0 3.4 0.8 — — 0.6 — 0.1 — 0.5 — 0.4 0.3 1.4 — US 1.7 — 142.7 6.8 1.5 — 124.0 0.5 0.5 4.7 145.6 — Rest of North America Russia Rest of Asia — 0.5 5.0 — 1.2 — 8.0 — — — — — 2.0 2.0 103.9 3.6 3.2 — 103.7 1.6 0.6 — 99.8 0.6 — 2.4 14.4 — 2.6 2.9 16.5 2.1 2.1 1.5 20.2 2.0 15.0 — 137.3 — 9.4 — 282.7 — 3.4 — 88.5 — 5.0 — 53.5 2.6 1.4 1.0 43.6 0.8 1.6 0.3 55.2 1.0 — — 1.3 — — — 1.1 — — — 0.5 — 24.0 4.9 460.1 13.0 22.2 6.3 582.6 5.0 8.9 7.8 414.6 4.4 a Because of rounding, some totals may not exactly agree with the sum of their component parts. 236 BP Annual Report and Form 20-F 2018 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 2018. 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 2018 Exploratory Gross Net Development Gross Net UK — — 9.0 2.9 Rest of Europe 0.9 0.3 4.6 1.4 US 5.0 2.9 147.0 80.5 Rest of North America — — 5.0 2.5 a Because of rounding, some totals may not exactly agree with the sum of their component parts. Russia Rest of Asia 3.0 0.8 11.0 5.0 3.0 1.3 18.0 9.2 — — — — 3.0 3.0 108.0 19.0 — — — — 14.9 8.3 302.6 120.5 BP Annual Report and Form 20-F 2018 237 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 Payablesa Non-current liabilities Payablesa Deferred tax liabilities Defined benefit pension plan deficits Total liabilities Net assets Capital and reservesb 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 2018 2 3 4 3 5 5 6 4 7 $ million 2017 166,276 2,623 3,838 172,737 293 10 303 173,040 166,271 2,600 5,473 174,344 151 13 164 174,508 14,665 10,203 31,800 1,907 184 33,891 48,556 125,952 101,078 1,931 (6,579) 96,430 5,402 12,305 11,815 125,952 31,804 1,337 221 33,362 43,565 129,475 104,498 2,145 (5,565) 101,078 5,343 12,147 10,907 129,475 a A re-presentation from non-current payables to current payables has been made in 2017. See Note 5 for details. b See Statement of changes in equity on page 239 for further information. The financial statements on pages 238-271 were approved and signed by the group chief executive on 29 March 2019 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 238-271 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 2018 Company statement of changes in equitya Share capital Share premium account Capital redemption reserve 5,343 — — — 49 (13) 23 5,402 5,284 — — — 72 (13) — 5,343 12,147 — — — (49) — 207 12,305 12,219 — — — (72) — — 12,147 1,426 — — — — 13 — 1,439 1,413 — — — — 13 — 1,426 Merger reserve 26,509 — — — — — — 26,509 26,509 — — — — — — 26,509 $ million Foreign currency translation reserve Profit and loss account Total equity (70) — (296) (296) — — — (366) (236) — 166 166 — — — (70) 101,078 1,931 1,178 3,109 (6,699) (355) (703) 96,430 104,498 2,145 1,815 3,960 (6,153) (343) (884) 101,078 129,475 1,931 882 2,813 (6,699) (355) 718 125,952 131,244 2,145 1,981 4,126 (6,153) (343) 601 129,475 Treasury shares (16,958) — — — — — 1,191 (15,767) (18,443) — — — — — 1,485 (16,958) At 1 January 2018 Profit for the year Other comprehensive income Total comprehensive income Dividends Repurchases of ordinary share capital Share-based payments, net of tax At 31 December 2018 At 1 January 2017 Profit for the year Other comprehensive income Total comprehensive income Dividends Repurchases of ordinary share capital Share-based payments, net of tax At 31 December 2017 a See Note 8 for further information. The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 239 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 2018 were approved and signed by the group chief executive on 29 March 2019 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) (g) 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. the requirement of the second sentence of paragraph 110 and paragraphs 113(a), 114,115, 118, 119(a) to (c), 120 to 127 and 129 of IFRS 15 Revenue from Contracts with Customers Where required, equivalent disclosures are given in the consolidated financial statements of BP p.l.c. As permitted by Section 408 of the Companies Act 2006, the income statement of the company is not presented as part of these financial statements. The financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where otherwise indicated. Significant accounting policies: use of judgements, estimates and assumptions Inherent in the application of many of the accounting policies used in preparing the financial statements is the need for management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and assumptions used. The accounting judgements and estimates that have a significant impact on the results of the company are set out in boxed text below, and should be read in conjunction with the information provided in the Notes 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. Where these circumstances have reversed, the impairment previously made is reversed to the extent of the original cost of the investment. Foreign currency translation The functional and presentation currency of the financial statements is US dollars. Transactions in foreign currencies are initially recorded in the functional currency by applying the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included in the income statement. Non-monetary assets and liabilities, other than those measured at fair value, are not retranslated subsequent to initial recognition. Exchange adjustments arising when the opening net assets and the profits for the year retained by a non-US dollar functional currency branch are translated into US dollars are recognized in a separate component of equity and reported in other comprehensive income. Income statement transactions are translated into US dollars using the average exchange rate for the reporting period. Financial guarantees The company enters into financial guarantee contracts with its subsidiaries. At the inception of a financial guarantee contract, a liability is recognized initially at fair value and then subsequently 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 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 240 BP Annual Report and Form 20-F 2018 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, unless their fair value cannot be reliably estimated. If the fair value of the goods and services received cannot be reliably estimated, the transaction is measured by reference to the fair value of the equity instruments granted. Cash-settled transactions The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the corresponding liability which is recognized on the balance sheet. The liability is remeasured at fair value at each balance sheet date until settlement, with changes in fair value recognized in the income statement. Pensions The defined benefit pension plans are plans that share risks between entities under common control.  In each instance BP p.l.c. is the principal employer and carries the whole plan surplus or deficit on its balance sheet. The cost of providing benefits under the company’s defined benefit plans is determined separately for each plan using the projected unit credit method, which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to determine the present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company becomes committed to a change. Net interest expense relating to pensions, which is recognized in the income statement, represents the net change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking into account expected changes in the obligation or plan assets during the year. Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not subsequently reclassified to profit and loss. The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the present value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, typically by way of refund. Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable. Significant estimate: pensions Accounting for defined benefit pensions involves making significant estimates when measuring the company's pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties. Pension assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the company’s balance sheet, and pension expense for the following year. The assumptions used are provided in Note 4. The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate, salary growth and mortality levels. Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in material changes to the carrying amounts of the company’s pension obligations within the next financial year for the UK plan. Any differences between these assumptions and the actual outcome will also affect future net income and net assets. The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and obligation used are provided in Note 4. Income taxes Income tax expense represents the sum of current tax and deferred tax. Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity. Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are taxable or deductible in other periods as well as items that are never taxable or deductible. The company’s liability for current tax is calculated using tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for taxable temporary differences. Deferred tax assets are only recognized to the extent that it is probable that they will be realized in the future. The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 241 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. See note 6 for further details. Financial assets 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. The subsequent measurement of financial assets depends on their classification, as set out below. The company derecognizes financial assets when the contractual rights to the cash flows expire or the financial asset is transferred to a third party. Financial assets measured at amortized cost Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets are derecognized or impaired and when interest is recognized using the effective interest method. This category of financial assets includes trade and other receivables. Cash equivalents Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets measured at amortized cost. Financial liabilities All financial liabilities held by the company are classified as financial liabilities measured at amortized cost. Financial liabilities include other payables, accruals, and 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 directly attributable transaction costs. For interest-bearing loans and borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing. After initial recognition, financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively. This category of financial liabilities includes trade and other payables and finance debt. Impact of new International Financial Reporting Standards The company adopted two new accounting standards issued by the IASB with effect from 1 January 2018, IFRS 9 ‘Financial instruments’ and IFRS 15 ‘Revenue from contracts with customers’. There are no other new or amended standards or interpretations adopted during the year that have a significant impact on the financial statements. IFRS 9 ‘Financial Instruments’ IFRS 9 ‘Financial Instruments’ was issued in July 2014 and replaced IAS 39 ‘Financial Instruments: Recognition and Measurement.’ The company adopted IFRS 9 and the related consequential amendments to other IFRSs in the financial reporting period commencing 1 January 2018. The company has applied the new standard in accordance with the transition provisions of IFRS 9. Comparatives have not been restated and there were no material adjustments on transition reported in opening retained earnings at 1 January 2018. The company’s revised accounting policies in relation to financial instruments are provided above. IFRS 15 ‘Revenue from Contracts with Customers’ IFRS 15 ‘Revenue from Contracts with Customers’ was issued in May 2014 and replaced IAS 18 ‘Revenue’ and certain other standards and interpretations. IFRS 15 provides a single model for accounting for revenue arising from contracts with customers, focusing on the identification and satisfaction of performance obligations. The company adopted IFRS 15 from 1 January 2018 and applied the ‘modified retrospective’ transition approach to implementation. The company identified no changes in accounting as a result of implementing IFRS 15. The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 242 BP Annual Report and Form 20-F 2018 2. Investments Cost At 1 January 2018 Additions Disposals At 31 December 2018 Amounts provided At 1 January 2018 At 31 December 2018 Cost At 1 January 2017 Disposals Other movements At 31 December 2017 Amounts provided At 1 January 2017 Disposals At 31 December 2017 At 31 December 2018 At 31 December 2017 Subsidiaries Associates Shares Shares Total $ million 166,307 270 (275) 166,302 33 33 166,355 (41) (7) 166,307 74 (41) 33 166,269 166,274 2 — — 2 — — 2 — — 2 — — — 2 2 166,309 270 (275) 166,304 33 33 166,357 (41) (7) 166,309 74 (41) 33 166,271 166,276 The more important subsidiaries of the company at 31 December 2018 and the percentage holding of ordinary share capital (to the nearest whole number) are set out below. For a full list of related undertakings see Note 14. Subsidiaries International BP Global Investments BP International Burmah Castrol Canada BP Holdings Canada US % Country of incorporation Principal activities 100 England & Wales 100 England & Wales 100 Scotland Investment holding Integrated oil operations Lubricants 100 England & Wales Investment holding BP Holdings North America 100 England & Wales Investment holding The carrying value of the investment in BP International Limited at 31 December 2018 was $76,152 million (2017 $76,152 million). 3. Receivables  Amounts receivable from subsidiariesa Amounts receivable from associates Other receivables 2018 $ million 2017 Current Non-current Current Non-current 148 4 (1) 151 2,600 — — 2,600 289 4 — 293 2,623 — — 2,623 a Non-current receivables includes a promissory note issued by BP (Abu Dhabi) Limited in 2016 in consideration for the issue of BP p.l.c. ordinary shares to the government of Abu Dhabi. 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 2018 the aggregate level of contributions was $490 million (2017 $509 million). The aggregate level of contributions in 2019 is expected to be approximately $262 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. The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 243 4. Pensions – continued For the primary UK plan there is a funding agreement between the company and the trustee. On an annual basis the latest funding position is reviewed and a schedule of contributions is agreed covering the next five years. Contractually committed funding amounted to $1,275 million at 31 December 2018, all of which relates to future service. The surplus relating to the primary UK pension plan is recognized on the balance sheet on the basis that the company is entitled to a refund of any remaining assets once all members have left the plan. The obligation and cost of providing the pension benefits is assessed annually using the projected unit credit method. The date of the most recent actuarial review was 31 December 2018. The principal plans are subject to a formal actuarial valuation every three years in the UK. The most recent formal actuarial valuation of the main pension plan was as at 31 December 2017. The material financial assumptions used for estimating the benefit obligations of the plans are set out below. The assumptions are reviewed by management at the end of each year and are used to evaluate accrued pension benefits at 31 December and pension expense for the following year. Financial assumptions used to determine benefit obligation Discount rate for pension plan liabilities Rate of increase in salaries Rate of increase for pensions in payment Rate of increase in deferred pensions Inflation for pension plan liabilities Financial assumptions used to determine benefit expense Discount rate for pension plan service costs Discount rate for pension plan other finance expense Inflation for pension plan service costs 2018 2.9 3.8 3.0 3.0 3.1 2018 2.6 2.5 3.1 % 2017 2.5 4.1 2.9 2.9 3.1 % 2017 2.7 2.7 3.2 The discount rate assumption is based on third-party AA corporate bond indices and we use yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumption is based on the difference between the yields on index-linked and fixed-interest long- term government bonds. The inflation assumption is used to determine the rate of increase for pensions in payment and the rate of increase in deferred pensions. The assumption for the rate of increase in salaries is based on our inflation assumption plus an allowance for expected long-term real salary growth. This comprises of an allowance for promotion-related salary growth of 0.7%. In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best practice in the UK and have been chosen with regard to the latest available published tables adjusted to reflect the experience of the plans and an extrapolation of past longevity improvements into the future. For the main pension plan the mortality assumptions are as follows: Mortality assumptions Life expectancy at age 60 for a male currently aged 60 Life expectancy at age 60 for a male currently aged 40 Life expectancy at age 60 for a female currently aged 60 Life expectancy at age 60 for a female currently aged 40 2018 27.4 28.9 28.8 30.6 Years 2017 27.4 29.0 28.8 30.5 The assets of the primary plan are held in a trust, the primary objective of which is to accumulate pools of assets sufficient to meet the obligations of the plan. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management. A 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. The trustee’s long-term investment objective for the primary UK plan as it matures is to invest in assets whose value changes in the same way as the plan liabilities, in order to reduce the level of funding risk. To move towards this objective, the UK plan uses a liability driven investment (LDI) approach for part of the portfolio, investing primarily in government bonds to achieve this matching effect for the most significant plan liability assumptions of interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements, whereby the plan borrows money using existing bonds as security and which will be bought back at a specified price at an agreed future date. The funds raised are used to invest in further bonds to increase the proportion of assets which match the plan liabilities. The borrowings are shown separately in the analysis of pension plan assets in the table below. For the primary UK pension plan there is an agreement with the trustee to increase the proportion of assets with liability matching characteristics over time primarily by reducing the proportion of plan assets held as equities and increasing the proportion held as bonds. During 2018, the plan switched 12.5% from equities to bonds. 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 % 30 63 7 The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2018 were $4,197 million (2017 $2,588 million) of government-issued nominal bonds and $17,491 million (2017 $16,177 million) of index-linked bonds. The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 244 BP Annual Report and Form 20-F 2018 4. Pensions – continued 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 246. Fair value of pension plan assets Listed equities – developed markets – emerging markets Private equitya Government issued nominal bondsb Government issued index-linked bondsb Corporate bondsb Propertyc Cash Other Debt (repurchase agreements) used to fund liability driven investments 2018 5,191 950 2,792 4,263 17,491 4,606 2,311 376 116 (6,011) 32,085 $ million 2017 9,548 2,220 2,679 2,663 16,177 4,682 2,211 390 104 (5,583) 35,091 a Private equity is valued as fair value based on the most recent third-party net asset valuation. b Bonds held are denominated in sterling and valued using quoted prices in active markets. Where quoted prices are not available, quoted prices for similar instruments in active markets are used. c Property held is all located in the United Kingdom and are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party valuers. Analysis of the amount charged to profit or loss Current service costa Past service 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) 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 2018 295 15 310 38 348 (868) 773 (95) (722) 1,768 123 520 1,689 $ million 2017 357 12 369 31 400 (845) 830 (15) 2,396 (237) 734 91 2,984 a The costs of managing the fund’s investments are treated as being part of the investment return, the costs of administering our pensions plan benefits are included in current service cost. b Past service cost represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes. c The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above. The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 245 4. Pensions – continued Movements in benefit obligation during the year Benefit obligation at 1 January Exchange adjustments Operating charge relating to defined benefit plans Interest cost Contributions by plan participantsa Benefit payments (funded plans)b Benefit payments (unfunded plans)b Remeasurements Benefit obligation at 31 December Movements in fair value of plan assets during the year Fair value of plan assets at 1 January Exchange adjustments Interest income on plan assetsc Contributions by plan participantsa Contributions by employers (funded plans) Benefit payments (funded plans)b Remeasurementsc Fair value of plan assets at 31 Decemberd e Surplus at 31 December Represented by Asset recognized Liability recognized The surplus may be analysed between funded and unfunded plans as follows Funded Unfunded The defined benefit obligation may be analysed between funded and unfunded plans as follows Funded Unfunded 2018 31,474 (1,587) 310 773 21 (1,780) (4) (2,411) 26,796 35,091 (1,883) 868 21 490 (1,780) (722) 32,085 5,289 5,473 (184) 5,289 5,473 (184) 5,289 $ million 2017 29,871 2,882 369 830 16 (1,903) (3) (588) 31,474 30,180 3,048 845 16 509 (1,903) 2,396 35,091 3,617 3,838 (221) 3,617 3,838 (221) 3,617 (26,612) (184) (26,796) (31,253) (221) (31,474) a Most of the contributions made by plan participants were made under salary sacrifice. b  The benefit payments amount shown above comprises $1,764 million benefits (2017 $1,888 million) plus $20 million (2017 $18 million) of plan expenses incurred in the administration of the benefit. c  The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above. d  Reflects $31,818 million of assets held in the BP Pension Fund (2017 $34,841 million) and $203 million held in the BP Global Pension Trust (2017 $183 million), as well as $51 million representing the company’s share of Merchant Navy Officers Pension Fund (2017 $53 million) and $13 million of Merchant Navy Ratings Pension Fund (2017 $14 million). e  The fair value of plan assets includes borrowings related to the LDI programme as described on page 244. 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 2018 for the company’s plans would have had the effects shown in the table below. The effects shown for the expense in 2019 comprise the total of current service cost and net finance income or expense. Discount ratea Effect on pension expense in 2019 Effect on pension obligation at 31 December 2018 Inflation rateb Effect on pension expense in 2019 Effect on pension obligation at 31 December 2018 Salary growth Effect on pension expense in 2019 Effect on pension obligation at 31 December 2018 $ million One percentage point Increase Decrease (270) (4,137) 176 3,939 37 449 239 5,527 (145) (3,396) (33) (411) 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 2019 pension expense by $34 million and the pension obligation at 31 December 2018 by $965 million. The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 246 BP Annual Report and Form 20-F 2018 4. Pensions – continued Estimated future benefit payments and the weighted average duration of defined benefit obligations The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2028 and the weighted average duration of the defined benefit obligations at 31 December 2018 are as follows: Estimated future benefit payments 2019 2020 2021 2022 2023 2024-2028 Weighted average duration 5. Payables Amounts payable to subsidiariesa Accruals and deferred income Other payables $ million 1,027 1,034 1,054 1,086 1,118 5,766 Years 17.8 $ million 2017 2018 Current Non-current Current Non-current 14,559 31 75 14,665 31,765 — 35 31,800 10,070 60 73 10,203 31,755 — 49 31,804 a In 2017, an amount of $2,300 million has been reclassified from non-current payables to current payables. Included in non-current amounts payable to subsidiaries is an interest-bearing payable of $4,236 million (2017 $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 $27,100 million (2017 $27,100 million) with BP International Limited, with interest being charged based on a 3-month USD LIBOR rate plus 65 basis points and a maturity date of May 2023. Current amounts payable to subsidiaries also includes an interest-bearing payable of $5,000 million (2017 $2,300 million) with BP Finance plc, with interest being charged based on a 1-year USD LIBOR rate and a maturity date of April 2020, callable upon demand. 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 6. Taxation Tax charge included in total comprehensive income Deferred tax Origination and reversal of temporary differences in the current year This comprises: Taxable temporary differences relating to pensions Deferred tax Deferred tax liability Pensions Net deferred tax liability Analysis of movements during the year At 1 January Charge (credit) for the year in the income statement Charge (credit) for the year in other comprehensive income At 31 December 2018 40 31,520 240 31,800 2018 570 570 1,907 1,907 1,337 59 511 1,907 $ million 2017 73 4,530 27,201 31,804 $ million 2017 1,158 1,158 1,337 1,337 179 (11) 1,169 1,337 At 31 December 2018, deferred tax assets of $258 million on other temporary differences, $7 million relating to pensions, $67 million relating to income losses and $184 million relating to other deductible temporary differences (2017 $92 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. There is no fixed expiry date for the unrecognised temporary differences. The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 247 7. Called-up share capital The allotted, called-up and fully paid share capital at 31 December was as follows: Issued 8% cumulative first preference shares of £1 eacha 9% cumulative second preference shares of £1 eacha Ordinary shares of 25 cents each At 1 January Issue of new shares for the scrip dividend programme Issue of new shares for employee share-based payment plans Repurchase of ordinary share capital At 31 December Shares thousand 7,233 5,473 21,288,193 195,305 92,168 (50,202) 21,525,464 2018 $ million 12 9 21 5,322 49 23 (13) 5,381 5,402 Shares thousand 7,233 5,473 21,049,696 289,789 — (51,292) 21,288,193 2017 $ million 12 9 21 5,263 72 — (13) 5,322 5,343 a The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of preference shares. Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each. In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value. During 2018 the company repurchased 50 million ordinary shares at a cost of $355 million, including transaction costs of $2 million, as part of the share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The repurchased shares represented 0.2% of ordinary share capital. Treasury sharesa At 1 January Purchases for settlement of employee share plans Issue of new shares for employee share-based payment plans Shares re-issued for employee share-based payment plans At 31 December Of which - shares held in treasury by BP                - shares held in ESOP trusts - shares held by BP’s US plan administratorb Shares thousand 1,482,072 757 92,168 (148,732) 1,426,265 1,264,732 161,518 15 2018 Nominal value $ million 370 — 23 (37) 356 316 40 — Shares thousand 1,614,657 4,423 — (137,008) 1,482,072 1,472,343 9,705 24 2017 Nominal value $ million 403 1 — (34) 370 368 2 — 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 6.9% (2017 7.5%) of the called-up ordinary share capital of the company. During 2018, the movement in shares held in treasury by BP represented less than 1.0% (2017 less than 0.5%) of the ordinary share capital of the company. 8. Capital and reserves See statement of changes in equity for details of all reserves balances. Share capital The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury shares. Share premium account The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares. Capital redemption reserve The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled. Merger reserve The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in an acquisition made by the issue of shares. The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 248 BP Annual Report and Form 20-F 2018 8. Capital and reserves – continued 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 (2017 $24,107 million), the distribution of which is limited by statutory or other restrictions. The financial statements for the year ended 31 December 2018 do not reflect the dividend announced on 5 February 2019 and paid in March 2019; this will be treated as an appropriation of profit in the year ended 31 December 2019. 9. Financial guarantees The company has issued guarantees under which the maximum aggregate liabilities at 31 December 2018 were $77,965 million (2017 $75,824 million), the majority of which relate to finance debt of subsidiaries. Also included are guarantees of subsidiaries' liabilities under the Consent Decree between the United States, the Gulf states and BP and under the settlement agreement with the Gulf states in relation to the Gulf of Mexico oil spill. The company has also issued uncapped indemnities and guarantees, including a guarantee of subsidiaries’ liabilities under the Plaintiffs’ Steering Committee agreement relating to the Gulf of Mexico oil spill. Uncapped indemnities and guarantees are also issued in relation to potential losses arising from environmental incidents involving ships leased and operated by a subsidiary. 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 2018 429 (9) 420 27 23 $ million 2017 397 9 406 54 58 Additional information on the company’s share-based payment plans is provided in Note 11 to the consolidated financial statements. 11. Auditor’s remuneration Note 36 to the consolidated financial statements provides details of the remuneration of the company’s auditor on a group basis. 12. Directors’ remuneration Remuneration of directors Total for all directors Emoluments Amounts awarded under incentive schemesa Total a Excludes amounts relating to past directors. 2018 8 16 24 $ million 2017 9 9 18 Emoluments These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits earned during the relevant financial year, plus cash bonuses awarded for the year. Further information is provided in the Directors’ remuneration report on page 87. The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 249 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 2018 491 74 80 645 2018 269 1,151 2,344 3,764 $ million 2017 496 74 92 662 2017 262 1,125 2,384 3,771 The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 250 BP Annual Report and Form 20-F 2018 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 2018 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. (99.90%) 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 Oy Air BP Iceland Air BP Limited Air BP Norway AS Air BP Sales Romania S.R.L. Air BP Sweden AB Air Refuel Pty Ltdb Allgreen Pty Ltd AM/PM International Inc. American Oil Company Amoco (Fiddich) Limited Amoco (U.K.) Exploration Company, LLCa Amoco Bolivia Petroleum Company Amoco Bolivia Services Company Inc. Amoco Canada International Holdings B.V. Amoco Capline Pipeline Company Amoco Chemical (Europe) S.A. 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 and Fibers Ltd.c Amoco Guatemala Petroleum Company Amoco International Finance Corporation Amoco International Petroleum Company 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 Limitedd Amoco Nigeria Oil Company Limitedd Amoco Nigeria Petroleum Company Amoco Nigeria Petroleum Company Limited 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 d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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 Öljytie 4, 01530 Vantaa, Finland Armula 24, 108, Reykjavik, Iceland Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom P.O. Box, 153 Skoyen, Oslo, 0212, Norway 59 Aurel Vlaicu Street, Otopeni, Ilfov County, Romania Box 8107, 10420, Stockholm, Sweden 398 Tingira Street, Pinkenba QLD 4008, 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 Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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 d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands 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 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 Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 251 14. Related undertakings of the group – continued 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 Trinidad Gas B.V. Amoco Tri-States NGL Pipeline Company Amoco U.K. Petroleum Limited AmProp Finance Company Amprop Illinois I Limited Partnershipe Amprop, Inc. Anaconda Arizona, Inc. Arabian Production And Marketing Lubricants Company (50.00%) Aral Aktiengesellschaft Aral Luxembourg S.A. Aral Services Luxembourg Sarl Aral Tankstellen Services Sarl Aral Vertrieb GmbH ARCO British International, Inc. ARCO British Limited, LLCa ARCO Coal Australia Inc. ARCO El-Djazair Holdings Inc. ARCO El-Djazair LLC 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 Mediterraneo Inversiones, S.L ARCO Midcon LLCa 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 ARCO Unimar Holdings LLCa Areas Noriega S.L. Areas Singulares Reyes S.L. Aspac Lubricants (Malaysia) Sdn. Bhd. (63.03%) Atlantic 2/3 UK Holdings Limited Atlantic Richfield Company Autino Holdings Limited (88.85%)f Autino Limited (88.85%) Auwahi Wind Energy Holdings LLCa B2Mobility GmbH Bahia de Bizkaia Electridad, S.L. (75.00%) Baltimore Ennis Land Company, Inc. BHP Billiton Petroleum (Eagle Ford Gathering) LLC (75.00%)a BHP Billiton Petroleum (KCS Resources), LLCa BHP Billiton Petroleum (Tx Gathering), LLCa BHP Billiton Petroleum (TxLa Operating) Company BHP Billiton Petroleum (WSF Operating), Inc. BHP Billiton Petroleum Properties (GP), LLCa 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 d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 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 Riyadh Airport Road, Business Gate, Building C2, 2nd Floor., Saudi Arabia Wittener Straße 45, 44789 Bochum, Germany Bâtiment B, 36route de Longwy, L-8080 Bertrange, Luxembourg Autoroute A3/E25, L-3325 Brechem Ouest, Luxembourg Bâtiment B, 36route de Longwy, L-8080 Bertrange, Luxembourg Überseeallee 1, 20457, Hamburg, 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 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 Federico García Lorca, 43, entreplanta, 04004, Almería, Spain 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 Providence House, East Hill Street, P.O. Box N-3944, Nassau, Bahamas Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Ronda de Poniente 3, 1ªPlanta, 28760 Tres Cantos, Madrid, Spain Calle Velázquez 18, 28001 Madrid, Spain Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 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 83-85 London Street , Reading , Berkshire, RG1 4QA, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Wittener Straße 45, 44789 Bochum, Germany 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 Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States The Corporation Company, 1833 South Morgan Road,, Oklahoma City OK 73128, United States 350 North St. Paul Street, Suite 2900, Dallas, Texas 75201, United States 5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States CT Corporation System, 1021 Main Street, Suite 1150, Houston, Texas 77002, United States The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 252 BP Annual Report and Form 20-F 2018 14. Related undertakings of the group – continued BHP Billiton Petroleum Properties (LP) LLCa BHP Billiton Petroleum Properties (N.A.), LPe Black Lake Pipe Line Company BP - Castrol (Thailand) Limited (57.57%)g BP (Abu Dhabi) Limited BP (Barbados) Holding SRL BP (Barbican) Limitedh BP (China) Holdings Limiteda BP (China) Industrial Lubricants Limiteda BP (Gibraltar) Limitedi BP (Indian Agencies) Limitedh BP (Malta) Limited (in liquidation)h BP (Shandong) Petroleum Co., Ltda BP (Shanghai) Trading Limiteda BP Absheron Limited BP Advanced Mobility Limited BP Africa Limitedh BP Akaryakit Ortakligi (70.00%)e BP Alaska LNG LLCa BP Alternative Energy Holdings Limited BP Alternative Energy Investments 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 Angola (Block 18) B.V. BP Argentina Exploration Company BP Argentina Holdings LLCa BP Aromatics Holdings Limited BP Aromatics Limited BP Asia Limited BP Asia Pacific (Malaysia) Sdn. Bhd. BP Asia Pacific Holdings Limited BP Asia Pacific Pte Ltdh BP Australia Capital Markets Limited BP Australia Employee Share Plan Proprietary Limited BP Australia Group Pty Ltdd BP Australia Investments Pty Ltd BP Australia Nominees Proprietary Limited BP Australia Pty Ltd BP Australia Shipping Pty Ltdj BP Australia Swaps Management Limited BP Aviation A/S BP Benevolent Fund Trustees Limitedh BP Berau Ltd. BP Biocombustíveis S.A. (91.10%) BP Bioenergia Campina Verde Ltda. (91.10%) BP Bioenergia Ituiutaba Ltda. (81.26%) BP Bioenergia Itumbiara S.A. (73.95%) BP Bioenergia Tropical S.A. (94.04%) 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. (81.18%) Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 1999 Bryan St., STE 900, Dallas TX 75201, 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 1-2201, Sijian Meilin Mansion, No. 48-15 Wuyingshan Middle Road, Tianqiao District, Ji'nan, Shandong, China No. 28 Maji Road, Donghua Financial Building, China (Shanghai) Pilot Free Trade, Shanghai, China Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Degirmen yolu cad. No:28, Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 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 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 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 d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Unit 807, Tower B, Manulife Financial Centre, 223 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur, Malaysia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore Level 17, 717 Bourke Street, Docklands VIC, 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 Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Avenida das Nações Unidas, 12399, 4fl, Sao 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, 12399, 4fl, Sao Paulo, Brazil The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 253 14. Related undertakings of the group – continued BP Bomberai Ltd. BP Brasil Ltda. BP Brazil Tracking L.L.C.a BP Bulwer Island Pty Ltdk 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 Car Fleet Limitedh BP Caribbean Company BP Castrol KK (64.84%) BP Castrol Lubricants (Malaysia) Sdn. Bhd. (63.03%) BP Chembel N.V. BP Chemicals (Korea) Limited BP Chemicals East China Investments Limited BP Chemicals Investments Limited BP Chemicals Limited BP Chemicals Trading Limited (In Liquidation) BP China Exploration and Production Company BP China Limited (In Liquidation)h BP Comercializadora de Energia Ltda. BP Commodities Trading Limited BP Commodity Supply B.V. 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. BP D230 Limited BP Danmark A/S BP D-B Pipeline Company LLCe BP Developments Australia Pty. Ltd. BP Diagnostic Acoustic Sensing Limited BP Dogal Gaz Ticaret Anonim Sirketi BP East Kalimantan CBM Limited BP Eastern Mediterranean Limited 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 Energy Solutions B.V. BP Espana, S.A. Unipersonalk BP Estaciones y Servicios Energéticos, Sociedad Anónima de Capital Variableb BP Europa SEl BP Exploracion de Venezuela S.A. BP Exploration & Production Inc.c BP Exploration (Absheron) Limited BP Exploration (Alaska) Inc. BP Exploration (Algeria) Limited BP Exploration (Alpha) Limited BP Exploration (Angola) Limited BP Exploration (Azerbaijan) Limited 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 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 d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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 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 Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur, Malaysia Amocolaan 2 2440 Geel , Belgium 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 Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 55 Baker Street, London, W1U 7EU, United Kingdom Avenida das Nações Unidas, 12399, 4fl, Sao Paulo, Brazil Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands 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 Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Arne Jacobsens Allé 7, 5th Floor, 2300, Copenhagen, Denmark Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 8, 250 St Georges Terrace, Perth WA 6000, Australia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Degirmen yolu cad. No:28, Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico 7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Avenida de Barajas 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain Avenida Santa Fe 505, Piso 10, Distrito Federal, Mexico C.P. 0534, Mexico Überseeallee 1, 20457, Hamburg, Hamburg, Germany Av. Francisco de Miranda, Edif Cavendes, Los Palos Grandes, Chacao, Caracas Miranda, 1060, Venezuela Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 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 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 254 BP Annual Report and Form 20-F 2018 14. Related undertakings of the group – continued 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 (In Liquidation) BP Exploration (Greenland) Limited BP Exploration (Madagascar) 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 BP Exploration (South Atlantic) Limited BP Exploration (STP) Limited BP Exploration (Vietnam) Limited (In Liquidation) 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 Limitedm 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 Limitedk 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 Ghana Limited BP Global Investments Limitedh BP Global Investments Salalah & Co LLC BP Global West Africa Limited BP GOM Logistics LLCa BP Greece Limited BP Guangdong Limited (90.00%)a BP High Density Polyethylene - France BP Holdings (Thailand) Limited (81.01%)n BP Holdings B.V. BP Holdings Canada Limitedh BP Holdings International B.V. BP Holdings North America Limitedh BP Hong Kong Limited BP India Limited BP India Services Private Limited BP Indonesia Investment Limited BP International Limitedh 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. 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 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 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 7 Straits View #26-01, Marina One East Tower, Singapore, 018936, 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 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 Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, 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 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 Heritage Place, 7th Floor, Left Wing, 21 Lugard Avenue, Ikoyi, Lagos, Nigeria Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Rm 2710Guangfa Bank Plaza, No. 83 Nonglin Xia Road, Yuexiu District, Guangzhou, China Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe, Cergy Pontoise, France 39/77-78 Moo 2 Rama II Road, Tambon Bangkrachao, Amphur Muang, Samutsakorn 74000, Thailand d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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 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 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 Verona 12, Cornaredo, 20010, Milan, Italy Roppongi Hills Mori Tower, 10-1 Roppongi 6-chome, Minato-ku, Tokyo106-6115, Japan The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 255 14. Related undertakings of the group – continued BP Kapuas II Limited (in liquidation) BP Korea Limited BP Kuwait Limited BP Latin America LLCa BP Latin America Upstream Services Inc. BP LNG Shipping Limited 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 Mariner Holding Company LLCa BP Maritime Services (Isle of Man) Limited BP Maritime Services (Singapore) Pte. Limited BP Marketing Egypt LLC BP Mauritania Investments Limited BP Mauritius Limited (In Liquidation) BP Middle East Enterprises Corporation BP Middle East Limitedh BP Middle East LLC BP Midstream Partners GP LLCa BP Midstream Partners Holdings LLCa BP Midstream Partners LP (54.37%)o BP Mocambique Limitada BP Mocambique Limited BP Muturi Holdings B.V. BP Nederland Holdings BV BP Netherlands Upstream B.V. BP New Ventures Middle East Limited BP New Zealand Holdings Limited BP New Zealand Share Scheme Limited BP Nutrition Inc. BP Offshore Gathering Systems Inc. BP Offshore Pipelines Company LLCa BP Offshore Response Company LLCa BP Oil (Thailand) Limited (90.32%)p 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 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 Limitedh BP Pensions (Overseas) Limitedi BP Pensions Limitedh 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 55 Baker Street, London, W1U 7EU, 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 Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Clarendon House, 2 Church Street, P.O. Box HM 1022, Hamilton, HM DX, Bermuda East Tower 20F, Gate CIty Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Aire de Capellen, L-8309 Capellen, Luxembourg Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur, Malaysia d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Samuel Harris House, 5-11 St Georges Street, Douglas, Isle of Man, IM1 1AJ, Isle of Man 7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore Plot 28, North 90 Road, Housing & Construction Bank Building, New Cairo, Cairo, 11835, Egypt Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 5th Floor, Ebene Esplanade, 24 Cybercity, Ebene, Mauritius Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom P.O.Box 1699, Dubai, 1699, United Arab Emirates Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Society and Geography Avenue, Plot No. 269 , Third floor, Maputo, Mozambique Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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 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 39/77-78 Moo 2 Rama II Road, Tambon Bangkrachao, Amphur Muang, Samutsakorn 74000, Thailand Level 17, 717 Bourke Street, Docklands VIC, Australia Polígono Industrial "El Serrallo", s/n 12100 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 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, 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 OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 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 The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 256 BP Annual Report and Form 20-F 2018 14. Related undertakings of the group – continued 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 Limitedh BP Raffinaderij Rotterdam B.V. BP Refinery (Kwinana) Proprietary Limited BP Regional Australasia Holdings Pty Ltd BP River Rouge Pipeline Company LLCe BP Russian Investments Limited BP Russian Ventures Limited BP SC Holdings LLCa BP Scale Up Factory Limited BP Senegal Investments Limited BP Services International Limited BP Servicios de Combustibles S.A. de C.V. BP Servicios territoriales, S.A. de C.V. BP Shafag-Asiman Limited BP Shipping Limited BP Singapore Pte. Limited BP Solar Energy North America LLCa BP Solar Espana, S.A. Unipersonalb BP Solar International Inc. BP Solar Pty Ltd BP South America Holdings Ltd BP South East Asia Limited (In Liquidation)h 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 (In Liquidation) BP Technology Ventures Inc. BP Technology Ventures Limited BP Trading Limited (In Liquidation) 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 Limitedh BP Two Pipeline Company LLCe 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 (91.90%)a BP+Amoco International Limitedh BPA Investment Holding Company BP-AIOC Exploration (TISA) LLC (65.88%)a BPNE International B.V. BPRY Caribbean Ventures LLC (70.00%)a BPX Energy Inc. Brian Jasper Nominees Pty Ltd Britannic Energy Trading Limited Britannic Investments Iraq Limited (90.00%) Britannic Marketing Limited Britannic Strategies Limited Britannic Trading Limited British Pipeline Agency Limited (50.00%)g q Britoil Limited BTC Pipeline Holding Company Limited Burmah Castrol Australia Pty Ltdr 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 Level 17, 717 Bourke Street, Docklands VIC, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore 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 55 Baker Street, London, W1U 7EU, 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 55 Baker Street, London, W1U 7EU, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 55 Baker Street, London, W1U 7EU, 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 Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 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 153 Neftchilar Avenue, Baku, AZ1010, Azerbaijan d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 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 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 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 The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 257 14. Related undertakings of the group – continued Burmah Castrol Holdings Inc. Burmah Castrol PLCh Burmah Castrol South Africa (Pty) Limiteds Burmah Chile SpA BXL Plastics Limitedt Cadman DBP Limited Cape Vincent Wind Power, LLCa Casitas Pipeline Company Castrol (China) Limited Castrol (Ireland) Limited Castrol (Shanghai) Management Co., Ltda Castrol (Shenzhen) Company Limiteda Castrol (Tianjin) Lubricants Co., Ltda 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 Digital Holdings Limited Castrol Egypt Lubricants S.A.E. (51.00%) Castrol Hungária Trading Co. LLC "u.d." (Castrol Hungária Kereskedelmi Kft. "v.a.")a Castrol India Limited (51.00%) Castrol Industrie und Service GmbH Castrol KK (64.84%) Castrol Limited Castrol Lubricants RO S.R.L Castrol Mexico, S.A. de C.V.b Castrol Namibia (Pty) Limited Castrol Offshore Limited Castrol Pakistan (Private) Limited Castrol Philippines, Inc. Castrol Servicos Ltda. Castrol Slovensko, s.r.o. (v likvidácii) (in liquidation)a Castrol Ukraine LLCa Castrol Zimbabwe (Private) Limited Centrel Pty Ltd Charge Your Car Limitedb Chargemaster (Europe) GmbH Chargemaster Limited Charging Solutions Limited CH-Twenty, Inc. Clarisse Holdings Pty Ltd Coastwise Trading Company, Inc. Consolidada de Energia y Lubricantes, (CENERLUB) C.A. Conti Cross Keys Inn, Inc. Corner Card, S.L. Coro Trading NZ Limited Cuyama Pipeline Company 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 Partnershipe Dome Beaufort Petroleum Limited 1979 Partnership No. 1e Dome Wallis (1980) Limited Partnership (92.50%)e Dradnats, Inc. ECM Markets SA (Pty) Ltd (75.00%) Elektromotive Limited 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 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 2 Grand Canal Square, Dublin 2, Dublin, Ireland Floor 20, Shanghai Youyou International Plaza, No.76 Pujian Road, Pudong, Shanghai, China No.1120 Mawan Road, Nanshan District, China Tianjin Economic Development Area, 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 d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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 KR 7 NO. 74 09, Bogota D.C., Colombia Av. Camino Real, 111 Torre B Oficina, 603 San Isidro, Lima, Peru Technology Centre, Whitchurch Hill, Pangbourne, Reading, RG8 7QR, United Kingdom Plot 28, North 90 Road, Housing & Construction Bank Building, New Cairo, Cairo, 11835, Egypt 32-34 Soroksári út, Budapest, 1095, Hungary Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400 093, India 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 5th Floor, 92-96 Izvor St, 5th District, Bucharest, Romania Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, 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, Karachi, Pakistan 32/F LKG Tower, Ayala Avenue, Makati City, 6801, Philippines Avenida Tamboré, 448, Barueri, Sao Paulo, Brazil Rožnavská 24, 821 04 Bratislava 2, Slovakia 2a Konstiantynivskay Street, Kyiv, 04071, Ukraine Barking Road, Willowvale, Harare, Zimbabwe Level 17, 717 Bourke Street, Docklands VIC, Australia 500 Capability Green, Luton, LU1 3LS, United Kingdom Bischof-von-Henle-Straße 2a, Regensburg, 93051, Germany 500 Capability Green, Luton, LU1 3LS, United Kingdom 500 Capability Green, Luton, LU1 3LS, United Kingdom 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 Ronda de Poniente 3, 1ªPlanta, 28760 Tres Cantos, Madrid, Spain Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC, 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 - 4th 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 500 Capability Green, Luton, LU1 3LS, United Kingdom The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 258 BP Annual Report and Form 20-F 2018 14. Related undertakings of the group – continued Elite Customer Solutions Pty Ltd Elm Holdings Inc. Energy Global Investments (USA) Inc. Enstar LLCa Estacion De Servicio Molinar S.L. Europa Oil NZ Limited Exomet, Inc. Expandite Contract Services Limited Exploration (Luderitz Basin) Limited Exploration Service Company Limited Flat Ridge 2 Holdings LLCa Flat Ridge Wind Energy, LLCa Foseco Holding International B.V. Foseco Holding, Inc. Foseco, Inc. Fosroc Expandite Limited Fowler Ridge Holdings LLCa Fowler Ridge I Land Investments LLCa Fowler Ridge II Holdings LLCa Fowler Ridge III Wind Farm LLCa FreeBees B.V. Fuel & Retail Aviation Sweden AB Fuelplane- Sociedade Abastecedora De Aeronaves, Unipessoal, Lda FWK (2017) Limitedu FWK Holdings (2017) LTDu Gardena Holdings Inc. Gasolin GmbH GB Electrical and Building Services Limited Gelsenkirchen Raffinerie Netz GmbH GOAM 1 C.I S. A .S Grampian Aviation Fuelling Services Limited Guangdong Investments Limited Highlands Ethanol, LLCa Hosteleria Noriega S.L. Hydrogen Energy International Limited IGI Resources, Inc. Insight Analytics Solutions Holdings Limited (74.50%) Insight Analytics Solutions Limited (74.50%) Insight Analytics Solutions USA, Inc (74.50%) International Bunker Supplies Pty Ltd International Card Centre Limited Iraq Petroleum Company Limited Jupiter Insurance Limited Ken-Chas Reserve Company Kenilworth Oil Company Limitedh Kingbook Inversiones Socimi, S.A. Latin Energy Argentina S.A. Lebanese Aviation Technical Services S.A.L. Limited Liability Company BP Toplivnaya Kompaniaa Limited liability company Setra Lubricantsa Lubricants UK Limited Mardi Gras Transportation System Company LLCa Markoil, S.A. Unipersonal Masana Petroleum Solutions (Pty) Ltd (37.88%) Mayaro Initiative for Private Enterprise Development (70.00%)a Mehoopany Holdings LLCa Mes Tecnologia en Servicios y Energia, S.A. De C.V.b Minza Pty. Ltd. Mountain City Remediation, LLCa No. 1 Riverside Quay Proprietary Limited Nordic Lubricants A/S Nordic Lubricants AB Nordic Lubricants Oy, (in liquidation) North America Funding Company 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 Ronda de Poniente 3, 1ªPlanta, 28760 Tres Cantos, Madrid, Spain 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 112 SW 7th Street, Suite 3C, Topeka, Kansas, 66603, United States d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Box 8107, 10420, Stockholm, Sweden Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road , Sunbury on Thames , TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Wittener Straße 45, 44789 Bochum, Germany 500 Capability Green, Luton, LU1 3LS, United Kingdom Alexander-von-Humboldt-Straße 1, Gelsenkirchen, 45896, Germany 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 Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Ronda de Poniente 3, 1ªPlanta, 28760 Tres Cantos, Madrid, Spain Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 12550 W. Explorer Dr., Suite 100, Boise, Idaho, 83713, United States Romax Technology Centre , University of Nottingham Innovation Park, Triumph Road, Nottingham, NG7 2TU, United Kingdom Romax Technology Centre , University of Nottingham Innovation Park, Triumph Road, Nottingham, NG7 2TU, United Kingdom 2108 55th Street, Suite 105, Boulder CO 80301, 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 The Albany, South Esplanade, St Peter Port, GY1 4NF, Guernsey Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Calle Velázquez 18, 28001 Madrid, Spain Av. Cordoba 315 Piso 8, Buenos Aires, 1054, Argentina P O Box - 11 -5814c/o Coral Oil Building, 583Avenue de Gaulle, Raoucheh, Beirut, Lebanon Novinskiy blvd.8, 17th floor, office 11, 121099, Moscow, Russian Federation 2 Paveletskaya sq, Building1, 115054 Moscow, Russian Federation Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 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 5-5A Queen's Park West, Port-of-Spain, Trinidad and Tobago Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, 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 Hemvärnsgatan , 171 54, Solna, Sweden Teknobulevardi 3-5, 01530 Vantaa, Finland Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 259 14. Related undertakings of the group – continued 111 Eighth Avenue, New York, New York, 10011, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Novinskiy blvd.8, 17th floor, office 11, 121099, Moscow, Russian Federation 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 Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Ronda de Poniente 3, 1ªPlanta, 28760 Tres Cantos, Madrid, Spain Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States OMD87, Inc. Omega Oil Company OnSight Analytics Solutions India Private Ltd. (74.50%) #11, Platinum Tower, Ground Floor, Old Trunk Road, Pallavaram Chennai, India OOO BP STLa 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%) Peaks America Inc. Pearl River Delta Investments Limited Petrocorner Retail S.L.U. Petrohawk Energy Corporation Phoenix Petroleum Services, Limited Liability Company Baghdad International Airport, Al-Burhan Commercial Complex , First floor, Baghdad, Iraq Produits Métallurgie Doittau Prospect International, C.A. (In liquidation) PT BP Petrochemicals Indonesia PT Castrol Indonesia (68.30%) PT Castrol Manufacturing Indonesia PT Jasatama Petroindob Remediation Management Services Company Richfield Oil Corporation Rolling Thunder I Power Partners, LLCa Romax Insight Korea Limited (74.50%) Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France 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, Jakarta12520, Indonesia JL. Raya Merak KM 117, DS Gerem, Gerem Grogol, Cilegon, Banten, Indonesia Perkantoran Hijau Arkadia, Tower B, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta12520, Indonesia 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 504 Cheong dan ro-213-3, Young pyung dong 2170-1 Jeju Science Park Smart Building, Jeju City, Jeju-do, Korea, Republic of Ropemaker Deansgate Limited Ropemaker Properties Limited Ruhr Oel GmbH (ROG) Rusdene GSS Limitedu Saturn Insurance Inc. Setra Lubricants Kazakhstan LLP (in liquidation)e Sherbino I Holdings LLCa Sherbino Mesa I Land Investments LLCa Shine Top International Investment Limited Sociedade de Promocao Imobiliaria Quinta do Loureiro, SA Société de Gestion de Dépots d'Hydrocarbures - GDHa SOFAST Limited (62.77%)v South Texas Shale LLCa Southeast Texas Biofuels LLCa Southern Ridge Pipeline Holding Company Southern Ridge Pipeline LP LLCa Sp/f Decision3 (GreenSteam) Company (61.68%)w SRHP (99.99%)a Standard Oil Company, Inc. Taradadis Pty. Ltd. Telcom General Corporation (99.96%)c Terre de Grace Partnership (75.00%)e The Anaconda Company The BP Share Plans Trustees Limitedh The Burmah Oil Company (Pakistan Trading) Limited The Standard Oil Company TISA Education Complex LLC (65.88%)a TJKK Toledo Refinery Holding Company LLCa Union Texas International Corporation Vastar Pipeline, LLCa Viceroy Investments Limited Warrenville Development Limited Partnershipa Water Way Trading and Petroleum Services LLC (90.00%) Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Johannastraße 2-8, 45899 Gelsenkirchen-Horst, Germany 4 High Street, Alton, Hampshire, GU34 1BU, United Kingdom 400 Cornerstone Drive, Suite 240, Williston VT 05495, United States 98 Panfilov Street, office 809, Almaty, 05000, Kazakhstan 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 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 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 251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States Level 17, 717 Bourke Street, Docklands VIC, Australia 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 4400 Easton Commons Way , Suite 125, Columbus OH 43219, United States 153 Neftchilar Avenue, Baku, AZ1010, Azerbaijan Roppongi Hills Mori Tower, 10-1 Roppongi 6-chome, Minato-ku, Tokyo106-6115, Japan Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 33 North LaSalle Street, Chicago, Illinois 60602, United States Hay Al Wihda, Q904, Alley 68, H32, Korodha, Baghdad, Iraq Welchem, Inc. West Kimberley Fuels Pty Ltd Westlake Houston Development, LLCa Whiting Clean Energy, Inc. Windpark Energy Nederland B.V. Winwell Resources, L.L.C.a 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 d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands 5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States Wiriagar Overseas Ltd Jayla Place, Wickhams Cay 1, PO Box 3190, Road Town, Tortola, VG1110, British Virgin Islands The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 260 BP Annual Report and Form 20-F 2018   14. Related undertakings of the group – continued Related undertakings other than subsidiaries Berghausener Straße 96, 40764 Langenfeld, Germany Box 135, 190 46 Arlanda, Sweden 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Brucknerstraße 4, 1041 Wien, Austria Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 18010 Skypark Circle , #130 , Irvine CA 92614, United States Harvard Business Services, Inc., 16192 Coastal Hwy, Lewes, Delaware, 19958, USA Berghausener Straße 96, 40764 Langenfeld, Germany A Flygbranslehantering AB (AFAB) (25.00%) Aashman Power Limited (43.20%) ABG Autobahn-Betriebe GmbH (32.58%)a Abu Dhabi Marine Areas Limited (33.33%)g Advanced Biocatalytics Corporation (24.20%)x AEP I HoldCo LLC (24.30%) AGES International GmbH & Co. KG, Langenfeld (24.70%)e AGES Maut System GmbH & Co. KG, Langenfeld (24.70%)e 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 (51.00%) Ammenn GmbH (75.00%) ATAS Anadolu Tasfiyehanesi Anonim Sirketi (68.00%)y Degirmen yolu cad. No:28, Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey 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%) 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 Level 12, 680 George Street, Sydney NSW 2000, 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 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 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%)g 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%) Axion Comercializacion de Combustibles y Lubricantes S.A. (50.00%) Axion Energy Argentina S.A. (50.00%) Axion Energy Holding S.L. (50.00%)a 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 Building 1, 747 Lytton Road, Murarrie QLD 4172, Australia Level 3, Unit 3, 22 Albert Road, South Melbourne VIC 3205, Australia 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 Luis A de Herrera 1248, Torre II, Piso 22 (Edificio World Trade Center), Montevideo, Uruguay Carlos María Della Paolera 265, Piso 22, Ciudad Autónoma de Buenos Aires, Argentina Campus Empresarial Arbea - Edificio No 1, Carretera Fuencarral a Alcobendas, Alcobendas, Madrid, Spain Av. España 1369 esquina San Rafael, Asunción, Paraguay Avenida Luis Alberto de Herrera 1248, Oficina 1901, Montevideo, Uruguay Avenida Luis Alberto de Herrera 1248, Oficina 1901, Montevideo, Uruguay P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, 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 Saganer Straße 31, 90475 Nürnberg, Germany Saganer Straße 31, 90475 Nürnberg, Germany Sportallee 6, 22335 Hamburg, Germany Axion Energy Paraguay S.R.L. (50.00%)a Axuy Energy Holdings S.R.L. (50.00%)a Axuy Energy Investments S.R.L. (50.00%)a Azerbaijan Gas Supply Company Limited (23.06%)g Azerbaijan International Operating Company (30.37%)z 190 Elgin Avenue, George Town, Grand Cayman , KY1-9005, Cayman Islands Baplor S.A. (50.00%) Barranca Sur Minera S.A. (50.00%) Beer GmbH (50.00%) Beer GmbH & Co. Mineralol-Vertriebs-KG (50.00%)e BGFH Betankungs-Gesellschaft Frankfurt-Hahn GbR (50.00%)e Billund Refuelling I/S (50.00%) Blendcor (Pty) Limited (37.50%)α Blue Marble Holdings Limited (23.58%)β Bodmin Solar Limited (43.20%) BP AOC Pumpstation Maatschap (50.00%)e BP Dhofar LLC (49.00%) BP Esso AOC Maatschap (22.80%)e BP Esso Pipeline Maatschap (50.00%)e BP Guangzhou Development Oil Product Co., Ltd (40.00%)a BP Petro China Jiangmen Fuels Co., Ltd. (49.00%)a BP PetroChina Petroleum Co., Ltd (49.00%)a GA Centervej 1, DK-7190, Billund, Denmark 135 Honshu Road, Islandview, Durban, 4052, South Africa Desklodge - 5th Floor, 1 Temple Way, Bristol, BS2 0BY, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands P.O.Box 20302/211, 20302, Oman Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands No.13 Longxue Road, Longxue Island, Nansha District, Guangzhou, Guangdong, 511450, China Room A, building B , 5th floor, no. 22 Gangang Road, Jiangmen, China Room A17th Floor, No.22 Gangkou Road, Jiangmen, Guangdong Province, China The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 261 14. Related undertakings of the group – continued BP PETRONAS Acetyls Sdn. Bhd. (70.00%) BP Sinopec (ZheJiang) Petroleum Co., Ltd (40.00%)a BP Sinopec Marine Fuels Pte. Ltd. (50.00%) BP West Africa Supply Limited (50.00%) 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 Number 1, Rehoboth Place, Dade Street, North Labone Estates, Accra, Accra Metropolitan, Greater Accra, P. O. BOX CT3278, Ghana 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 BP YPC Acetyls Company (Nanjing) Limited (50.00%)a BP-Husky Refining LLC (50.00%)a BP-Japan Oil Development Company Limited (50.00%)g Braendstoflageret Kobenhavns Lufthavn I/S (20.83%)e Københavns, Lufthavn, 2770 Kastrup, Denmark BTC International Investment Co. (30.10%)γ Burnthouse Solar Limited (43.20%) Butamax™ Advanced Biofuels LLC (50.00%)a Caesar Oil Pipeline Company, LLC (56.00%)a Cairns Airport Refuelling Service Pty Ltd (33.33%) Cantera K-3 Limited Partnership (39.00%)e Canton Renewables, LLC (50.00%)a Castrol Cuba S.A. (50.00%) Castrol DongFeng Lubricant Co., Ltd (50.00%)a Cedar Creek II Holdings LLC (50.00%)a Cedar Creek II, LLC (50.00%)a Cefari RNG OKC, LLC (50.00%)a Cekisan Depolama Hizmetleri Limited Sirketi (35.70%) Yakuplu Ambarli Mevkii, 9 Ada2-3-6-7 Parsel, Büyükçekmece, Istanbul, Turkey Central African Petroleum Refineries (Pvt) Ltd (20.75%) CERF Shelby, LLC (50.00%)a Chicap Pipe Line Company (56.17%)a China American Petrochemical Company, Ltd. (CAPCO) (61.36%) P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 680 George Street, Sydney NSW 2000, Australia 6400 Shafer Ct., Suite 400, Rosemont IL 60018-4927, United States 30600 Telegraph Road, Suite 2345, Bingham Farms MI 48025, United States Calle 6 No 319, esq 5ta. Ave., Miramar, Playa, La Habana, Cuba 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 Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 800 S. Gay Street, Suite 2021, Knoxville TN 37929, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 6th Floor, No. 413 Section 2 Ruei Kuang Road, Neihhu, Taipei, 11493, Taiwan Block 1Tendeseka Office Park, Samora Machel Av/Renfrew Road, Harare, Zimbabwe China Aviation Oil (Singapore) Corporation Ltd (20.03%) Chittering Solar Limited (43.20%) Clean Eagle RNG, LLC (50.00%)a Cleopatra Gas Gathering Company, LLC (53.00%)a Coastal Oil Logistics Limited (25.00%) Compania de Inversiones El Condor Limitada (99.00%) Concessionaria Stalvedro SA (50.00%) CSG Convenience Service GmbH (24.80%) Danish Refuelling Service I/S (33.33%)e Danish Tankage Services I/S (50.00%)e Dinarel S.A. (20.00%) Donoma Power Limited (43.20%) DOPARK GmbH (25.00%) Dusseldorf Fuelling Services GbR (33.00%)e Dusseldorf Tank Services GbR (33.00%)e 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%) EMSEP S.A. de C.V. (50.00%) Endymion Oil Pipeline Company, LLC (65.00%)a Energy Emerging Investments, LLC (50.00%)a Entrepot petrolier de Chambery (32.00%) Entrepôt Pétrolier de Puget sur Argens - EPPA (58.25%) Erdol-Lagergesellschaft m.b.H. (23.00%)a Esma Petroleum Company "ESMA" (50.00%) Estonian Aviation Fuelling Services Etzel-Kavernenbetriebsgesellschaft mbH & Co. KG (33.00%)e Etzel-Kavernenbetriebs-Verwaltungsgesellschaft mbH (33.33%) Ffos Las Solar Developments Limited (43.20%) FFS Frankfurt Fuelling Services (GmbH & Co.) OHG (33.00%)e 8 Temasek Boulevard #31-02, Suntec City Tower 3, Singapore 038988, Singapore 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 10th Floor, The Bayleys Building, Cnr Brandon St and Lambton Quay, Wellington, 6011, New Zealand Av. Andrés Bello 2711, Piso 24, Las Condes, Santiago, Chile San Gottardo Sud, 6780, Airolo, Switzerland Wittener Straße 45, 44789 Bochum, Germany Kastrup Lufthavn, 2770 Kastrup, Denmark Kastrup Lufthavn, 2770 Kastrup, Denmark La Cumparsita 1373, piso 4°, Montevideo, Uruguay 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Westfalendamm 166, 44141 Dortmund, Germany 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, Dubai, United Arab Emirates Av. Paseo de la Reforma 505 piso 32, Colonia Cuauhtémoc, Delegación Cuauhtémoc (06500), CDMX, Mexico Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 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 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt Lennujaama tee 2, Tallinn EE0011, Estonia Bertrand-Russell-Straße 3, 22761 Hamburg, Germany Bertrand-Russell-Straße 3, 22761 Hamburg, Germany 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Sportallee 6, 22335 Hamburg, Germany The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 262 BP Annual Report and Form 20-F 2018 14. Related undertakings of the group – continued Field Services Enterprise S.A. (50.00%) Finite Carbon Corporation (50.00%) Finite Resources, Inc. (50.00%) 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%)e Flytanking AS (50.00%) Foreseer Ltd (25.00%) Formosa BP Chemicals Corporation (50.00%) Fotech Group Limited (22.40%)x 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 Free Power for Schools 13 Limited (43.20%) Free Power for Schools 14 Limited (43.20%) Free Power for Schools 15 Limited (43.20%) Free Power for Schools 17 Limited (43.20%) Free Power for Schools 19 Limited (43.20%) Free Power for Schools 4 Limited (43.20%) Free Power for Schools 5 Limited (43.20%) Free Power for Schools 6 Limited (43.20%) Free Power for Schools 7 Limited (43.20%) Freetricity Central June Limited (43.20%) Freetricity Commercial June Limited (43.20%) 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. (50.00%) Georgian Pipeline Company (30.37%)z Gezamenlijke Tankdienst Schiphol B.V. (50.00%) GISSCO S.A. (50.00%) Gnowee Power Limited (43.20%) 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 Guangdong Dapeng LNG Company Limited (30.00%)a Gulf Of Suez Petroleum Company "GUPCO" (50.00%) GVÖ Gebinde-Verwertungsgesellschaft der Mineralölwirtschaft mbH (21.00%) H7 Energy Limited (43.20%) Hamburg Tank Service (HTS) GbR (33.00%)e Hebei Dongming Yinglun Petroleum Co., Ltd. (49.00%)a Heinrich Fip GmbH & Co. KG (50.00%)e Heliex Power Limited (32.40%)x Henan Dongming Yinglun Petroleum Co., Ltd. (49.00%)a HFS Hamburg Fuelling Services GbR (25.00%)e Hiergeist Heizolhandel GmbH & Co. KG (50.00%)e Hiergeist Verwaltung GmbH (50.00%) Hokchi Energy S.A. de C.V. (50.00%) Hokchi Iberica S.L. (50.00%) Av. Leandro N. Alem 1180, piso 11, Buenos Aires, Argentina 435 Devon Park Drive, Suite 700, Wayne, Pennsylvania, 19087 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 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, 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 5th Floor, Condor House, 10 St Paul's Churchyard, London, EC4M 8AL , 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 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 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 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 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Box 2154, 438 14, LANDVETTER, Sweden Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 150 Avenue Yves Farge, 37700, Saint Pierre des Corps, 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 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Sportallee 6, 22335 Hamburg, Germany South Side, Floor 10, Insurance Industrial Park, No. 672, Chengjiao Street, Qiaoxi, Shijiazhuang, Hebei Province, China Rheinstraße 36, 49090 Osnabrück, Germany Kelvin Building , Bramah Avenue , East Kilbride, Glasgow , Scotland, G75 0RD, United Kingdom Room 124, Longhu Enterprise Service Center, Floor 1, Building No. 10, Courtyard No.1, Long Xing Jia Yuan, No. 66, Longhu Outer Ring Road, Zhengdong New District, Zhenzhou City Sportallee 6, 22335 Hamburg, Germany Grubenweg 4, 83666 Waakirchen-Marienstein, Germany 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 Howbery Solar Park Limited (43.20%) In Salah Gas Ltd (25.50%)α In Salah Gas Services Ltd (25.50%)α India Gas Solutions Private Limited (50.00%) Jamaica Aircraft Refuelling Services Limited (51.00%)g PCJ Building36 Trafalgar Road, Kingston 10, Jamaica Johnson Corner Solar I, LLC (43.20%)a Kala Power Limited (43.20%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 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 Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 263 14. Related undertakings of the group – continued Kingston Research Limited (50.00%) Klaus Köhn GmbH (50.00%) KM Phoenix Holdings LLC (25.00%)a Köhn & Plambeck GmbH & Co. KG (50.00%)e Kosmos Energy Investments Senegal Limited (49.99%)g Kurt Ammenn GmbH & Co. KG (50.00%)e LCA Aviation Fuelling Systems Limited (35.00%) LFS Langenhagen Fuelling Services GbR (50.00%)e Lightning Hybrids, LLC (31.60%)c Lightsource Asset Holdings Limited (43.20%) Lightsource Asset Management Limited (43.20%) Lightsource Australia SPV 1 Pty Limited (43.20%) Lightsource BP Renewable Energy Investments Limited (43.20%)δ Lightsource Commercial Rooftops (Buyback) Limited (43.20%) Lightsource Commercial Rooftops Limited (43.20%) Lightsource Construction Management Limited (43.20%) Lightsource Development Services Australia Pty Ltd (43.20%) Lightsource Development Services Limited (43.20%) Lightsource Egypt Holdings Limited (43.20%) Lightsource Finance 55 Limited (43.20%) Lightsource Grace 1 Limited (43.20%) Lightsource Grace 2 Limited (43.20%) Lightsource Grace 3 Limited (43.20%) Lightsource Holdings 1 Limited (43.20%) Lightsource Holdings 2 Limited (43.20%) Lightsource India Holdings (Mauritius) Limited (43.20%) Lightsource India Holdings Limited (43.20%) Lightsource India Investments (UK) Limited (43.20%) Lightsource India Limited (22.03%)g Lightsource India Maharashtra 1 Holdings Limited (43.20%) Lightsource India Maharashtra 1 Limited (43.20%) Lightsource Kingfisher Holdings Limited (43.20%) Lightsource Kingpin 1 Limited (43.20%) Lightsource Kingpin 2 Limited (43.20%) Lightsource Kingpin 3 Limited (43.20%) Lightsource Labs Holdings Limited (43.20%) Lightsource Labs Limited (41.04%) Lightsource Largescale Limited (43.20%) Lightsource Midscale Limited (43.20%) Lightsource Nala Limited (43.20%) Lightsource Operations 1 Limited (43.20%) Lightsource Operations 2 Limited (43.20%) Lightsource Operations 3 Limited (43.20%) Lightsource Operations Services Limited (43.20%) Lightsource Pumbaa Limited (43.20%) Lightsource Radiate 1 Limited (43.20%) Lightsource Radiate 2 Limited (43.20%) Lightsource Raindrop Limited (43.20%) Lightsource Renewable Development Limited (43.20%) Lightsource Renewable Energy (Australia) Pty Ltd (43.20%) Lightsource Renewable Energy (India) Limited (43.20%) Lightsource Renewable Energy (NI) Limited (43.20%) Lightsource Renewable Energy Australia Holdings Limited (43.20%) Lightsource Renewable Energy Development LLC (43.20%)a Lightsource Renewable Energy Holdings Limited (43.20%) C/O Banks Cooper Associates, 21 Marina Court, Hull, HU1 1TJ, United Kingdom An der Braker Bahn 22, 26122 Oldenburg, Germany Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States An der Braker Bahn 22, 26122 Oldenburg, Germany 6th Floor, 65 Gresham Street, London, England and Wales, EC2V 7NQ, United Kingdom Luisenstraße 5 a, 26382 Wilhelmshaven, Germany 90 Archiepiskopou str, Dromolaxia – Meneou, 7020 Larnaca , Cyprus Sportallee 6, 22335 Hamburg, Germany 160 Greentree Drive, Suite 101, Dover, County of Kent DE 19904, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom CBW' Level 19, 181 William Street, Melbourne, VIC 3000, Australia 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom CBW' Level 19, 181 William Street, Melbourne, VIC 3000, Australia 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, Jie Tai Plaza, 218 - 222 Zhong Shan Liu Road, Guangzhou, China 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Trinity House, Charleston Road, Ranelagh, Dublin 6, D06C8X4, Ireland 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom CBW' Level 19, 181 William Street, Melbourne, VIC 3000, Australia 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 264 BP Annual Report and Form 20-F 2018 14. Related undertakings of the group – continued Lightsource Renewable Energy India Assets Limited (43.20%) Lightsource Renewable Energy India Holdings Limited (43.20%) Lightsource Renewable Energy India Opco Private Limited (43.20%) Lightsource Renewable Energy India Projects Limited (43.20%) Lightsource Renewable Energy Ireland Limited (43.20%) Lightsource Renewable Energy Limited (43.20%) Lightsource Renewable Energy Nederland Holdings B.V. (43.20%) Lightsource Renewable Energy Netherlands Holdings Limited (43.20%) Lightsource Renewable Energy North America LLC (43.20%)a Lightsource Renewable Energy North America Management LLC (43.20%)a Lightsource Renewable Energy North America Operations LLC (43.20%)a Lightsource Renewable Services Limited (43.20%) Lightsource Residential NI Limited (43.20%) Lightsource Residential Rooftops (Buyback) Limited (43.20%) Lightsource Residential Rooftops (PPA) Limited (43.20%) Lightsource Residential Rooftops Limited (43.20%) Lightsource Simba Limited (43.20%) Lightsource Singapore Renewables Holdings Private Limited (43.20%) Lightsource Singapore Renewables Private Limited (43.20%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom No.44/38, 1st Floor, Veerabhadran Street, Valluvarkottam, Nungambakkam, Chennai, 600034, India 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Trinity House, Charleston Road, Ranelagh, Dublin 6, D06C8X4, Ireland 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Prins Bernhardplein 200, 1097JB, Amsterdam, Netherlands 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 8 Marina Boulevard, #05-02 Marina Bay Financial Centre, Singapore 8 Marina Boulevard, #05-02 Marina Bay Financial Centre, Singapore Lightsource SPV 10 Limited (43.20%) Lightsource SPV 100 Limited (43.20%) Lightsource SPV 101 Limited (43.20%) Lightsource SPV 104 Limited (43.20%) Lightsource SPV 105 Limited (43.20%) Lightsource SPV 106 Limited (43.20%) Lightsource SPV 108 Limited (43.20%) Lightsource SPV 109 Limited (43.20%) Lightsource SPV 112 Limited (43.20%) Lightsource SPV 114 Limited (43.20%) Lightsource SPV 115 Limited (43.20%) Lightsource SPV 116 Limited (43.20%) Lightsource SPV 118 Limited (43.20%) Lightsource SPV 123 Limited (43.20%) Lightsource SPV 126 Limited (43.20%) Lightsource SPV 127 Limited (43.20%) Lightsource SPV 128 Limited (43.20%) Lightsource SPV 130 Limited (43.20%) Lightsource SPV 133 Limited (43.20%) Lightsource SPV 135 Limited (43.20%) Lightsource SPV 137 Limited (43.20%) Lightsource SPV 138 Limited (43.20%) Lightsource SPV 140 Limited (43.20%) Lightsource SPV 142 Limited (43.20%) Lightsource SPV 143 Limited (43.20%) Lightsource SPV 145 Limited (43.20%) Lightsource SPV 147 Limited (43.20%) Lightsource SPV 149 Limited (43.20%) Lightsource SPV 151 Limited (43.20%) Lightsource SPV 152 Limited (43.20%) Lightsource SPV 154 Limited (43.20%) Lightsource SPV 155 Limited (43.20%) Lightsource SPV 156 Limited (43.20%) Lightsource SPV 160 Limited (43.20%) Lightsource SPV 162 Limited (43.20%) Lightsource SPV 166 Limited (43.20%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 265 14. Related undertakings of the group – continued Lightsource SPV 167 Limited (43.20%) Lightsource SPV 169 Limited (43.20%) Lightsource SPV 170 Limited (43.20%) Lightsource SPV 171 Limited (43.20%) Lightsource SPV 174 Limited (43.20%) Lightsource SPV 175 Limited (43.20%) Lightsource SPV 176 Limited (43.20%) Lightsource SPV 179 Limited (43.20%) Lightsource SPV 18 Limited (43.20%) Lightsource SPV 180 Limited (43.20%) Lightsource SPV 182 Limited (43.20%) Lightsource SPV 183 Limited (43.20%) Lightsource SPV 184 Limited (43.20%) Lightsource SPV 185 Limited (43.20%) Lightsource SPV 187 Limited (43.20%) Lightsource SPV 189 Limited (43.20%) Lightsource SPV 19 Limited (43.20%) Lightsource SPV 191 Limited (43.20%) Lightsource SPV 192 Limited (43.20%) Lightsource SPV 196 Limited (43.20%) Lightsource SPV 199 Limited (43.20%) Lightsource SPV 20 Limited (43.20%) Lightsource SPV 200 Limited (43.20%) Lightsource SPV 201 Limited (43.20%) Lightsource SPV 202 Limited (43.20%) Lightsource SPV 203 Limited (43.20%) Lightsource SPV 204 Limited (43.20%) Lightsource SPV 205 Limited (43.20%) Lightsource SPV 206 Limited (43.20%) Lightsource SPV 212 Limited (43.20%) Lightsource SPV 213 Limited (43.20%) Lightsource SPV 214 Limited (43.20%) Lightsource SPV 215 Limited (43.20%) Lightsource SPV 216 Limited (43.20%) Lightsource SPV 217 Limited (43.20%) Lightsource SPV 218 Limited (43.20%) Lightsource SPV 219 Limited (43.20%) Lightsource SPV 220 Limited (43.20%) Lightsource SPV 221 Limited (43.20%) Lightsource SPV 222 Limited (43.20%) Lightsource SPV 223 Limited (43.20%) Lightsource SPV 224 Limited (43.20%) Lightsource SPV 225 Limited (43.20%) Lightsource SPV 226 Limited (43.20%) Lightsource SPV 227 Limited (43.20%) Lightsource SPV 228 Limited (43.20%) Lightsource SPV 229 Limited (43.20%) Lightsource SPV 230 Limited (43.20%) Lightsource SPV 232 Limited (43.20%) Lightsource SPV 233 Limited (43.20%) Lightsource SPV 234 Limited (43.20%) Lightsource SPV 235 Limited (43.20%) Lightsource SPV 236 Limited (43.20%) Lightsource SPV 237 Limited (43.20%) Lightsource SPV 238 Limited (43.20%) Lightsource SPV 239 Limited (43.20%) Lightsource SPV 240 Limited (43.20%) Lightsource SPV 241 Limited (43.20%) Lightsource SPV 242 Limited (43.20%) Lightsource SPV 243 Limited (43.20%) Lightsource SPV 244 Limited (43.20%) Lightsource SPV 245 Limited (43.20%) Lightsource SPV 246 Limited (43.20%) Lightsource SPV 247 Limited (43.20%) Lightsource SPV 248 Limited (43.20%) Lightsource SPV 249 Limited (43.20%) Lightsource SPV 25 Limited (43.20%) Lightsource SPV 250 Limited (43.20%) 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 266 BP Annual Report and Form 20-F 2018 14. Related undertakings of the group – continued Lightsource SPV 251 Limited (43.20%) Lightsource SPV 252 Limited (43.20%) Lightsource SPV 253 Limited (43.20%) Lightsource SPV 254 Limited (43.20%) Lightsource SPV 255 Limited (43.20%) Lightsource SPV 256 Limited (43.20%) Lightsource SPV 257 Limited (43.20%) Lightsource SPV 258 Limited (43.20%) Lightsource SPV 259 Limited (43.20%) Lightsource SPV 26 Limited (43.20%) Lightsource SPV 260 Limited (43.20%) Lightsource SPV 261 Limited (43.20%) Lightsource SPV 262 Limited (43.20%) Lightsource SPV 263 Limited (43.20%) Lightsource SPV 264 Limited (43.20%) Lightsource SPV 265 Limited (43.20%) Lightsource SPV 266 (NI) Limited (43.20%) Lightsource SPV 267 (NI) Limited (43.20%) Lightsource SPV 268 (NI) Limited (43.20%) Lightsource SPV 269 (NI) Limited (43.20%) Lightsource SPV 270 (NI) Limited (43.20%) Lightsource SPV 271 (NI) Limited (43.20%) Lightsource SPV 272 (NI) Limited (43.20%) Lightsource SPV 273 (NI) Limited (43.20%) Lightsource SPV 274 (NI) Limited (43.20%) Lightsource SPV 275 (NI) Limited (43.20%) Lightsource SPV 276 (NI) Limited (43.20%) Lightsource SPV 277 (NI) Limited (43.20%) Lightsource SPV 278 (NI) Limited (43.20%) Lightsource SPV 279 (NI) Limited (43.20%) Lightsource SPV 280 (NI) Limited (43.20%) Lightsource SPV 281 (NI) Limited (43.20%) Lightsource SPV 282 (NI) Limited (43.20%) Lightsource SPV 283 (NI) Limited (43.20%) Lightsource SPV 284 (NI) Limited (43.20%) Lightsource SPV 285 (NI) Limited (43.20%) Lightsource SPV 286 Limited (43.20%) Lightsource SPV 29 Limited (43.20%) Lightsource SPV 32 Limited (43.20%) Lightsource SPV 35 Limited (43.20%) Lightsource SPV 39 Limited (43.20%) Lightsource SPV 40 Limited (43.20%) Lightsource SPV 41 Limited (43.20%) Lightsource SPV 42 Limited (43.20%) Lightsource SPV 44 Limited (43.20%) Lightsource SPV 47 Limited (43.20%) Lightsource SPV 49 Limited (43.20%) Lightsource SPV 5 Limited (43.20%) Lightsource SPV 50 Limited (43.20%) Lightsource SPV 54 Limited (43.20%) Lightsource SPV 56 Limited (43.20%) Lightsource SPV 60 Limited (43.20%) Lightsource SPV 69 Limited (43.20%) Lightsource SPV 73 Limited (43.20%) Lightsource SPV 74 Limited (43.20%) Lightsource SPV 75 Limited (43.20%) Lightsource SPV 76 Limited (43.20%) Lightsource SPV 78 Limited (43.20%) Lightsource SPV 79 Limited (43.20%) Lightsource SPV 8 Limited (43.20%) Lightsource SPV 88 Limited (43.20%) Lightsource SPV 91 Limited (43.20%) Lightsource SPV 92 Limited (43.20%) Lightsource SPV 98 Limited (43.20%) Lightsource Timon Limited (43.20%) Lightsource Trading Limited (43.20%) Lightsource Trojan 1 Limited (43.20%) Lightsource Trojan 2 Limited (43.20%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 267 14. Related undertakings of the group – continued Lightsource Viking 1 Limited (43.20%) Lightsource Viking 2 Limited (43.20%) Limited Liability Company TYNGD (20.00%)a LL Property Services 2 Limited (43.20%) LL Property Services Limited (43.20%) LLC "Kharampurneftegaz" (49.00%)a Lora Solar Limited (43.20%) Lotos - Air BP Polska Spółka z ograniczoną odpowiedzialnością (50.00%) LOTTE BP Chemical Co., Ltd (50.94%) LREHL Renewables India SPV 1 Private Limited (32.79%) Maasvlakte Europoort Pipeline Maatschap (50.00%)e Maatschap Europoort Terminal (50.00%)e Mach Monument Aviation Fuelling Co. Ltd. (70.00%) Malmo Fuelling Services AB (33.33%) Manchester Airport Storage and Hydrant Company Limited (25.00%) Manor Farm (Solar Power) Limited (43.20%) Manpetrol S.A. (50.00%) Maputo International Airport Fuelling Services (MIAFS) Limitada (50.00%)a Mars Oil Pipeline Company LLC (28.50%)e Masana Employee Share Trust No. 1 (37.88%)a Mavrix, LLC (50.00%)a McFall Fuel Limited (49.00%) Mediteranean Gas Co. "MEDGAS" (25.00%) Mehoopany Wind Energy LLC (50.00%)a Mehoopany Wind Holdings LLC (50.00%)a Meri Power Limited (43.20%) Middle East Lubricants Company LLC (40.00%) Milne Point Pipeline, LLC (50.00%)a Mobene Beteiligungs GmbH & Co. KG (50.00%)a Mobene GmbH & Co. KG (50.00%)e Mobene Verwaltungs-GmbH (50.00%) MTS Francis Court Solar Limited (43.20%) MTS Trefinnick Solar Limited (43.20%) N.V. Rotterdam-Rijn-Pijpleiding Maatschappij (RRP) (44.40%) Natural Gas Vehicles Company "NGVC" (40.00%) New Zealand Oil Services Limited (50.00%) Newshelf 1310 (RF) Proprietary Limited (37.88%) Nextpower Trevemper Limited (43.20%) NFX Combustíveis Marítimos Ltda. (50.00%) Nima Power Limited (43.20%) Nord-West Oelleitung GmbH (59.33%) North Ghara Petroleum Company (NOGHCO) (30.00%) North October Petroleum Company "NOPCO" (50.00%) Ocwen Energy Pty Ltd (49.50%) Oleoductos Canarios, S.A. (20.00%) Olympic Pipe Line Company LLC (70.00%)a Oslo Lufthaven Tankanlegg AS (33.33%) PAE E & P Bolivia Limited (50.00%) PAE Oil & Gas Bolivia Ltda. (50.00%) Palk Power Limited (43.20%) Pan American Energy Chile Limitada (50.00%) Pan American Energy do Brasil Ltda. (50.00%)a Pan American Energy Group, S.L. (50.00%)α Pan American Energy Holdings S.A. (50.00%) Pan American Energy Iberica S.L. (50.00%) Pan American Energy Investments Ltd. (50.00%) Pan American Energy Uruguay S.A. (50.00%) Pan American Energy US LLC (51.00%)a Pan American Energy, S.L. (50.00%)a 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Pervomayskaya street, 32A, 678144, Lensk, Sakha (Yakutiya) Republic, Russian Federation 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 629830, Gubkinskiy town, Yamalo-Nenets Autonomous Okrug, Russian Federation 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Grunwaldzka 472B, 80-309, Gdansk, Poland 2-2 Sangnam-ri, Chungryang-myun, Ulju-gun, Ulsan 689-863, Republic of Korea 815-816 International Trade Tower, Nehru Place, New Delhi, New Delhi, 110019, India Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands Moezelweg 101, 3198LS 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 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Francisco Behr 20, Barrio Pueyrredon, Comodoro Rivadavia, Provincia del Chubut, Argentina Praca Dos Trabalhadores, Nr 09, Distrito Urbano 1, Maputo, Mozambique Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Block B, 2nd Floor, BP House, 10 Junction Avenue, Parktown, 2193, South Africa Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 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 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 6th Flr City Tower, 2 - Sheikh Zayed Road, PO Box 1699, Dubai, United Arab Emirates 900 E. Benson Boulevard, Anchorage, Alaska, 99508, United States Spaldingstraße 64, 20097 Hamburg, Germany Spaldingstraße 64, 20097 Hamburg, Germany Spaldingstraße 64, 20097 Hamburg, Germany 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Butaanweg 215, NL-3196 KC Vondelingenplaat, Rotterdam, 3045, Havennummer , Netherlands 85 El Nasr Road, Cairo, Cairo, Egypt Level 3, 139 The Terrace, Wellington, 6011, New Zealand Block B, 2nd Floor, BP House, 10 Junction Avenue, Parktown, 2193, South Africa 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Avenida Atlântica, no. 1.130, 2nd floor (part), Copacabana, Rio de Janeiro, RJ, 22021-000, Brazil 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Zum Ölhafen 207, 26384 Wilhelmshaven, Germany 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt 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 Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Postboks 134, Gardermoen, NO-2061, Norway Trinity Place Annex, Corner of Frederick & Shirley Streets, P.O. Box N-4805, Nassau, Bahamas Cuarto anillo, Avda. Ovidio Barbery N° 4200,Equipetrol Norte, Santa Cruz de la Sierra, Bolivia 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 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 Campus Empresarial Arbea - Edificio No 1, Carretera Fuencarral a Alcobendas, Alcobendas, Madrid, Spain Colonia 810, Oficina 403, Montevideo, Uruguay 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 Colonia 810, Oficina 403, Montevideo, Uruguay Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Campus Empresarial Arbea - Edificio No 1, Carretera Fuencarral a Alcobendas, Alcobendas, Madrid, Spain The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 268 BP Annual Report and Form 20-F 2018 14. Related undertakings of the group – continued Pan American Fueguina S.A. (50.00%) Pan American Sur S.A. (50.00%) Peninsular Aviation Services Company Limited (25.00%)h Pentland Aviation Fuelling Services Limited (50.00%)b Petrostock SA (50.00%) Pharaonic Petroleum Company "PhPC" (25.00%) Pont Andrew Limited (43.20%) Prince William Sound Oil Spill Response Corporation (25.00%) Proteus Oil Pipeline Company, LLC (65.00%)a PT Petro Storindo Energi (30.00%) PT. Aneka Petroindo Raya (49.90%) PT. Dirgantara Petroindo Raya (49.90%) PTE Pipeline LLC (32.00%)a Raffinerie de Strasbourg (in liquidation) (33.33%) Rahamat Petroleum Company (PETRORAHAMAT) (50.00%) RAPI SA (62.51%) Raststaette Glarnerland AG, Niederurnen (20.00%) RD Petroleum Limited (49.00%) Resolution Partners LLP (68.00%)e Rhein-Main-Rohrleitungstransportgesellschaft mbH (35.00%) Rio Grande Pipeline Company (30.00%)e RMF Holdings Limited (49.00%) Romanian Fuelling Services S.R.L. (50.00%) Rosneft Oil Company (19.75%) Routex B.V. (25.00%) Rudeis Oil Company "RUDOCO" (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%) SeaPort Midstream Partners, LLC (49.00%)a Servicios Logísticos de Combustibles de Aviación, S.L (50.00%) Shakti Power Limited (43.20%) Shandong Dongming Yinglun Petroleum Co., Ltd. (49.00%)a Sharjah Aviation Services Co. LLC (49.00%)α Sharjah Pipeline Company LLC (49.00%) Shell and BP South African Petroleum Refineries (Pty) Ltd (37.50%)g Shell Mex and B.P. Limited (40.00%)α Shenzhen Cheng Yuan Aviation Oil Company Limited (25.00%)a Shenzhen Dapeng LNG Marketing Company Limited (30.00%)a 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%) Solar Photovoltaic (SPV2) Limited (43.20%) Solar Photovoltaic (SPV3) Limited (43.20%) South Caucasus Pipeline Company Limited (28.83%)α 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%)a Stansted Intoplane Company Limited (20.00%) O´Higgins N° 194, Rio Grande, Argentina O´Higgins N° 194, Rio Grande, Argentina P O Box 6369, Jeddah 21442, Saudi Arabia 6th Floor (c/o Q8 Aviation), Dukes Court, Duke Street, Woking, GU21 5BH, United Kingdom route de Pré-Bois 2, 1214, Vernier, Switzerland 70/72 Road 200, Maadi, Cairo, Egypt 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 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 AKR Tower 25th floor, Jalan Panjang No.5, Kebon Jeruk, Jakarta, 11530, Indonesia Wisma AKR, 25th floor, Jalan Panjang No.5, Kebon Jeruk, , Jakarta Barat, 11530, Indonesia 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 24 Cours Michelet, 92800, Puteaux, France 70/72 Road 200, Maadi, Cairo, Egypt 26 Kifissias Ave. and 2 Paradissou st., 15125 Maroussi, Athens, Greece Nideracher 1, 8867, Niederurnen, Switzerland Albert Alloo & Sons, 67 Princes Street, Dunedin, New Zealand 1675 Broadway, Denver CO 80202, United States Godorfer Hauptstraße 186, 50997 Köln, Germany Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States KPMG, 247 Cameron Road, Tauranga, 3110, New Zealand 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 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, 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 Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States Vía de los Poblados1, Madrid, Spain 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Room 01, 08, 09, 10, Floor 11, Block B, , No. 8, Luoyuan Avenue, Lixia District, Jinan City, China P O Box- 97, Sharjah, United Arab Emirates Sharjah 42244, Sharjah, UAE, Sharjah, United Arab Emirates 1 Refinery Road, Prospecton, 4110, South Africa Shell Centre, London, SE1 7NA, United Kingdom Fu Yong Town, Bao An county, ShenZhen Airport, Guangdong Province, China Room 316 Excellence Mansion, No.98 Fuhua 1Rd, Futian District, Shenzhen, China 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 27 Route du Bassin Numéro 6, 92230, Gennevilliers, France 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 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 Causeway House, 1 Dane Street, Bishop's Stortford, Hertfordshire, CM23 3BT, United Kingdom The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 269 14. Related undertakings of the group – continued STDG Strassentransport Dispositions Gesellschaft mbH (50.00%) Holstenhofweg 47, 22043 Hamburg, Germany Sportallee 6, 22335 Hamburg, Germany 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands Shell Centre, London, SE1 7NA, United Kingdom Carretera de San Andréss/n, La Jurada-María Jiménez, Santa Cruz de Tenerife, Spain Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands Sportallee 6, 22335 Hamburg, Germany 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Sportallee 6, 22335 Hamburg, Germany Box 7, 190 45 Arlanda, Sweden Stockholm Fuelling Services Aktiebolag (25.00%) Palm Grove House, P.O. Box 438, Road Town, Tortola, British Virgin Islands Stonewall Resources Ltd. (50.00%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Sula Power Limited (43.20%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Sun and Soil Renewable 12 Limited (43.20%) Sunrise Oil Sands Partnership (50.00%)e c/o Husky Oil Operations Limited, 707 - 8th Avenue SW, Calgary AB T2P 1H5, Canada Birmenstorferstrasse 2, 5507, Mellingen, Switzerland Tankanlage AG Mellingen (33.33%) Zwüscheteich, 8153, Rümlang, Switzerland TAR - Tankanlage Ruemlang AG (27.32%) Auhafenstrasse 10a, 4132, Muttenz, Switzerland TAU Tanklager Auhafen AG (50.00%) Avenida Paulista, 287, 1st floor, room 10, São Paulo, São Paulo, 01311000, Brazil TCE Participações S.A. (50.00%) Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands Team Terminal B.V. (22.80%) Tecklenburg GmbH (50.00%) Wesermünder Straße 1, 27729 Hambergen, Germany Tecklenburg GmbH & Co. Energiebedarf KG (50.00%)e Wesermünder Straße 1, 27729 Hambergen, Germany Terminales Canarios, S.L. (50.00%) Texaco Esso AOC Maatschap (TEAM) (22.80%)e TFSS Turbo Fuel Services Sachsen GbR (20.00%)e TGC Solar 106 Limited (43.20%) TGC Solar 91 Limited (43.20%) TGFH Tanklager-Gesellschaft Frankfurt-Hahn GbR (50.00%)e TGH Tankdienst-Gesellschaft Hamburg GbR (33.33%)e Sportallee 6, 22335 Hamburg, Germany Sportallee 6, 22335 Hamburg, Germany TGHL Tanklager-Gesellschaft Hannover-Langenhagen GbR (50.00%)e TGK Tanklagergesellschaft Koln-Bonn (25.00%)e Thames Electricity Limited (43.20%) The Baku-Tbilisi-Ceyhan Pipeline Company (30.10%)γ The Consolidated Petroleum Company Limited (50.00%)α The Consolidated Petroleum Supply Company Limited (50.00%)ε The Sullom Voe Association Limited (33.33%)α TLK Holding Company LLC (37.04%)a TLK Intermediate Holding Company LLC (37.04%)a TLK Operating Company LLC (37.04%)a TLM Tanklager Management GmbH (49.00%)a TLS Tanklager Stuttgart GmbH (45.00%) Tonatiuh Trading 1 Limited (43.20%) Torsina Oil Company "TORSINA" (37.50%) TRaBP GbR (75.00%)e Trafineo GmbH & Co. KG (75.00%)e Trafineo Service GmbH (75.00%) Trafineo Verwaltungs-GmbH (75.00%) Trans Adriatic Pipeline AG (24.57%) TransTank GmbH (50.00%) Tricoya Ventures UK Limited (35.56%) TRTM Inc. (37.04%) Tuwale Power Limited (43.20%) TWQE2 Limited (43.20%) 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%) Walton-Gatwick Pipeline Company Limited (42.33%) West London Pipeline and Storage Limited (30.50%) West Morgan Petroleum Company (PETROMORGAN) (50.00%) Town Hall, Lerwick, Shetland, ZE1 0HB, 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 Am Tankhafen 4, 4020 Linz, Austria Zum Ölhafen 49, 70327 Stuttgart, Germany 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 4 Palestine Road, 4th District, New Maadi, Cairo, Egypt Huestraße 25, 44787, Bochum, Germany Wittener Straße 56, Bochum, Germany Wittener Straße 45, 44789 Bochum, Germany Wittener Straße 56, Bochum, Germany Lindenstrasse 2, 6340 Baar, Switzerland Am Stadthafen 60, 45881 Gelsenkirchen, Germany Brettenham House, 19 Lancaster Place, London, WC2E 7EN, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 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 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 Shell Centre, London, SE1 7NA, United Kingdom Wick Farm Grid Limited (21.60%) Wiri Oil Services Limited (27.78%) Yangtze River Acetyls Co., Ltd (51.00%)a Yermak Neftegaz LLC (49.00%)a Your Power No. 1 Limited (43.20%) Your Power No. 10 Limited (43.20%) Your Power No. 19 Limited (43.20%) Your Power No. 2 Limited (43.20%) Your Power No. 3 Limited (43.20%) Your Power No. 8 Limited (43.20%) Woodwater House, Pynes Hill, Exeter, England, EX2 5WR 303 Parnell Rd, Parnell, Auckland, New Zealand 97 Weijiang Road (in the Petrochemical Park), Changshou District, Chongqing, China Kosmodamianskaya nab, 52/3, 115035, Moscow, Russian Federation 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 270 BP Annual Report and Form 20-F 2018 14. Related undertakings of the group – continued Your Power No12 Limited (43.20%) 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Zubie, Inc. (20.30%) 160 Greentree Drive, Suite 101, Dover, County of Kent DE 19904, United States a  Member interest b A and B shares c  Common stock and preference shares d Ordinary shares and preference shares e Partnership interest f  A, B and D shares g  A shares h  Interest held directly by BP p.l.c. i 99% held directly by BP p.l.c. j 1% held directly by BP p.l.c. k Ordinary, A and B shares l  0.008% held directly by BP p.l.c. m Ordinary shares and cumulative redeemable preference shares n  79.93% ordinary shares and 99.06% preference shares o Members interest, (49.99%) subordinated units and (4.37%) common units traded on the New York stock exchange 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  Ordinary and A shares t  Ordinary and deferred shares u Subsidiary undertaking pursuant to sections 1162(2), 1162(3)(b) and Paragraph 6 of Schedule 7 of the Companies Act 2006 v  100% ordinary shares and 58.63% preference shares w 92.31% B shares and 78.43% D shares x  Preference shares y 15% held directly by BP p.l.c z Unlimited redeemable shares α B shares β 96.52% C shares γ 1.89% A shares and 40.80% B shares δ 43.2% A shares, 43.2% C shares, 43.2% D shares, 43.2% E shares, 43.2% F shares and 43.2% G shares ε 5% held directly by BP p.l.c The parent company financial statements of BP p.l.c. on pages 238-271 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 2018 271 THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY 272 BP Annual Report and Form 20-F 2018 Additional disclosures 274 Selected financial information 277 Liquidity and capital resources 279 Upstream analysis by region 284 Downstream plant capacity 285 Oil and gas disclosures for the group 291 Environmental expenditure 291 Regulation of the group’s business 296 Legal proceedings 298 International trade sanctions 300 Material contracts 300 Property, plant and equipment 300 Related-party transactions 300 Corporate governance practices 300 Code of ethics 300 Controls and procedures 301 Principal accountant’s fees and services 301 Directors’ report information 302 Disclosures required under Listing Rule 9.8.4R 303 Cautionary statement BP Annual Report and Form 20-F 2017 BP Annual Report and Form 20-F 2018 247 273 A d d i t i o n a l l i d s c o s u r e s Selected financial information This information has been extracted or derived from the audited consolidated financial statements of the BP group. Note 1 to the financial statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related notes. The audited consolidated financial statements and related notes as of 31 December 2018 and 2017 and for the three years ended 31 December 2018 are presented on page 114. Income statement data Sales and other operating revenues Profit (loss) before interest and taxation Finance costs and net finance expense relating to pensions and other post-retirement benefits Taxation Non-controlling interests Profit (loss) for the yeara Inventory holding (gains) losses«, before tax Taxation charge (credit) on inventory holding gains and losses RC profit (loss)«for the year Net (favourable) adverse impact of non-operating items« and fair value accounting effects«, before taxb Taxation charge (credit) on non-operating items and fair value accounting effects Underlying RC profit«for the year Earnings per sharec – cents Profit (loss) for the yeara per ordinary share Basic Diluted RC profit (loss) for the year per ordinary share« Underlying RC profit for the year per ordinary share« Dividends paid per share – cents – pence Capital expenditure«d Organic capital expenditure« Inorganic capital expenditure« 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 datae Basic weighted average number of shares Diluted weighted average number of shares 2018 2017 2016 2015 2014 $ million except per share amounts 298,756 19,378 240,208 9,474 183,008 (430) 222,894 (7,918) 353,568 6,412 (2,655) (7,145) (195) 9,383 801 (198) 9,986 (2,294) (3,712) (79) 3,389 (853) 225 2,761 (1,865) 2,467 (57) 115 (1,597) 483 (999) (1,653) 3,171 (82) (6,482) 1,889 (569) (5,162) (1,462) (947) (223) 3,780 6,210 (1,917) 8,073 3,380 3,730 6,746 15,067 8,234 (643) 12,723 (325) 6,166 (3,162) 2,585 (4,000) 5,905 (4,171) 12,136 46.98 46.67 50.00 63.70 40.50 30.568 15,140 9,948 25,088 282,176 101,548 5,402 99,444 56,426 30.3% 17.20 17.10 14.02 31.31 40.00 30.979 16,501 1,339 17,840 276,515 100,404 5,343 98,491 55,491 27.4% 0.61 0.60 (5.33) 13.79 40.00 29.418 16,675 777 17,452 263,316 96,843 5,284 95,286 51,666 26.8% (35.39) (35.39) (28.18) 32.22 40.00 26.383 N/A N/A 20,202 20.55 20.42 43.90 66.00 39.00 23.850 N/A N/A 23,192 261,832 98,387 5,049 97,216 46,224 21.6% 284,305 112,642 5,023 111,441 45,977 16.7% Share million 19,970 20,102 19,693 19,816 18,745 18,855 18,324 18,324 18,385 18,497 a Profit attributable to BP shareholders. b See pages 276 and 320 for further analysis of these items. c A reconciliation to GAAP information is provided on page 320. d From 2017 onwards BP reports organic, inorganic and total capital expenditure on a cash basis which were previously reported on an accruals basis. This aligns with BP's financial framework and is consistent with other financial metrics used when comparing sources and uses of cash. An analysis of capital expenditure on a cash basis for 2015 and 2014 is not available. e The number of ordinary shares shown has been used to calculate the per share amounts. 274 «See Glossary BP Annual Report and Form 20-F 2018 Additional information Capital expenditure Capital expenditure Organic capital expenditure Inorganic capital expenditurea Organic capital expenditure by segment Upstream US Non-US Downstream US Non-US Other businesses and corporate US Non-US Organic capital expenditure by geographical area US Non-US 2018 2017 15,140 9,948 25,088 16,501 1,339 17,840 2018 2017 3,482 8,545 12,027 877 1,904 2,781 54 278 332 15,140 4,413 10,727 15,140 2,999 10,764 13,763 809 1,590 2,399 64 275 339 16,501 3,872 12,629 16,501 $ million 2016 16,675 777 17,452 $ million 2016 3,415 10,929 14,344 774 1,328 2,102 32 197 229 16,675 4,221 12,454 16,675 a On 31 October 2018, BP acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation, a wholly owned subsidiary of BHP that holds a portfolio of unconventional onshore US oil and gas assets. As at 31 December 2018, $6,788 million of the consideration had been paid. 2018 includes $1,739 million relating to the purchase of an additional 16.5% interest in the Clair field west of Shetland in the North Sea, as part of the agreements with ConocoPhillips in which ConocoPhillips simultaneously purchased BP's entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska. 2018 also includes amounts relating to the 25-year extension to our ACG production-sharing agreement« in Azerbaijan. 2017 includes amounts paid to acquire interests in Mauritania and Senegal and in the Zohr gas field in Egypt. BP Annual Report and Form 20-F 2018 «See Glossary 275 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 b Environmental and other provisions Restructuring, integration and rationalization costsc Fair value gain (loss) on embedded derivatives Otherb d Downstream Impairment and gain (loss) on sale of businesses and fixed assetsa e Environmental and other provisions Restructuring, integration and rationalization costsc Fair value gain (loss) on embedded derivatives Other Rosneft Impairment and gain (loss) on sale of businesses and fixed assets Environmental and other provisions Restructuring, integration and rationalization costs Fair value gain (loss) on embedded derivatives Other Other businesses and corporate Impairment and gain (loss) on sale of businesses and fixed assetsa Environmental and other provisionsf Restructuring, integration and rationalization costsc Fair value gain (loss) on embedded derivatives Gulf of Mexico oil spill responseg Other Total before interest and taxation Finance costsg Total before taxation Taxation credit (charge) on non-operating itemsh Taxation - impact of US tax reformi Total after taxation 2018 2017 (90) (35) (131) 17 56 (183) (54) (83) (405) — (174) (716) (95) — — — — (95) (260) (640) (190) — (714) (159) (1,963) (2,957) (479) (3,436) 510 121 (2,805) (563) 1 (24) 33 (118) (671) 579 (19) (171) — — 389 — — — — — — (22) (156) (72) — (2,687) 90 (2,847) (3,129) (493) (3,622) 1,172 (859) (3,309) $ million 2016 2,391 (8) (373) 32 (289) 1,753 405 (73) (300) — (56) (24) 62 — — — (39) 23 — (134) (90) — (6,640) (55) (6,919) (5,167) (494) (5,661) 2,833 — (2,828) a See Financial statements – Note 4 for further information. b 2018 includes an impairment reversal for assets in the North Sea and Angola. 2017 includes an impairment charge relating to BPX Energy (previously known as the US Lower 48 business), partially offset by gains associated with asset divestments. In addition, 2017 includes an impairment charge arising following the announcement of the agreement to sell the Forties Pipeline System business to INEOS. 2016 includes a $319-million exploration write-back relating to Block KG D6 in India. In addition, an impairment reversal of $234 million was also recorded in relation to this block. c Restructuring charges are classified as non-operating items where they relate to an announced major group restructuring. A major group restructuring is a restructuring programme affecting more than one of the group’s operating segments that is expected to result in charges of more than $1 billion over a defined period. Following the Gulf of Mexico oil spill in 2010 and since the fall in oil prices in late 2014, major group restructuring programmes were initiated.The group's restructuring programme, originally announced in 2014, has now been completed. d 2018 and 2017 include exploration write-offs of $124 million and $145 million respectively in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. 2017 also includes BP’s share of an impairment reversal recognized by the Angola LNG equity-accounted entity, partially offset by other items. 2016 includes the write-off of $334 million in relation to the value ascribed to the licence in Brazil as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. e 2017 primarily reflects the disposal of our shareholding in the SECCO joint venture. f 2018 primarily reflects charges due to the annual update of environmental provisions, including asbestos-related provisions for past operations, together with updates of non-Gulf of Mexico oil spill related legal provisions. g See Financial statements – Note 2 for further details regarding costs relating to the Gulf of Mexico oil spill. h 2017 includes the tax effect of the increase in the provision in the fourth quarter for business economic loss and other claims associated with the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) at the new US tax rate. i In 2017 the US tax reform reduced the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018. The impact disclosed has been calculated as the change in deferred tax balances at 31 December 2017, excluding the increase in the provision in the fourth quarter for business economic loss and other claims associated with the DHCSSP, which arises following the reduction in the tax rate. 2018 reflects a further impact following a clarification of the tax reform. The impact of the US tax reform has been treated as a non-operating item because it is not considered to be part of underlying business operations, has a material impact upon the reported result and is substantially impacted by Gulf of Mexico oil spill charges, which are also treated as non-operating items. Separate disclosure is considered meaningful and relevant to investors. 276 «See Glossary BP Annual Report and Form 20-F 2018 Liquidity and capital resources Financial framework BP’s financial framework sets a number of parameters in support of growing shareholder value, distributions and returns, while maintaining a strong balance sheet. BP’s objective over time is to grow sustainable free cash flow« through a combination of operating cash flow« growth and capital discipline, in service of growing shareholder distributions over the long term. We maintain our progressive dividend policy and the commitment to the share buyback programme and expect the impact of the scrip dilution since the third quarter of 2017 to be fully offset by the end of 2019. The shape of the buyback programme will reflect ongoing consideration of factors including changes in the environment, the underlying performance of the business, the outlook for the group financial framework, and other market factors which may vary quarter to quarter. We expect operating cash flow excluding amounts relating to the Gulf of Mexico oil spill to continue to cover organic capital expenditure« of $15-17 billion and the full dividend« (including scrip) at around $50 per barrel. Looking further out, this balancing point is expected to steadily reduce to $35-40 per barrel by 2021, with organic capital expenditure in a range of $15-17 billion per year. In a constant price environment, surplus organic free cash flow« is expected to grow and be used to ensure the right balance between deleveraging the balance sheet, growing distributions and disciplined investment, depending on the context and outlook at the time. Gulf of Mexico oil spill payments were just over $3 billion in 2018, are expected to step down to around $2 billion in 2019 and around $1 billion per annum thereafter. Over the next two years we plan to complete more than $10 billion of divestments and we expect divestment proceeds« subsequently to revert to the historical norm of around $2-3 billion per annum. We continue to target a gearing« band on a pre-IFRS 16 basis of 20-30%, while maintaining strong liquidity and debt market access. Payments for the acquisition of BHP’s onshore US assets using available cash moved gearing to 30.3% at the end of 2018. Gearing is expected to move towards the middle of the band in 2020 in line with the generation of free cash flow and receipt of disposal proceeds. In 2018, the return on average capital employed« was 11.2%a at an average of $71 per barrel. At $55 per barrel real, return on average capital employed is targeted to improve to over 10% by 2021, as we continue to grow our underlying business. a Nearest equivalent GAAP measures: Numerator – Profit attributable to BP shareholders $9.4 billion; Denominator – Average capital employed $165.5 billion. 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 10.25 cents per share from the third quarter of 2018 (2017 10 cents per share). The total dividend distributed to BP shareholders in 2018 was $8.1 billion (2017 $7.9 billion). Shareholders have the option to receive a scrip dividend in place of receiving cash. In 2018 the total dividend paid in cash was $6.7 billion (2017 $6.2 billion). Details of share repurchases to satisfy the requirements of certain employee share-based payment plans are set out on page 312. The share buyback programme to offset the dilutive impact of the scrip dividend purchased 50 million ordinary shares in 2018 at a cost of $355 million, including fees and stamp duty. Financing the group’s activities The group’s principal commodities, oil and gas, are priced internationally in US dollars. Group policy has generally been to minimize economic exposure to currency movements by financing operations with US dollar debt. Where debt 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. Cash balances of the group are mainly held in US dollars or swapped to US dollars and holdings are well diversified to reduce concentration risk. The group is not, therefore, exposed to significant currency risk regarding its cash or borrowings. Also see Risk factors on page 55 for further information on risks associated with prices and markets and Financial statements – Note 29. The group’s gross debt at 31 December 2018 amounted to $65.8 billion (2017 $63.2 billion). Of the total gross debt, $9.4 billion is classified as short term at the end of 2018 (2017 $7.7 billion). See Financial statements – Note 26 for more information on the short- term balance. Net debt« was $44.1 billion at the end of 2018, an increase of $6.3 billion from the 2017 year-end position of $37.8 billion. The ratio of gross debt to gross debt plus equity at 31 December 2018 was 39.3% (2017 38.6%). The ratio of net debt to net debt plus equity« was 30.3% at the end of 2018 (2017 27.4%). See Financial statements – Note 27 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 $22.5 billion at 31 December 2018 (2017 $25.6 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 $7.6 billion (see Financial statements – Note 29 for more information). We believe that the group has sufficient working capital for foreseeable requirements, taking into account the amounts of undrawn borrowing facilities and levels of cash and cash equivalents, and its ongoing ability to generate cash. BP utilizes various arrangements in order to manage its working capital including discounting of receivables and, in the supply and trading business, the active management of supplier payment terms, inventory and collateral. Standard & Poor’s Ratings’ long-term credit rating for BP is A- (stable outlook) and the Moody’s Investors Service rating is A1 (stable outlook). The group’s sources of funding, its access to capital markets and maintaining a strong cash position are described in Financial statements – Note 25 and Note 29. On 14 December 2018, BP completed the exchange of $10.5 billion of notes previously issued by BP Capital Markets p.l.c for new notes issued by BP Capital Markets America Inc. in order to optimize the BP group’s capital structure and align revenue generation to indebtedness. Further information on the management of liquidity risk and credit risk, and the maturity profile and fixed/floating rate characteristics of the group’s debt are also provided in Financial statements – Note 26 and Note 29. Off-balance sheet arrangements At 31 December 2018, the group’s share of third-party finance debt of equity-accounted entities was $16.1 billion (2017 $18.0 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 2018 were $696 million (2017 $656 million) in respect of liabilities of joint ventures«and associates«and $432 million (2017 $382 million) in respect of liabilities of other third parties. Of these amounts, $684 million (2017 $645 million) of the joint ventures and associates guarantees relate to borrowings and for other third-party guarantees, $423 million (2017 $350 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 28. 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 303 and Risk factors on page 55, 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. BP Annual Report and Form 20-F 2018 «See Glossary 277 Contractual obligations The following table summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2018 and the proportion of that expenditure for which contracts have been placed. Capital expenditure Committed of which is contracted Total 26,378 8,319 2019 12,749 5,646 2020 5,689 1,742 2021 3,456 528 2022 1,653 157 2023 1,001 53 2024 and thereafter 1,830 193 $ 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 2018, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to $1,411 million. Contracts were in place for $1,170 million of this total. The following table summarizes the group’s principal contractual obligations at 31 December 2018, distinguishing between those for which a liability is recognized on the balance sheet and those for which no liability is recognized. Further information on borrowings is given in Financial statements – Note 26 and more information on operating leases is given in Financial statements – Note 28. $ million Payments due by period Expected payments by period under contractual obligations Total 2019 2020 2021 2022 2023 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 Total 74,587 1,350 23,807 1,663 18,360 19,114 138,881 11,979 144,660 156,639 295,520 11,607 98 290 300 2,302 1,237 15,834 2,511 69,676 72,187 88,021 8,646 97 169 303 1,569 1,211 11,995 1,875 16,422 18,297 30,292 8,410 95 107 219 1,343 1,149 11,323 1,446 11,479 12,925 24,248 9,385 94 339 173 1,267 1,084 12,342 1,124 8,326 9,450 21,792 2024 and thereafter 28,429 880 22,806 532 10,660 13,366 76,673 8,110 86 96 136 1,219 1,067 10,714 914 4,109 6,715 7,629 18,343 32,042 36,151 112,824 a Expected payments include interest totalling $10,646 million ($2,350 million in 2019, $1,904 million in 2020, $1,653 million in 2021, $1,379 million in 2022, $1,101 million in 2023 and $2,259 million thereafter). b Expected payments include interest totalling $683 million ($54 million in 2019, $51 million in 2020, $47 million in 2021, $43 million in 2022, $37 million in 2023 and $451 million thereafter). c The amounts presented are undiscounted. d The amounts presented are undiscounted. Gulf of Mexico oil spill liabilities are included in the group balance sheet, on a discounted basis, within other payables. See Financial statements – Note 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 2019 include purchase commitments existing at 31 December 2018 entered into principally to meet the group’s short-term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts is discussed in Financial statements – Note 29. The following table summarizes the nature of the group’s unconditional purchase obligations. Unconditional purchase obligations Crude oil and oil products Natural gas Chemicals and other refinery feedstocks Power Utilities Transportation Use of facilities and services Total Total 62,801 27,642 6,715 5,573 1,037 21,682 19,210 144,660 2019 43,265 14,916 4,857 3,296 163 1,740 1,439 69,676 2020 6,395 4,922 923 1,087 138 1,480 1,477 16,422 2021 4,679 2,880 298 494 80 1,580 1,468 11,479 2022 2,769 2,325 291 158 64 1,412 1,307 8,326 $ million Payments due by period 2023 2,356 1,555 118 113 64 1,412 1,097 6,715 2024 and thereafter 3,337 1,044 228 425 528 14,058 12,422 32,042 278 «See Glossary BP Annual Report and Form 20-F 2018 Upstream analysis by region Our upstream operations are set out below by geographical area, with associated significant events for 2018. BP’s percentage working interest in oil and gas assets is shown in brackets. Working interest is the cost-bearing ownership share of an oil or gas lease. Consequently, the percentages disclosed for certain agreements do not necessarily reflect the percentage interests in proved reserves and production. In addition to exploration, development and production activities, our upstream business also includes midstream and liquefied natural gas (LNG) supply activities. Midstream activities involve the ownership and management of crude oil and natural gas pipelines, processing facilities and export terminals, LNG processing facilities and transportation, and our natural gas liquids (NGLs) processing business. Our LNG supply activities are located in Abu Dhabi, Angola, Australia, Indonesia and Trinidad. We market around 3.5 million tonnes per annum of our LNG production to IST, which uses contractual rights to access import terminal capacity in the liquid markets of Italy (Rovigo), the Netherlands (Gate), Spain (Bilbao), the UK (the Isle of Grain) and the US (Cove Point), with the remainder marketed directly to customers. LNG is supplied to customers in markets including Argentina, China, the Dominican Republic, India, Japan, Kuwait, South Korea, Taiwan and Thailand. Europe BP is active in the North Sea and the Norwegian Sea. In 2018 BP’s production came from three key areas: the Shetland area comprising the Clair, Foinaven, Magnus and Schiehallion fields; the central area comprising the Andrew area, Bruce, ETAP, Keith, Kinnoull and Rhum fields; and Norway, through our equity accounted 30% interest in Aker BP. • In July we announced that we had entered into an agreement with ConocoPhillips to increase our holding in the Clair field (prior to the increase BP 29% and operator) by 16.5%, while selling our non- operated interest in the Greater Kuparuk Area on the North Slope of Alaska as well as our holding in the Kuparuk Transportation Company. Clair is the largest oilfield on the UK Continental Shelf. The transaction completed in December. • In September we received approval from the Oil and Gas Authority (OGA) to proceed with the Vorlich development (BP 66% and operator). Located 240 kilometres east of Aberdeen, in the central North Sea, Vorlich will consist of two wells tied back to the existing Ithaca Energy-operated FPF-1 floating production facility. The development is part of a programme of North Sea subsea tie-back developments that seek to access new production from fields located near to established producing infrastructure. The field is expected to come onstream in 2020. • In October EnQuest notified BP that it would exercise its option to acquire the remaining 75% of BP’s stake in the Magnus field and associated infrastructure. The disposal completed at the end of November. EnQuest acquired the initial 25% of BP’s interest in the Magnus field and associated infrastructure in December 2017. • Also in October we received approval from OGA to proceed with the Alligin development (BP 50% and operator). Located 140 kilometres west of Shetland, Alligin is part of the Greater Schiehallion area. We announced our intention to develop it in April. The development will consist of two wells tied back to the existing Schiehallion and Loyal subsea infrastructure, and is expected to come onstream in 2020. • Development progressed at the Total-operated Culzean field (BP 32%) during the year. The field will be developed with three fixed platforms and a floating storage unit. At the end of 2018, construction activities were complete and the hook-up and commissioning activities were underway, with first production expected in 2019. • In November 2017 we announced that we had agreed to sell a package of our interests in the North Sea comprising the Bruce (BP 37%), Keith (BP 35%) and Rhum (BP 50%) fields, three bridge- linked platforms and associated subsea infrastructure to Serica Energy plc. We operated the assets through the year until the sale and transfer of ownership completed at the end of November 2018. • In November as part of the sale of Rhum to Serica Energy plc the US Office of Foreign Assets Control issued a joint licence to BP and Serica permitting certain US persons and US owned and controlled companies to support Rhum activities in compliance with US primary sanctions and a letter of comfort permitting all non-US persons to support Rhum activities in compliance with US secondary sanctions. The Rhum field is now owned by Serica (50%) and the Iranian Oil Company (U.K.) Limited (IOC, 50%) under a joint operating agreement. The shares in IOC are now held in trust. See International Trade Sanctions on page 298. • In November we announced the start-up of production at Clair Ridge – the second phase of development at the Clair field. Two new, bridge-linked platforms and oil and gas export pipelines have been constructed as part of the project. The new facilities, which required capital investment in excess of $6 billion, are designed for around 40 years of production. North America Our upstream activities in North America are located in five areas: deepwater Gulf of Mexico, the Lower 48 states, Alaska, Canada and Mexico. BP has around 240 lease blocks in the deepwater Gulf of Mexico and operates four production hubs. • In October we announced the start-up of the Northwest Expansion project at our Thunder Horse platform, under budget and ahead of schedule. The project, which achieved first oil just 16 months after being sanctioned, adds a new subsea manifold and two wells tied into existing flowlines two miles to the north of the platform. The new project is expected to boost production at Thunder Horse and is the third major field expansion there in recent years. • We participated in lease sales 250 and 251 during the year, and were awarded 44 leases in total. • In December BP received approval from the Bureau of Safety Environmental Enforcement of the assignment of Chevron’s interest in the Tiber and Guadalupe leases. BP now has a 100% working interest in these leases. • Exploration write-offs totalling $447 million were recognized in 2018, driven primarily by lease relinquishment ($131 million of this was recognized as a non-operating item). • In February 2019 we announced the start-up of the Constellation project (BP 66.67%), operated by Anadarko. • See also Financial statements – Note 1 for further information on exploration leases. The US Lower 48 onshore new combined business, following acquisition of BHP's unconventional assets (see below), has significant operated and non-operated activities across Colorado, Louisiana, New Mexico, Oklahoma, Texas and Wyoming producing natural gas, oil, NGLs and condensate. It had a 2.4 billion boe proved reserve base as at 31 December 2018, predominantly in unconventional reservoirs (tight gas«, shale gas and coalbed methane, and newly acquired shale oil). This resource spans 3.5 million net developed acres and has approximately 12,000 operated gross wells, with daily net production around 500mboe/d. Since the beginning of 2015, our US Lower 48 onshore business has operated as a separate business while remaining part of our Upstream segment. With its own governance, systems and processes, it was established to increase competitive performance through swift decision making and innovation, while maintaining BP’s commitment to safe, reliable and compliant operations. In October 2018 we announced that we had changed the name of our Lower 48 business to BPX Energy. • In October we completed the acquisition of BHP’s US unconventional assets in a landmark deal that will significantly upgrade our US onshore oil and gas portfolio and help drive long- term growth. The acquisition, which was announced in July, adds oil and gas production of 190mboe/d in the liquids-rich regions of BP Annual Report and Form 20-F 2018 «See Glossary 279 the Permian and Eagle Ford basins in Texas and in the Haynesville natural gas basin in East Texas and Louisiana.   offshore exploration licences in Nova Scotia, Newfoundland and Labrador and the Canadian Beaufort Sea. • As part of the BHP acquisition announcement, BPX Energy expects to divest some existing assets to shift the organization’s core focus towards the newly-acquired BHP assets. The divestment includes core positions in San Juan, Wamsutter, Anadarko, Arkoma, legacy East Texas and Southwest Oklahoma basins, as well as diversified non-operated royalty and working interests across the US Lower 48. 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 the year. For the past four years BP has slowed decline at Prudhoe Bay through wellwork and improved operating field efficiencies, with production being largely maintained. Infrastructure renewal activities in 2018 included compressor replacements, fire and gas system upgrades, safety system upgrades, pipeline renewal, and facility piping upgrade projects. BP owns significant interests in three producing fields operated by others, as well as a non-operating interest in the Liberty development project and owned significant interests in an additional five producing fields operated by others prior to the sale of our interest in the Greater Kuparuk Area (see below). • In July we announced the sale of our non-operated 39.2% interest in the Greater Kuparuk Area on the North Slope comprising five fields, as well as our holding in the Kuparuk Transportation Company to ConocoPhillips. The transaction received all regulatory approvals and closed in December, with a retroactive effective date of 1 July 2018. • In May 2018 BP signed a Gas Sales Precedent Agreement with the Alaska Gas Development Corporation detailing key terms for potential future gas sales to the State. In addition, in September an amendment to the Point Thomson development plan was agreed with the State to better align field milestones to those of the Alaska LNG project. 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 southcentral Alaska. In April 2012 Unocal (1.37%) gave notice to the other TAPS owners of their intention to withdraw as an owner of TAPS. The remaining owners and Unocal have not yet reached agreement regarding the terms for the transfer of Unocal’s interest in TAPS. • In 2017 the parties involved in TAPS tariff matters at the Federal Energy Regulatory Commission (FERC) and the Regulatory Commission of Alaska (RCA) reached an agreement to settle all pending legal challenges involving TAPS interstate rates at FERC for the years 2009-15 and establish a mechanism for calculating interstate rate ceilings for TAPS for the period from 2016 through 2021, as well as subsequent years unless otherwise terminated. The agreement resolved all challenges involving TAPS intrastate rates from 2008 to 2019 and established intrastate rate ceilings for the future through to 30 June 2019. RCA approval was granted in January and FERC approval in February and all associated settlement amounts and tariff refunds were paid. • In September BP Alaska removed one of its four Alaska grade crude oil tankers from service (the vessel Frontier). Historically, BP Alaska has utilized four tankers to carry crude oil shipments from Alaska. With the reduction in volume over time, as well as new efficiencies identified in the shipping programme, Frontier has been removed from service and its carrying value impaired accordingly. In Canada BP is focused on oil sands development as well as pursuing offshore exploration opportunities. We utilize in-situ steam- assisted gravity drainage (SAGD) technology in our oil sands developments, 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 lease areas through the Sunrise Oil Sands and Terre de Grace partnerships and the Pike Oil Sands joint operation«. In addition, we have significant • The government of Canada continued with its plans to introduce legislation to allow it to suspend any oil and gas activities in the Beaufort Sea. In Mexico, we have interests in two exploration joint operations« in the Salina Basin with Equinor and Total, Block 1 (BP 33% and operator) and Block 3 (BP 33%), and in one exploration joint operation in the Sureste Basin with Total and Hokchi, a subsidiary of Pan American Energy Group (PAEG), Block 34 (BP 42.5% and operator). Both Salina Basin operations received exploration plan approval in March from Comisión Nacional de Hidrocarburos (CNH), the Mexican regulator. Seismic interpretation and well pre-spud activities are taking place in 2018 and 2019 with the tentative plan to commence drilling in the first half of 2020. The Sureste Basin operation submitted an exploration plan for approval to CNH at the end of December. South America BP has upstream activities in Brazil and Trinidad & Tobago and through PAEG, in Argentina and Bolivia. In Brazil BP has interests in 25 exploration concessions across five basins. • In the North Campos basin, BP was nominated as operator following Anadarko's withdrawal from both the BM-C-30 and BM- C-32 blocks. Regulatory consent is being sought for both Anadarko's exit and the operatorship transfer. The consortium decided not to perform the previously planned extended well test during the year. Instead it elected to finalize the appraisal plans and request a postponement of up to five years to decide whether the projects are commercially feasible. During this period, the consortium will assess alternative development concepts. Approval of this request by the Brazilian National Petroleum Agency (ANP) is still pending. • BP continues to progress the preparatory activities for drilling exploration wells in the Foz do Amazonas Basin, with a BP- operated well scheduled to start drilling in 2021. An extension request to August 2020 was approved by the ANP regarding the BP-operated Block FZA-M-59. BP is monitoring developments on its other non-operated interests in the Foz de Amazonas basin (BP 30%) to establish an expected drilling activity schedule. • In the South Campos basin, BP's request for a contract suspension in Block BM-C-35 is under review by the ANP. • BP won Blocks C-M-755 and C-M-793 at the 15th bid round in March in a consortium with Equinor (BP 60%). • In June BP won the licence for the Dois Irmãos block located in the Campos basin, offshore Brazil, as a result of the fourth Pre-Salt Production Sharing Contract Bid Round (Petrobras operator 45%, BP 30%, and Equinor 25%). • BP accessed new acreage in the Santos basin, offshore Brazil in September by winning the licence for the Pau Brasil block (BP 50% and operator). This represents BP’s first operated production sharing acreage in the Santos basin. • In October drilling commenced at the Peroba block (BP 40%). Well results are expected in the first quarter of 2019. In Argentina and Bolivia BP conducts activity through PAEG, a joint venture that is owned by BP (50%) and Bridas Corporation (50%). PAEG also has activities in Mexico. In Trinidad & Tobago BP holds exploration and production licences and production-sharing agreements«(PSAs) covering 1.8 million acres offshore of the east and north-east coast. Facilities include 14 offshore platforms and two onshore processing facilities. Production comprises gas and associated liquids. BP also has a shareholding in the Atlantic LNG liquefaction plant. BP’s shareholding averages 39% across four LNG trains« with a combined capacity of 15 million tonnes per annum. We sell gas to train 1, 2 and 3 and process gas in train 4. All LNG from train 1 and most of the LNG from trains 2 and 3 is sold to third parties under 280 «See Glossary BP Annual Report and Form 20-F 2018 long-term contracts. BP’s LNG entitlement from trains 2, 3 and 4 is marketed to the US, Europe, Asia and South America. • The Atoll field in the North Damietta concession came fully onstream at the start of 2018. • In December, the Cassia compression project was sanctioned. This project involves the installation of a new compression platform (Cassia C), bridge-linked to the Cassia B processing platform and providing lowered wellhead pressures to fields served by the Cassia hub. The expected project start-up date is 2021. • Negotiations of three historical upstream commercial issues were completed with the government of the Republic of Trinidad & Tobago at the end of 2018. This resulted in a payment of $144 million representing final settlement. • The Atlantic LNG Train 1 gas supply contract is currently being negotiated for the period April 2019 to September 2024.  • Discussions are ongoing with partners in the Manakin project on the Unit Operating Agreement (UOA), Field Development Plan and subsurface arrangements following declaration of commerciality in January 2018. The UOA is expected to be agreed in 2019. Manakin, discovered in 1998, is a cross-border field with Venezuela. • In October the Bongos exploration well in the deepwater Block 14 (BP 30%) was announced as a discovery. Assessment of the well results is currently in progress. • The Angelin project, sanctioned in June 2017, involves the construction of a new platform, BP’s 15th offshore production facility, 60 kilometres off the south-east coast of Trinidad in water depths of approximately 65 metres. The development includes four wells, with gas from Angelin flowing to the Cassia B hub for processing via a new pipeline to the Serrette platform. During 2018 the jacket and topsides were installed and subsea skid and pipeline installation was also completed. The first well was completed in January 2019 and the project commenced production in February 2019. Africa BP’s upstream activities in Africa are located in Algeria, Angola, Côte d'Ivoire, Egypt, Libya, Madagascar, Mauritania, São Tomé & Príncipe and Senegal. In Algeria BP, Sonatrach and Equinor 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. • In December 2017 BP and Equinor signed an extension agreement for the In Amenas production sharing contract with Sonatrach, the Algerian state-owned energy company. The agreement was formally ratified in April 2018. In Angola, BP owns an interest in five major deepwater offshore licences and is operator in two of these, Blocks 18 and 31, that are producing. We also have an equity interest in the Angola LNG plant (BP 13.6%). • During the year a final investment decision (FID) on Block 17 was made by the operator, Total, to proceed with the Zinia 2 deep offshore development project (BP 16.67%). • In December, BP announced it had taken the FID to progress the Platina project in Block 18. The agreement also extends the production licence for the Greater Plutonio operation in Block 18 to 2032, and provides for Sonangol to take an 8% equity interest in the block, all subject to government approval. • The Block 25/11 production sharing agreement expired in January 2019. The remaining intangible asset of $42 million associated with the licence acquisition cost was written off at the start of 2018 as no further drilling activity was planned. In Côte d’Ivoire, BP has interests in five offshore oil blocks with Kosmos Energy (KE) under agreements with the government of Côte d'Ivoire and the state oil company Société Nationale d'Operations Pétrolières de la Côte d'Ivoire (PETROCI) (BP 45%, KE 45% and operator, PETROCI approximately 10%). New 3D seismic data was acquired during the year and analysis of it is ongoing. In Egypt, BP and its partners currently produce 10% of Egypt’s liquids« production and over 50% of its gas production. • In 2018 exploration write-offs of $236 million were recognized, the most significant being $169 million in connection with withdrawal from the Rahamat lease. • Following concept sanction in 2017, BP continued progressing the Baltim South West field. Two wells are planned in 2019 followed by further development wells in 2020. A new nine-slot platform will be installed and tied back to existing infrastructure (Abu Madi) through a new offshore and onshore pipeline. • In December BP announced it had acquired a 25% interest in the Nour North Sinai offshore concession area from Eni. The concession is in the East Nile Delta Basin. Eni, the operator, is currently carrying out drilling of the first exploration well and will remain the operator with a 40% stake in the concession. BP will hold a 25% interest, Mubadala Petroleum 20% and Tharwa Petroleum Company 15%. • In February 2019 BP announced the start-up of gas production from the Giza and Fayoum fields in the West Nile Delta development (BP 82.75%). This development comprises five fields across the North Alexandria and West Mediterranean deepwater offshore blocks and is being developed as three separate projects to enable BP and its partners to accelerate gas production commitments to Egypt. The first of these three projects (Taurus and Libra) started production in 2017, Giza and Fayoum is the second, and the third project (Raven) is expected to be onstream in 2019. In Libya, BP partners with the Libyan Investment Authority (LIA) in an exploration and production-sharing agreement (EPSA) to explore acreage in the onshore Ghadames and offshore Sirt basins (BP 85%). BP wrote off all balances associated with the Libya EPSA in 2015. • In October we announced that we had signed an agreement with the Libyan National Oil Corporation and Eni with a view to working together to resume exploration activities in Libya. The parties have agreed to work towards Eni acquiring a 42.5% interest in the BP- operated EPSA in Libya. On completion, Eni would also become operator of the EPSA. The companies are working to finalize and complete all agreements with a target of resuming exploration activities in 2019. In Mauritania and Senegal, BP has a 62% participating interest in the C-6, C-8, C-12 and C-13 exploration blocks in Mauritania and a 60% participating interest in the Cayar Profond and St Louis Profond exploration blocks in Senegal. Together these blocks cover approximately 33,000 square kilometres. BP also has a 15% interest in the C-18 exploration block, operated by Total. • In February KE announced that the Requin Tigre-1 well in the Saint Louis Profond Block, offshore Senegal, was fully tested but did not encounter hydrocarbons. • In December BP and partners announced that the FID for Phase 1 of the cross-border Greater Tortue Ahmeyim development had been agreed. The decision was made following agreement between the Mauritanian and Senegalese governments and partners BP, KE and National Oil Companies, Petrosen and SMHPM. The project will produce gas from an ultra-deepwater subsea system and mid-water floating production, storage and offloading (FPSO) vessel. The gas will then be transferred to a floating liquefied natural gas (FLNG) facility at a near-shore hub located on the Mauritania and Senegal maritime border. The FLNG facility is designed to provide approximately 2.5 million tonnes of LNG per annum on average. The project, the first major gas project to reach FID in the basin, is planned to provide LNG for global export as well as making gas available for domestic use in both Mauritania and Senegal. First gas for the project is expected in 2022. In Madagascar, BP signed four production-sharing contracts (PSC) in 2018 for exploration licences situated offshore northwest Madagascar, under agreements with the government of Madagascar represented by Office des Mines Nationales et des Industries Stratégiques (OMNIS) (BP 100%). BP Annual Report and Form 20-F 2018 «See Glossary 281 In São Tomé & Príncipe, BP and KE were awarded two offshore blocks in March 2018, under production-sharing agreements with the government of São Tomé & Príncipe represented by Agência Nacional do Petróleo de São Tomé e Príncipe (ANP-STP) (BP 50% (operator), KE 35% ANP-STP 15%). During the year work began on environmental baseline surveys, with completion anticipated in the second half of 2019. capacity of the pipeline during the first phase is 106mboe/d and the average throughput in 2018 was 30mboe/d. The second phase will take gas from Eskishehir to the connection with the Trans Adriatic Pipeline (TAP) in Greece. BP has a 20% interest in TAP, that will take gas through Greece and Albania into Italy. In December TAP entered into project financing arrangements with multiple lenders. BP's share of the funds received as a result of financing is $594 million. Asia BP has activities in Abu Dhabi, Azerbaijan, China, India, Iraq, Kuwait, Oman and Russia. In China we have a 30% equity stake in the Guangdong LNG regasification terminal and trunkline project with a total storage capacity of 640,000 cubic metres. The project is supplied under a long-term contract with Australia’s North West Shelf venture (BP 16.67%). • BP has two PSCs for shale gas exploration, development and production in the Neijiang-Dazu block and Rong Chang Bei block in the Sichuan basin. The two blocks, both in the exploration phase, cover a total area of approximately 2,500 square kilometres. China National Petroleum Corporation (CNPC) is the operator. In 2018, drilling activity continued to progress in the two blocks in the Sichuan basin. In Azerbaijan, BP operates two PSAs, Azeri-Chirag-Gunashli (ACG) (BP 30.37%) and Shah Deniz (BP 28.83%) and also holds a number of other exploration leases. • 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 were lifted or suspended as part of the Joint Comprehensive Plan of Action. However, in November the US secondary sanctions were reinstated. For further information see International trade sanctions on page 298. • In April we announced that we had signed a new PSA with the State Oil Company of Azerbaijan Republic (SOCAR) for the joint exploration and development of Block D230 in the North Absheron basin. The block lies 135 kilometres north-east of Baku in the Caspian Sea, covering an area of 3,200 square kilometres. Under the PSA, which is for 25 years, BP will be the operator during the exploration phase and hold a 50% interest, with SOCAR holding the remaining 50%. The signing of the PSA follows the memorandum of understanding for exploration of Block D230, which was agreed in May 2016. • In July we announced the start-up of the landmark Shah Deniz Stage 2 gas development in Azerbaijan, including its first commercial gas delivery to Turkey. The BP-operated $28 billion project is the first subsea development in the Caspian Sea and the largest subsea infrastructure operated by BP worldwide. It is also the starting point for the Southern Gas Corridor series of pipelines that will deliver natural gas from the Caspian Sea direct to European markets for the first time. BP holds a 30.1% interest in and operates the Baku-Tbilisi-Ceyhan oil pipeline. The 1,768-kilometre pipeline transports oil from the BP- operated ACG oilfield and gas condensate from the Shah Deniz gas field in the Caspian Sea, along with other third-party oil, to the eastern Mediterranean port of Ceyhan. The pipeline has a capacity of 1mmboe/d, with an average throughput in 2018 of 697mboe/d. BP is technical operator of, and currently holds a 28.83% interest in, the 693 kilometre South Caucasus Pipeline. The pipeline takes gas from Azerbaijan through Georgia to the Turkish border and has a capacity of 143mboe/d, with average throughput in 2018 of 142mboe/d. BP (as operator of Azerbaijan International Operating Company) also operates the Western Route Export Pipeline that transports ACG oil to Supsa on the Black Sea coast of Georgia, with an average throughput of 76mboe/d in 2018. BP also holds a 12% interest in the Trans Anatolian Natural Gas Pipeline. In the first phase, which commenced in June, gas from Shah Deniz is transported from Georgia to Eskishehir in Turkey. The In Oman BP operates the Khazzan field in Block 61 (BP 60%). • In April BP announced that, together with its partner the Oman Oil Company Exploration & Production (OOCEP), it had approved the development of Ghazeer, the second phase of the Khazzan gas field in Oman. The Ghazeer project is expected to increase production by 50% and will involve construction of a third gas processing train to handle this. The project is currently on track to deliver first gas as planned in 2021. • In January 2019 BP announced that together with Eni, they had signed a heads of agreement (HoA) with the Ministry of Oil and Gas of the Sultanate of Oman to work jointly towards a significant new exploration opportunity in Oman. Under the HoA, the two companies will work with the government of Oman towards the award of a new EPSA for Block 77 in central Oman. BP and Eni have entered discussions with the Ministry to finalise details of the EPSA. Block 77, with a total area of almost 3,100 square kilometres, is located in central Oman, 30 kilometres east of the BP-operated Block 61. In Abu Dhabi, BP holds a 10% interest in the ADNOC onshore concession. We also have a 10% equity shareholding in ADNOC LNG and a 10% shareholding in the shipping company NGSCO. ADNOC LNG supplied approximately 5.4 million tonnes of LNG (729bcfe regasified) in 2018. Our interest in the ADNOC onshore concession expires at the end of 2054. • In March 2019 ADNOC and ADNOC LNG agreed to extend the gas supply agreement to 2040. The new agreement will take effect from 1 April 2019, and replaces an existing agreement expiring on 31 March 2019. Our interest in the ADNOC offshore concession expired in March 2018. The concession, together with all related rights and obligations, has reverted back to the government of the Emirate of Abu Dhabi. In 2016 BP signed an enhanced technical service agreement for south and east Kuwait conventional oilfields, which includes the Burgan field, with Kuwait Oil Company. Target performance for the 2017-18 plan was delivered and implementation of the 2018-19 plan is underway. In India we have a participating interest in two oil and gas PSAs (KG D6 30% and NEC25 33.33%) both operated by Reliance Industries Limited (RIL). We also have a stake in a 50:50 joint venture (India Gas Solutions Private Limited) with RIL for the sourcing and marketing of gas in India. • In April BP and RIL sanctioned the Satellite Cluster project in Block KG D6. This is the second of three projects in the Block KG D6 integrated development. The first of the projects, development of the R-Series deep-water gas fields, was sanctioned in June 2017 and is currently under development. The Satellite Cluster is a dry gas development and comprises four discoveries with a five-well subsea development in Block KG D6, off the east coast of India. It is expected to come on stream in 2021. In Iraq BP holds a 47.6% working interest and is the lead contractor in the Rumaila technical service contract in southern Iraq. The technical services contract runs to December 2034. Rumaila is one of the world’s largest oil fields, comprising five producing reservoirs. • In January 2018 BP entered into a letter of intent to work on the Kirkuk field which extends until 2019. In Russia in addition to its 19.75% equity interest in Rosneft, BP holds a 20% interest in Taas-Yuryakh Neftegazodobycha (Taas) together with Rosneft (50.1%) and a consortium comprising Oil India Limited, Indian Oil Corporation Limited and Bharat PetroResources Limited (29.9%). Taas is developing the Srednebotuobinskoye oil and gas condensate field in East Siberia (see Rosneft on page 34 for further details). Also with Rosneft, we hold a 49% interest in Yermak 282 «See Glossary BP Annual Report and Form 20-F 2018 Neftegaz LLC, which conducts exploration in the West Siberian and Yenisei-Khatanga basins. Yermak Neftegaz LLC currently holds seven exploration and production licences. The venture has carried out further appraisal work on the Baikalovskoye field, an existing Rosneft discovery in the Yenisei-Khatanga area of mutual interest. • In the second quarter, the Taas-Yuryakh expansion project completed commissioning of the main project facilities for the Srednebotuobinskoye oil and gas condensate. • Also in the second quarter BP acquired a 49% stake in LLC Kharampurneftegaz to develop subsoil resources jointly with Rosneft within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets. • In September Rosneft and BP also agreed to jointly explore two additional oil and gas licence areas located in Sakha (Yakutia). The licences are expected to be held by a Yermak subsidiary. Completion of the deal, subject to external approvals, is expected in 2019. 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 largest single source supplier to the domestic market in Western Australia and one of the largest LNG export projects in the region, with five LNG trains in operation. BP’s net share of the capacity of NWS LNG trains 1-5 is 2.7 million tonnes of LNG per year. BP is also one of five participants in the Browse LNG venture (operated by Woodside) and holds a 17.33% interest. • The Browse project participants finalized evaluating a range of development options for the project and have selected to develop Browse by connecting it via a 900 kilometre pipeline to the NWS venture's Karratha gas plant. A final investment decision is expected in 2021. This decision has resulted in the write-off of $136 million in relation to previous project development costs for Browse. • In October we announced the start-up of production at our Western Flank B project (BP 16.67%), ahead of schedule. • During the year, the Ocean Great White rig contract was cancelled and a commercial arrangement entered into with the lessor whereby BP will utilize different rigs on projects in the future. In Papua Barat, Eastern Indonesia, BP operates the Tangguh LNG plant (BP 40.22%). The asset currently comprises 16 producing wells, two offshore platforms, two pipelines and an LNG plant with two production trains. It has a total capacity of 7.6 million tonnes of LNG per annum. Tangguh supplies LNG to customers in Indonesia, Mexico, China, South Korea, and Japan through a combination of long, medium and short-term contracts. • The Tangguh expansion project is progressing on schedule with the installation of two offshore platforms completed and the construction of the onshore LNG production train and supporting facilities currently ongoing. Drilling on the first of 13 new production wells commenced in early 2019, and first production is expected in 2020. The project will add 3.8 million tonnes per annum (mtpa) of production capacity to the existing facility, bringing total plant capacity to 11.4mtpa. • In November approval from the government of Indonesia to relinquish BP’s 32% interest in the Chevron-operated West Papua I was received. BP Annual Report and Form 20-F 2018 «See Glossary 283 Downstream plant capacity The following tablea summarizes BP group’s interests in refineries and average daily crude distillation capacities as at 31 December 2018. Fuels value chain US US North West US East of Rockies Europe Rhine Iberia Rest of world Australia New Zealand Southern Africa Country Refinery US Cherry Point Whiting Toledo Germany Netherlands Spain Bayernoild Gelsenkirchen Lingen Rotterdam Castellón Australia New Zealand South Africa Kwinana Whangareid e Durband Total BP share of capacity at 31 December 2018 a This does not include BP’s interest in Pan American Energy Group, which is reported through the Upstream segment. b Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period. c BP share of equity, which is not necessarily the same as BP share of processing entitlements. d Indicates refineries not operated by BP. e Reflects BP share of processing entitlement, which is not the same as BP share of equity. Petrochemicals production capacitya The following table summarizes BP group’s share of petrochemicals production capacities as at 31 December 2018. Crude distillation capacitiesb Group interestc (%) BP share thousand barrels per day 100 100 50 10 100 100 100 100 100 10.1 50 236 430 80 746 22 265 95 377 110 869 152 33 90 275 1,890 BP share of capacity thousand tonnes per annumb Geographical area US Europe UK Belgium Germany Rest of world Trinidad & Tobago China Indonesia South Korea Malaysia Taiwan Site Group interestc (%) Cooper River Texas Cityd Hull Geel Gelsenkirchene Mülheime Point Lisas Chongqing Nanjing Zhuhaif Merak Ulsang Kertih Mai Liao Taichung 100 100 100 100 100 100 36.9 51 50 91.9 100 34-51 70 50 61.4 Total BP share of capacity at 31 December 2018 PTA 1,400 — 1,400 — 1,400 — — 1,400 — — — 2,500 500 — — — 500 3,500 6,300 PX — 900 900 — 700 — — 700 — — — — — — — — — — 1,600 Acetic acid Olefins and derivatives — 600 600 500 — — — 500 — 200 300 — — 300 400 200 — 1,400 2,500 — — — — — 3,300 — 3,300 — — — — — — — — — — 3,300 Product Others — 100 100 200 — — 200 400 700 100 — — — 100 — — — 900 1,400 15,100 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 For acetic acid, group interest is quoted at 100%, reflecting the capacity entitlement which is marketed by BP. e 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. f BP Zhuhai Chemical Company Ltd is a subsidiary«of BP, the capacity of which is shown above at 100%. g Group interest varies by product. 284 «See Glossary BP Annual Report and Form 20-F 2018 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 2018 BP had material volumes of proved undeveloped reserves held for more than five years in Russia, 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, or where there are significant commitments on delivery to the relevant authority. Over the past five years, BP has annually progressed a weighted average 19% (18% for 2017 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 2018 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 2018 we progressed 1,306mmboe of proved undeveloped reserves (745mmboe 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 $14,210 million in 2018 ($9,917 million for subsidiaries and $4,293 million for equity-accounted entities). The major areas with progressed volumes in 2018 were Russia, US, Azerbaijan, UAE and Egypt. 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 material net positive revisions to our proved undeveloped resources in Russia as a result of development drilling results and material net negative revisions in the US Lower 48 due to changes in our development plan to incorporate activity associated with the purchase of new assets. The following tables describe the changes to our proved undeveloped reserves position through the year for our subsidiaries and equity-accounted entities and for our subsidiaries alone. Subsidiaries and equity-accounted entities Proved undeveloped reserves at 1 January 2018 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 2018 Subsidiaries only Proved undeveloped reserves at 1 January 2018 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 2018 volumes in mmboea 8,060 20 311 646 1,174 (12) 2,139 15 (1,306) 8,908 volumes in mmboea 4,052 (272) 297 169 945 (12) 1,128 12 (745) 4,447 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 BP Annual Report and Form 20-F 2018 «See Glossary 285 reserves assessment that relies on the integration of three types of data: • well data used to assess the local characteristics and conditions of reservoirs and fluids • field scale seismic data to allow the interpolation and extrapolation of these characteristics outside the immediate area of the local well control • data from relevant analogous fields. 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 35 years of diversified industry experience, with 13 years spent managing the governance and compliance of BP’s reserves estimation. He is a past member of the Society of Petroleum Engineers Oil and Gas Reserves Committee and of the American Association of Petroleum Geologists Committee on Resource Evaluation and is the current chair of the bureau of the United Nations Economic Commission for Europe Expert Group on Resource Classification. No specific portion of compensation bonuses for senior management is directly related to proved reserves targets. Additions to proved reserves is one of several indicators by which the performance of the Upstream segment is assessed by the remuneration committee for the purposes of determining compensation bonuses for the executive directors. Other indicators include a number of financial and operational measures. BP’s variable pay programme for the other senior managers in the Upstream segment is based on individual performance contracts. Individual performance contracts are based on agreed items from the business performance plan, one of which, if chosen, could relate to proved reserves. Compliance International Financial Reporting Standards (IFRS) do not provide specific guidance on reserves disclosures. BP estimates proved reserves in accordance with SEC Rule 4-10 (a) of Regulation S-X and relevant Compliance and Disclosure Interpretations (C&DI) and Staff Accounting Bulletins as issued by the SEC staff. By their nature, there is always some risk involved in the ultimate development and production of proved reserves including, but not limited to: final regulatory approval; the installation of new or additional infrastructure, as well as changes in oil and gas prices; changes in operating and development costs; and the continued availability of additional development capital. All the group’s proved reserves held in subsidiaries and equity-accounted entities are estimated by the group’s petroleum engineers or by independent petroleum engineering consulting firms and then assured by the group’s petroleum engineers. DeGolyer & MacNaughton (D&M), an independent petroleum engineering consulting firm, has estimated the net proved crude oil, condensate, natural gas liquids (NGLs) and natural gas reserves, as of 31 December 2018, 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 2018. 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. Netherland, Sewell & Associates (NSAI), an independent petroleum engineering consulting firm, has estimated the net proved crude oil, condensate, natural gas liquids (NGLs) and natural gas reserves, as of 31 December 2018, of certain properties owned by BP in the US Lower 48. The properties evaluated by NSAI account for 100% of BP’s net proved reserves in the US Lower 48 as of 31 December 2018. The net proved reserves estimates prepared by NSAI were prepared in accordance with the reserves definitions of Rule 4-10(a)(1)-(32) of Regulation S-X. All reserves estimates involve some degree of uncertainty. BP has filed NSAI’s independent report on its reserves estimates as an exhibit to this Annual Report on Form 20-F filed with the SEC. Our proved reserves are associated with both concessions (tax and royalty arrangements) and agreements where the group is exposed to the upstream risks and rewards of ownership, but where our entitlement to the hydrocarbons« is calculated using a more complex formula, such as with PSAs. In a concession, the consortium of which we are a part is entitled to the proved reserves that can be produced over the licence period, which may be the life of the field. In a PSA, we are entitled to recover volumes that equate to costs incurred to develop and produce the proved reserves and an agreed share of the remaining volumes or the economic equivalent. As part of our entitlement is driven by the monetary amount of costs to be recovered, price fluctuations will have an impact on both production volumes and reserves. We disclose our share of proved reserves held in equity-accounted entities (joint ventures« and associates«), although we do not control these entities or the assets held by such entities. BP’s estimated net proved reserves and proved reserves replacement 89% of our total proved reserves of subsidiaries at 31 December 2018 were held through joint operations«(88% in 2017), and 31% of the proved reserves were held through such joint operations where we were not the operator (34% in 2017). 286 «See Glossary BP Annual Report and Form 20-F 2018 Estimated net proved reserves of crude oil at 31 December 2018a b c UK Rest of Europe USd Rest of North Americae South Americaf Africa Rest of Asia Australasia Subsidiaries Equity-accounted entities Total Developed Undeveloped 223 — 962 43 8 223 1,126 30 2,615 3,541 6,156 243 — 802 190 5 36 482 5 1,763 2,792 4,555 Estimated net proved reserves of natural gas liquids at 31 December 2018a b UK Rest of Europe US Rest of North America South America Africa Rest of Asia Australasia Subsidiaries Equity-accounted entities Total Developed Undeveloped 8 — 266 — 2 14 — 5 295 114 409 6 — 246 — 25 4 — — 280 54 335 million barrels Total 466 — 1,764 234 14 259 1,608 34 4,378 6,333 10,711 million barrels Total 14 — 511 — 27 18 — 5 576 169 744 Estimated net proved reserves of liquids« Subsidiariesf Equity-accounted entitiesg Total Developed Undeveloped 2,910 3,655 6,565 2,044 2,846 4,890 million barrels Total 4,954 6,502 11,456 Estimated net proved reserves of natural gas at 31 December 2018a b UK Rest of Europe US Rest of North America South Americah Africa Rest of Asia Australasia Subsidiaries Equity-accounted entitiesi Total billion cubic feet Developed Undeveloped 439 — 6,270 — 2,168 1,313 3,599 2,630 16,420 9,515 25,934 343 — 5,056 — 3,073 1,067 3,218 1,179 13,936 9,369 23,305 Total 782 — 11,326 — 5,241 2,380 6,817 3,809 30,355 18,884 49,239 Estimated net proved reserves on an oil equivalent basis Subsidiaries Equity-accounted entities Total million barrels of oil equivalent Developed 5,741 5,296 11,037 Undeveloped 4,447 4,462 8,908 Total 10,188 9,757 19,945 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently, 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 2018 marker prices used were Brent« $71.43/bbl (2017 $54.36/bbl and 2016 $42.82/ bbl) and Henry Hub« $3.10/mmBtu (2017 $2.96/mmBtu and 2016 $2.46/mmBtu). c Includes condensate. d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels on which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. e All of the reserves in Canada are bitumen. f Includes 12 million barrels of liquids in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. g Includes 356 million barrels of liquids in respect of the non-controlling interest in Rosneft held assets in Russia including 24 million barrels held through BP’s interests in Russia other than Rosneft. h Includes 1,573 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. i Includes 1,211 billion cubic feet of natural gas in respect of the non-controlling interest in Rosneft held assets in Russia including 480 billion cubic feet held through BP’s interests in Russia other than Rosneft. Because of rounding, some totals may not agree exactly with the sum of their component parts. Proved reserves replacement Total hydrocarbon proved reserves at 31 December 2018, on an oil equivalent basis including equity-accounted entities, increased by 8% (increase of 7% for subsidiaries and increase of 9% for equity- accounted entities) compared with 31 December 2017. Natural gas represented about 43% (51% for subsidiaries and 33% for equity- accounted entities) of these reserves. The change includes a net increase from acquisitions and disposals of 1,498mmboe (increase of 993mmboe within our subsidiaries and increase of 505mmboe within our equity-accounted entities). Acquisition activity in our subsidiaries occurred in the US and UK, and divestment activity in our subsidiaries in the US and UK. In our equity-accounted entities acquisitions occurred in our Russian joint ventures other than Rosneft. There were no divestments in our equity-accounted entities. The proved reserves replacement ratio« is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery, and extensions and discoveries. For 2018, the proved reserves replacement ratio excluding acquisitions and disposals was 100% (143% in 2017 and 109% in 2016) for subsidiaries and equity-accounted entities, 66% for subsidiaries alone and 161% for equity-accounted entities alone. There were increases (131mmboe) of reserves due to extension of the date of cessation of production across the group due to higher oil and gas prices, but these were more than offset by decreases (140mmboe) in PSAs, principally in Azerbaijan, Indonesia and Iraq resulting from decreased cost recovery volumes due to higher oil and gas prices. In 2018 net additions to the group’s proved reserves (excluding production and sales and purchases of reserves-in-place) amounted to 1,381mmboe (576mmboe for subsidiaries and 805mmboe for equity-accounted entities), through revisions to previous estimates, improved recovery from, and extensions to, existing fields and discoveries of new fields. The subsidiary additions were through improved recovery from, and extensions to, existing fields and discoveries of new fields where they represented a mixture of proved developed and proved undeveloped reserves. Volumes added in 2018 principally resulted from the application of conventional technologies and extensions of the cessation of production as a result of higher prices. The principal proved reserves additions in our subsidiaries by region were in UAE, Oman and the US. We had material reductions in our proved reserves in Iraq principally due to higher oil and gas prices. The principal reserves additions in our equity-accounted entities were in PAE and Rosneft. 14% of our proved reserves are associated with PSAs. The countries in which we operated under PSAs in 2018 were Algeria, Angola, Azerbaijan, Egypt, India, Indonesia and Oman. In addition, the technical service contract (TSC) governing our investment in the Rumaila field in Iraq functions as a PSA. The group holds no licences due to expire within the next three years that would have a significant impact on BP’s reserves or production. For further information on our reserves see page 217. BP Annual Report and Form 20-F 2018 «See Glossary 287 BP’s net production by country – crude oila and natural gas liquids 2018 2017 Crude oil 2016 thousand barrels per day BP net share of productionb Natural gas liquids 2018 2017 2016 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 Abu Dhabic Azerbaijan Western Indonesiac Iraq India Oman Total Rest of Asia Total Asia Australiac Eastern Indonesiac Total Australasia Total subsidiaries Equity-accounted entities (BP share) Rosneft (Russia, Canada, Venezuela, Vietnam) Abu Dhabi Argentinac Boliviac Egypt Norwayc Russiac Angola Other Total equity-accounted entities Total subsidiaries and equity-accounted entitiesf 101 — — 101 106 18 261 385 24 24 408 7 7 147 49 9 204 169 72 — 54 — 17 313 313 16 2 17 1,051 919 16 52 3 — 34 14 1 — 1,040 2,091 80 — — 80 109 10 251 370 20 20 390 12 12 192 40 9 241 158 90 — 73 1 2 325 325 15 1 17 1,064 900 99 60 3 — 31 5 1 — 1,099 2,163 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 1,015 1,958 5 — — 5 — 37 23 60 — — 60 9 9 — — 11 11 — — — — — — — — 2 — 2 88 4 — — — 3 2 — 3 — 12 100 6 — — 6 — 34 21 56 — — 56 10 10 — — 10 10 — — — — — — — — 2 — 2 85 4 — — — 2 2 — 4 — 12 97 6 4 4 10 — 36 20 56 — — 56 8 8 — — 5 5 — — — — — — — — 3 — 3 82 4 — 1 — 3 — — 1 — 8 90 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 2018, BP acquired various interests in the Permian Basin, Eagle Ford and Haynesville Shales in Lower 48 onshore as a result of the acquisition of BHP’s US unconventional assets, increased its interest in the Clair asset in the UK North Sea, and acquired an interest in LLC Kharampurneftegaz in Russia, and in certain US offshore assets. It also disposed of its interests in the Greater Kuparuk Area in Alaska, the Magnus field in the UK North Sea, and in certain other assets in the UK North Sea and US onshore assets. In 2017, BP renewed its onshore concession of the United Arab Emirates that grants BP 10% interest in ADCO onshore concession. It also decreased its interest in Magnus field in North Sea and completed the formation of Pan American Energy Group (PAEG) (BP 50%, Bridas Corporation 50%), which is a combination of Pan American Energy and Axion Energy with an effective decrease in interest. 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. d Volumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields, which are operated by Shell. e All of the production from Canada in Subsidiaries is bitumen. f Includes 3 net mboe/d of NGLs from processing plants in which BP has an interest (2017 3mboe/d and 2016 3mboe/d). Because of rounding, some totals may not agree exactly with the sum of their component parts. 288 «See Glossary BP Annual Report and Form 20-F 2018 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 Azerbaijan Western Indonesiab India Oman Total Rest of Asia Total Asia Australiab Eastern Indonesiab Total Australasia Total subsidiariesc Equity-accounted entities (BP share) Rosneft (Russia, Canada, Egypt, Venezuela, Vietnam) Argentina Bolivia Norwayb Angola Western Indonesia Total equity-accounted entitiesc Total subsidiaries and equity-accounted entities million cubic feet per day BP net share of productiona 2018 2017 2016 152 — — 152 1,705 190 5 1,900 7 7 1,907 2,136 2,136 878 183 1,061 256 — 32 538 826 826 437 382 819 6,900 1,286 264 71 59 80 — 1,760 8,659 182 — — 182 1,467 186 5 1,659 9 9 1,667 1,936 1,936 745 205 949 232 — 60 79 371 371 426 357 783 5,889 1,308 329 89 53 77 — 1,855 7,744 170 82 82 252 1,476 173 6 1,656 10 10 1,666 1,689 1,689 305 208 513 245 35 84 — 363 363 451 369 820 5,302 1,279 354 95 12 18 15 1,773 7,075 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 2018, BP acquired various interests in the Permian Basin, Eagle Ford and Haynesville Shales in Lower 48 onshore as a result of the acquisition of BHP’s US unconventional assets, increased its interest in the Clair asset in the UK North Sea, and acquired an interest in LLC Kharampurneftegaz in Russia, and in certain US offshore assets. It also disposed of its interests in the Greater Kuparuk Area in Alaska, the Magnus field in the UK North Sea, and in certain other assets in the UK North Sea and US onshore assets. In 2017, BP decreased its interest in Magnus field in North Sea and completed the formation of Pan American Energy Group (PAEG) (BP 50%, Bridas Corporation 50%), which is a combination of Pan American Energy and Axion Energy with an effective decrease in interest.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. 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 2018 «See Glossary 289 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 Europe UK Rest of Europe North America South America Africa Asia Australasia Rest of North Americab US Russia Rest of Asia 71.28 31.63 7.71 53.67 32.77 5.09 42.80 25.70 4.50 — — — — — — — — — — — — — — — 40.16 20.16 4.19 70.24 — 7.93 55.08 — 5.78 50.71 — 5.16 67.11 25.81 2.43 49.98 22.42 2.36 39.65 14.71 1.90 — — — — — — — — — 33.57 — — 36.80 — — 26.11 — — — — — — — — — — — 69.17 35.74 3.08 55.44 26.79 2.25 45.64 21.40 1.72 62.35 — 4.36 49.97 — 4.49 48.88 34.51 4.21 68.81 39.14 4.82 53.61 36.48 3.82 40.83 21.30 3.89 — — — — — — — — — — — — — — — — — — 62.46 N/A 1.70 45.66 N/A 1.63 36.36 N/A 1.39 70.80 92.47 3.85 52.88 — 3.44 39.29 — 3.39 39.49 — — 15.61 — — 12.92 — 6.11 67.54 52.14 7.97 53.26 39.39 6.14 41.52 32.70 5.71 — — — — — — — — — Total group average 67.81 29.42 3.92 51.71 26.00 3.19 39.99 17.31 2.84 62.24 — 2.50 42.33 — 2.47 34.04 34.51 2.20 Subsidiaries 2018 Crude oilc Natural gas liquids Gas 2017 Crude oilc Natural gas liquids Gas 2016 Crude oilc Natural gas liquids Gas Equity-accounted entitiesd 2018 Crude oilc Natural gas liquidse Gas 2017 Crude oilc Natural gas liquidse Gas 2016 Crude oilc Natural gas liquidse Gas Average production cost per unit of productionf $ per unit of production Europe UK Rest of Europe 13.76 14.58 14.80 — — — — — 13.72 12.15 10.33 10.41 North America South America Africa Asia Australasia US 9.63 8.68 10.20 — — — Rest of North America 13.10 15.02 21.79 — — — 3.08 4.41 4.21 10.61 11.92 10.66 Russia Rest of Asia 7.31 6.47 9.34 — — — — — — 3.09 3.19 2.46 5.72 6.37 7.08 5.92 3.27 3.67 2.35 2.79 2.62 — — — Total group average 7.15 7.11 8.46 4.16 4.32 3.57 Subsidiaries 2018 2017 2016 Equity-accounted entities 2018 2017 2016 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 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. e Natural gas liquids for Russia are included in crude oil. f Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes. 290 «See Glossary BP Annual Report and Form 20-F 2018 Environmental expenditure Operating expenditure Capital expenditure Clean-ups Additions to environmental remediation provision Increase (decrease) in decommissioning provision 2018 501 449 31 428 137 2017 441 487 22 249 $ million 2016 487 564 27 262 (228) (804) 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 $501 million in 2018 (2017 $441 million) showed an overall increase of 14% the largest element of which was due to higher expenditures associated with sustaining and increasing production volumes in the Gulf of Mexico region. Environmental capital expenditure in 2018 was lower overall than in 2017 largely due to lower spend resulting from the divestiture of the North Sea Forties Pipeline System and lower expenditure on Arundel, Clair and Schiehallion fields. Clean-up costs were $31 million in 2018 (2017 $22 million) representing increases in oil spill clean-up costs and other associated remediation and disposal costs as well as costs related to the replacement of underground storage tanks in the US. 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 increased in 2018 largely due to the scope reassessments of the remediation plans of a number of our sites in the US and Canada. The charge for environmental remediation provisions in 2018 included $8 million in respect of provisions for new sites (2017 $8 million and 2016 $7 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 2018, the net decrease in the decommissioning provision, similar to the decrease in 2017, was a result of detailed reviews of expected future costs, partially offset by 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 23. 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. 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, solar and shipping activities, 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 US government entities are usually by lease. Arrangements with private property owners are also usually in the form of leases. Licences (or concessions) give the holder the right to explore for, develop and produce a commercial discovery. Under a licence, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the licence holder is entitled to all production, minus any royalties that are payable in kind. A licence holder is generally required to pay production taxes or royalties, which may be in cash or in kind. Less typically, BP may explore for, develop and produce hydrocarbons« under a service agreement with the host entity in exchange for reimbursement of costs and/or a fee paid in cash rather than production. 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 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 BP Annual Report and Form 20-F 2018 «See Glossary 291 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 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. This agreement applies to both developing and developed countries, although in some instances allowances or flexibilities are provided for developing countries. The Paris Agreement aims to hold the increase in the global average temperature to well below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5°C above pre- industrial levels. 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 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 towards absolute emission reduction targets over time. 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. On 1 June 2017, the US announced that it will withdraw from the Paris Agreement. This includes suspending the implementation of the US’s NDC and funding for the Green Climate Fund. The process for withdrawal can be completed no earlier than 4 November 2020. At the United Nations climate change conference in Poland (COP24) in December 2018, the ‘Paris Rulebook’ was agreed. This rulebook describes how the elements of the Paris Agreement will be implemented when it comes into force in 2020. COP24 failed to agree on rules for implementing Article 6, which could enable international carbon trading to assist in meeting NDCs. Discussions on Article 6 have now been deferred to COP25 which will take place in Chile in 2019. More stringent national and regional measures relating to the transition to a lower carbon economy can be expected in the future. These measures could increase BP’s production costs for certain products, increase compliance and litigation costs, increase demand for competing energy alternatives or products with lower-carbon intensity, and affect the sales and specifications of many of BP’s products. Further, such measures could lead to constraints on production and supply and access to new reserves, particularly due to the long term nature of many of BP’s projects. 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 used its existing statutory authority to implement that plan, including the Clean Air Act (CAA) and the Mineral Leasing Act (MLA). BP's operations are affected by regulation in a number of ways under the CAA, for example: • Stricter GHG regulations, stricter limits on sulphur in fuels, emissions regulations in the refinery sector and a revised lower ambient air quality standard for ozone, finalized by the EPA in October 2015, are affecting our US operations. • EPA regulations aimed at methane emissions are in place for new and modified sources. As discussed below, the Bureau of Land Management (BLM) has issued a new waste prevention rule which rescinded the prior rule regarding methane regulation on federal lands. • States may also have separate, stricter air emission laws in addition to the CAA. Despite the US withdrawal from the Paris Agreement, a number of US states, cities and private organizations remain committed to meeting Paris Agreement goals. A number of states also belong to or are considering joining carbon trading markets (e.g. California). As noted below, some of these regulations may be suspended, revised or rescinded resulting in regulatory uncertainty and complex compliance challenges for our affected businesses On 28 March 2017, the Trump administration issued Executive Order (EO) 13783 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 (CPP) which was an important element of the Obama administration’s Climate Action Plan, and the EPA new source methane rule. On 21 August 2018, the EPA introduced the Affordable Clean Energy (ACE) Rule, which is intended to address GHG emissions from certain stationary sources, and which is intended to replace the CPP. The CPP regulations are currently stayed pending resolution of existing legal challenges; the EPA may decline to defend certain of these legal challenges. When the ACE Rule is finalized, it is likely to face legal challenges as well. The outcome with respect to these rules may affect electricity generation practices and prices, reliability of electricity supply, and regulatory requirements affecting other GHG emission sources in other sectors and have potential impacts on combined heat and power installations. 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 by 40-45% from 2012 levels by 2025. In January 2017 the BLM's methane rule, aimed at limiting methane emissions from oil and gas operations on federal lands also came into effect. EO 13783 instructed the Department of Interior (DOI) to 292 «See Glossary BP Annual Report and Form 20-F 2018 review and possibly suspend, revise or rescind the BLM methane rule. In September 2018, BLM finalized a new waste prevention rule, which removed many of the provisions of the former BLM methane rule. The EPA rule and the new waste prevention rule are being challenged by states and NGOs. The final outcome of the rule revisions and legal challenges with respect to these EPA and BLM rules is uncertain. 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 are being phased in - the emission limit values set in the Directive applied from 20 December 2018 for new plants and by 2025 or 2030 for existing plants, depending on their size. 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 in Oregon). In October 2018, President Trump directed the EPA to conduct rulemaking to extend to E15 gasoline the volatility allowance currently given to E10 gasoline under the CAA. Current law allows E15 gasoline to be sold year-round, but this rule will make it easier for E15 to meet the more stringent summer volatility standards. This rulemaking will also address “market reforms” of the RFS credit-trading programme, which is the open market for renewables credit trading. EPA has indicated it hopes to have the rulemaking finalized by the summer 2019 driving season. Under the GHG mandatory reporting rule (GHGMRR), annual reports on GHG emissions must be filed with the EPA. 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. A number of states, municipalities and regional organizations have responded to current and proposed federal changes in environmental regulation and 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 adopted a carbon cap rule that was to become effective 2017, but the rule has been suspended pending review before the state’s supreme court. European Union • EU leaders in 2007 endorsed a set of measures to reduce GHG emissions and encourage renewables in the 2010 to 2020 period. These include an overall GHG reduction target of 20% by 2020. To meet this, a set of regulatory measures were adopted which include: a collective national reduction target for emissions not covered by the EU Emissions Trading System (EU ETS) Directive; binding national renewable energy targets of 20% renewable energy used in 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 legal framework to promote carbon capture and storage (CCS); and a revised EU ETS Phase 3. • In October 2014 EU leaders adopted the climate and energy framework setting key targets for the year 2030 including at least 40% cuts in GHG emissions (from 1990 levels). 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. Measures to achieve the 2030 targets include a significant revision of the EU ETS for Phase 4 agreed in 2017, which addresses the surplus allowances in the system and the amount of free allocation for sectors prone to international competition. In mid-2018 a 32% share of renewable energy and a 32.5% increase in energy efficiency was agreed which must be met by EU Member States by 2030. The package also sets a renewable energy target of 14% for the transportation sector. • On 28 November 2018 the European Commission presented its long-term Energy and Climate Strategy that sets a “vision” towards a net-zero GHG emissions economy by the mid-twenty first century. • The Medium Combustion Plants Directive (MCPD) applies to air emissions of sulphur dioxide (SO2), nitrogen oxides (NOx) and • The National Emission Ceiling Directive 2016 entered into force on 31 December 2016, replacing earlier legislation. It introduces stricter emissions limits from 2020 and 2030, with new indicative national targets applying from 2025. EU member states had to implement the Directive by 1 July 2018. NECD has been implemented in the UK by the National Emission Ceiling Regulations 2018. Each EU Member State is also required to produce a National Air Pollution Control Programme by 31 March 2019 setting out the measures it will take to ensure compliance with the 2020 and 2030 reduction commitments. • 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. 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 compliance obligations being based on facility performance relative to product specific benchmarks. Compliance is possible by improving emissions intensity, the purchase of offsets or the payment of C$30/tonne to the Climate Change and Emissions Management Fund. In addition, there is an economy-wide price of carbon policy that covers emissions not in the scope of the existing regulations for large final emitters (C$30/tonne in 2019; then escalating in line with Federal backstop pricing). Additional requirements are in place relating to electricity generation sources and limits on overall oil sands emissions. The Canadian federal government has announced climate change regulations, effective from January 2019, including a national backstop carbon price starting at C$20/tonne in 2019 and escalating to C$50/tonne by 2022 (or equivalent system for provinces with cap-and-trade systems), with implementation of the price and associated large emitters pricing system (modelled on the Alberta output-based-allocation system), use of any funds generated, and outcome reporting being managed by each province. Newfoundland & Labrador and Nova Scotia are implementing regulations that meet equivalency requirements of the Federal regulations via economy wide carbon taxes on fuels and large emitter programs (intensity based for Newfoundland & Labrador and cap and trade for Nova Scotia). • China is operating emission trading pilot programmes in five cities and three provinces. One of BP's subsidiaries and one of BP’s joint venture« companies in China are participating in these schemes. A plan to establish a nationwide carbon emissions trading market (initially covering the power sector only) was promulgated in December 2017 by the National Development and Reform Commission, which will not supersede the above eight pilot programmes immediately but allow those pilot schemes to be incorporated into the national scheme gradually. In 2018, the Climate Change Bureau was transferred to the newly formed Ministry for Ecology & Environment as part of the overall ministerial restructuring. The Climate Change Bureau remains in charge of the nationwide Emission Trading Scheme with no changes to the 2017 implementation plan. • In July 2016, China carried out pilot programmes on compensation for and trading of energy quotas in four provinces which may be further expanded in or after 2020. In January 2017, a nationwide pilot scheme on the issuance and voluntary purchase and trading of renewable energy green power certificates was launched, and draft regulation issued in 2018. The scheme is expected to undergo further testing in 2019 before becoming mandatory. Generators will be able to obtain certificates, which then can be sold to the two national grid companies. No secondary trading is foreseen initially. BP Annual Report and Form 20-F 2018 «See Glossary 293 • China has also adopted more stringent vehicle tailpipe emission standards and vehicle efficiency standards to address air pollution and GHG emissions. These standards will have an impact on transportation fuel product mix and overall demand. In addition, China has also introduced a mandate for sales of new energy vehicles (NEVs) commencing in 2020. This will accelerate NEV penetration into the light vehicle sector and impact light fuel 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 45. 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 23 for information on provisions for environmental restoration and remediation. A number of pending or anticipated governmental proceedings against certain BP group companies under environmental laws could result in monetary or other sanctions. Group companies are also subject to environmental claims for personal injury and property damage alleging the release of, or exposure to, hazardous substances. The costs associated with future environmental remediation obligations, governmental proceedings and claims could be significant and may be material to the results of operations in the period in which they are recognized. We cannot accurately predict the effects of future developments, such as stricter environmental laws 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 291. 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 2017, the Trump administration has issued a number of Executive Orders (EO) 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 legal challenges to some of these initiatives which can result in regulatory uncertainty and compliance challenges for our operations. • 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. State law analogues to NEPA could also limit or delay our projects. On 15 August 2017 the Trump administration issued EO 13807 which directs federal agencies to take certain actions to streamline the NEPA process although the effect of EO 13807 on our operations remains uncertain. In 2018 the Trump Administration started the rulemaking process to reform the NEPA regulations consistent with EO 13807. • 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’. EPA regulations impose light, medium and heavy duty vehicle emissions standards for GHGs (both fuel economy and tailpipe standards) as well as for nonroad engines and vehicles and permitting requirements for certain large GHG stationary emission sources. California also imposes Low Emission Vehicle (LEV) and Zero Emission Vehicle (ZEV) standards on vehicle manufacturers and a number of other states impose different stricter GHG emission limits on vehicles. These regulations may impact fuel demand and product mix in California and those states adopting LEV and ZEV standards and may impact BP’s product mix and demand for particular products. • In August 2018 the US Department of Transportation and EPA issued a joint proposed rulemaking to establish new or revised fuel economy and tailpipe carbon dioxide emissions standards for passenger cars and light trucks covering model years (MY) 2021 through 2026. The Trump administration’s proposed option would lock in the 2020 standards until 2026. This would be a rollback from the Obama Administration’s rules. The agencies have said they intend to finalize this rulemaking in Spring 2019. The proposal would also eliminate the waiver allowing California and other states to set their own LEV and ZEV standards. California and other states have announced their intention to litigate if such a rule is finalized. • The Clean Water Act regulates wastewater and other effluent discharges from BP’s facilities, and BP is required to obtain discharge permits, install control equipment and implement operational controls and preventative measures. • The Resource Conservation and Recovery Act regulates the generation, storage, transportation and disposal of wastes associated with our operations and can require corrective action at locations where such wastes have been disposed of or released. • The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) can, in certain circumstances, impose the entire cost of investigation and remediation on a party who owned or operated a site contaminated with a hazardous substance, or who arranged for disposal of a hazardous substance at a site. BP has incurred, or is likely to incur, liability under CERCLA or similar state laws, including costs attributed to insolvent or unidentified parties. • BP is also subject to claims for remediation costs 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 reporting on the storage, use and releases of designated quantities of certain listed hazardous substances to federal, 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 EPA has promulgated 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. In 2017, the EPA finalized details regarding the process and requirements for execution of the TSCA inventory reset. • 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 294 «See Glossary BP Annual Report and Form 20-F 2018 safety and reduce workplace emissions at gas processing, refining and other regulated facilities. On 17 January 2017, the US Occupational Safety and Health Administration (OSHA) published an instruction guidance document for implementing and conducting a “National Emphasis Program” for process safety management (PSM) in covered facilities. Over the next several years OSHA will pursue inspections through the National Emphasis Program to ensure compliance with PSM requirements in both refineries and chemical plants. • 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 imposes operational requirements, liability standards and other obligations governing the transportation of petroleum products in US waters and is implemented through regulations issued by the EPA, the US Coast Guard, the DOT, the 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, including equipment and testing, on offshore and onshore operations on federal lands subject to DOI authority. • 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 experienced increasing restrictions on our activities. European Union • The Industrial Emissions Directive (IED) 2010 provides the framework for granting permits for major industrial sites. It lays down rules on integrated prevention and control of air, water and soil pollution arising from industrial activities. As part of the IED framework, additional emission limit values are informed by sector specific and cross-sector Best Available Technology (BAT) Conclusions, such as the BAT Conclusions for the refining sector, for large combustion plants as well as common waste water and waste gas treatment and management systems in the chemical sector. These may result in requirements for BP to further reduce its emissions, particularly its air and water emissions. • The EU regulation on ozone depleting substances 2009 (ODS Regulation) requires companies to reduce the use of ozone depleting substances (ODSs) and phase out use of certain ODSs. BP continues to replace ODSs in refrigerants and/or equipment in the EU and elsewhere, in accordance with the Montreal Protocol and related legislation. The Kigali Amendment to the Montreal Protocol (which aims to reduce hydrofluorocarbons) came into force on 1 January 2019. In addition, the EU regulation on fluorinated GHGs with high global warming potential (the F-gas Regulations) require a phase-out of certain hydrofluorocarbons, based on global warming potential. • European regulations also establish passenger car performance standards for CO2 tailpipe emissions (European Regulation (EC) No 443/2009). By 2021, the European passenger fleet emissions target for new vehicles will be 95 grams of CO2 per kilometre. This target will be achieved by manufacturing fuel efficient vehicles and vehicles using alternative, low carbon fuels such as hydrogen and electricity. In addition, vehicle emission test cycles and vehicle type approval procedures are being updated to improve accuracy of emission and efficiency measurements. 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 October 2018 the European Council released an updated proposal on setting CO2 reduction targets, from a 2021 baseline, of 15% by 2025 and 35% by 2030 for passenger cars, and 15% by 2025 and 30% by 2030 for passenger vans and heavy duty vehicles. • The EU Registration, Evaluation Authorization and Restriction of Chemicals (REACH) Regulation 2006 requires registration of chemical substances manufactured in or imported into the EU, together with the submission of relevant hazard and risk data. REACH affects our manufacturing or trading/import operations in the EU. Since coming into force in 2007, REACH implementation has followed a phase-in schedule defined by the EU, the final phase of which was completed 31 May 2018. BP maintains compliance by checking whether imports are covered by the registrations of non-EU suppliers’ representatives, preparing and submitting registration dossiers to cover new manufactured and imported substances, and updating previously submitted registrations as required. Some substances registered previously, including substances supplied to us by third parties for our use, are now subject to evaluation and review for potential authorization or restriction procedures, and possible banning, by the European Chemicals Agency and EU member state authorities. In addition, BP’s facilities and operations in several EU countries have undergone REACH compliance inspections by the competent authority for the respective EU member state. An amendment to the Annex of the Regulation on classification, labelling and packaging of substances and mixture (CLP Regulation) requires harmonized notification of information on hazardous materials (certain lubricant and fuel formations) to EU member state poison centres. The uniform notification rules will apply as of January 2020 for consumer products, from 2021 for professional and 2024 for industrial uses. • Outside the EU, Turkey has published REACH-like regulations, known as KKDIK, as well as related implementation schedules and substance registrations. BP is compiling and preparing the requisite information to meet the pre-registration requirements for the KKDIK. • 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 review 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. • The “Best Available Techniques Guidance Document on upstream hydrocarbon exploration and production” seeks to document best practice in the upstream sector. The guidance defines Best Available Techniques and best risk management approaches across the upstream lifecycle, from exploration and appraisal through to decommissioning, and largely draws on experience and good practice from existing standards as well as existing regulatory regimes from Member States. While the document is non-binding, the European Commission are encouraging regulatory authorities to utilize this guidance when issuing permits. The guidance is in the final stages of review and is expected to be published in 2019. 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 is upgrading its water treatment facilities to meet consent levels agreed with the regulators to apply water discharge rules arising from the Certificate of Environmental Clearance (CEC) Regulations 2001 and associated Water Pollution Rules 2007. In Angola, BP has upgraded produced water treatment systems to meet revised oil in water limits for produced water discharge under Executive Decree ED 97-14. BP Annual Report and Form 20-F 2018 «See Glossary 295 The Abidjan Convention has been now been ratified by more than 15 African nations, including Angola. The Convention, along with the Additional Protocol published in 2012, sets environmental quality standards for the discharge of chemicals to the marine environment. BP currently operates produced water treatment to meet these quality standards in Angola and is designing systems to meet the standard for our future gas operations in Mauritania and Senegal. 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. OPA also mandates a levy on imported and domestically produced oil to fund oil spill responses. Some states, including Alaska, Washington, Oregon and California, impose additional liability for oil spills. Outside US territorial waters, BP Shipping tankers are subject to international 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 2018, 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, operate on other low sulphur fuels such as LNG or implement approved abatement technology to enable them to meet the low sulphur emissions requirements while continuing to use higher sulphur fuel. This new global cap will not alter the lower limits that apply in the sulphur oxides Emissions Control Areas established by the IMO. Measures to support consistent global implementation are expected to be finalized in 2019. • Under the International Convention for the Control and Management of Ships’ Ballast Water and Sediments 2004, which entered into force in September 2017, ships in international traffic are required to manage their ballast water and sediments to a certain standard, according to a ship-specific ballast water management plan. • The Convention for the Protection of the Marine Environment of the North-East Atlantic (OSPAR), entered into force in March 1998, is an international convention which aims to protect the marine environment of the North-East Atlantic. OSPAR has 16 contracting parties, including the UK Government. Work carried out in accordance with OSPAR is managed by the OSPAR Commission, which is made up of government representatives of the 15 contracting parties and the EU. OSPAR Recommendation 2001/1 relates to the management of produced water from offshore installations in the North Sea. The 2001 recommendation set a target of a 15% reduction in the total quantity of oil in produced water discharged by 2006 compared to 2000 levels and a performance standard for dispersed oil in produced water discharged into the sea of 30 mg/l. More recently, guidelines for the implementation of a risk-based approach to the management of produced water discharges from offshore installations were adopted (OSPAR Recommendation 2012/5). This approach supports a key goal of the 2001 recommendations, that by 2020 Contracting Parties should achieve a reduction of oil in produced water discharged into the sea to a level which will adequately ensure that each of those discharges will present no harm to the marine environment. • The EU shipping monitoring, reporting and verification (MRV) regulation entered into force in July 2015 and is aimed at gathering data on CO2 emissions based on ships’ fuel consumption. It is considered the first step of a staged approach for the inclusion of maritime transport emissions in the EU’s GHG reduction commitment. In parallel, through amendments to MARPOL Annex VI, the IMO Data Collection System (DCS) for collecting and analysing fuel consumption data came into effect in March 2018. 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 explosion and fire and resulting oil spill (the Incident). Lawsuits and claims arising from the Incident were brought principally in US federal and state courts. 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. All federal and state governmental claims in relation to the Incident have now been settled or dismissed and the 2014 administrative agreement with the US Environmental Protection Agency and BP’s obligations thereunder ended in March 2019. The remaining proceedings arising from the Incident are discussed below. PSC settlements PSC settlements – Economic and Property Damages Settlement Agreement In 2012 the Economic and Property Damages Settlement was entered into with the PSC to resolve certain economic and property damage claims. 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, which is under court supervision through the settlement claims process established by the Economic and Property Damages Settlement, continued during 2018. Only a very small number of business economic loss claims remain to be determined, although certain business economic loss claims continue to be appealed by BP and/or the claimants. 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 In 2012 the Medical Benefits Class Action Settlement (Medical Settlement) was entered into with the PSC. It involves payments to qualifying class members based on a matrix for certain Specified Physical Conditions (SPCs), as well as a 21-year Periodic Medical Consultation Program (PMCP) for qualifying class members, and also includes provisions regarding class members pursuing claims for later-manifested physical conditions (LMPCs). 296 «See Glossary BP Annual Report and Form 20-F 2018 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 37,226. As of 25 January 2019, 27,607 claims (comprising 22,833 SPC and 4,774 PMCP only) have been approved for compensation totalling approximately $67 million; 9,615 claims have been denied; and 4 claims are pending determination. In order to seek compensation from BP for an LMPC, class members must file a notice with the Medical Claims Administrator within 4 years after either (i) the date of first diagnosis of the LMPC or (ii) the effective date of the MSA (12 February 2014), whichever is later. As of 22 February 2019, there are 2,159 pending lawsuits brought by class members claiming LMPCs. Other civil complaints – economic loss PSC settlement - Opt out and Excluded claims In 2016, the vast majority of economic loss and property damage claims from individuals and businesses that either opted out of the 2012 PSC settlement and/or were excluded from that settlement were either resolved or dismissed. Although several groups of plaintiffs whose claims were dismissed by the district court for noncompliance with the district court’s prior orders filed appeals in the Fifth Circuit, only a small number of those individual and business plaintiffs now have pending appeals. BP-Branded Fuel Dealers On 23 March 2017, two plaintiffs filed an appeal to the Fifth Circuit from the district court’s October 2012 ruling dismissing their claims on the grounds that alleged losses by dealers of BP- branded fuel allegedly caused by the reputation impact of the spill on the BP brand are not compensable under OPA 90. On 3 July 2018, the Fifth Circuit affirmed the district court’s ruling dismissing their claims. General Maritime Law Claims On 19 July 2017 the district court held that maritime claims by 215 plaintiffs would be subject to further proceedings in MDL 2179 under OPA 90 and under general maritime law. The court dismissed with prejudice all other claims for economic loss brought by private plaintiffs under general maritime law. Five groups of plaintiffs filed appeals in the Fifth Circuit from the dismissal of their claims, and two of those appeals remain pending. MDL 2179 - Other Economic Loss and Property Damage Claims On 11 January 2018, the district court issued an order requiring all remaining plaintiffs in MDL 2179 with economic loss or property damage claims to file by 11 April 2018 a verified sworn statement regarding the actual damages each such plaintiff seeks in its pending litigation and an explanation of how those alleged damages were causally related to the Incident. On 10 July 2018 the district court issued an order on those plaintiffs’ compliance with the January 2018 order and on 29 November 2018 ruled on several motions for reconsideration of its July 2018 compliance order. In those two orders, the district court identified fewer than 200 plaintiffs with economic loss or property damage claims that it deemed to have complied with its January 2018 order, and it dismissed the remaining economic loss or property damage claims with prejudice. Other civil complaints – personal injury The vast majority of post-explosion clean-up, medical monitoring and personal injury claims from individuals that either opted out of the 2012 PSC settlement and/or were excluded from that settlement have been dismissed. On 9 April 2018 the district court in MDL 2179 issued an order requiring the 981 plaintiffs whose claims for post-explosion clean- up, medical monitoring and personal injury claims occurring after the Incident remain pending in MDL 2179 to file a sworn statement providing detailed information regarding their claims. On 20 September 2018, the district court issued an order requiring more than 150 plaintiffs whose responses to the 9 April 2018 order BP deemed to be materially deficient to show cause in writing by 11 October 2018 why their claims should not be dismissed with prejudice for their failure to comply with the court’s order. The district court has not yet ruled on the show cause submissions. Individual securities litigation Following court approval of the settlement of a securities class action brought on behalf of a class of post-explosion American depository share (ADS) holders in 2017, there remained individual cases filed in state and federal courts by pension funds, investment funds and advisers. These were 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. All of the cases, with the exception of one case that has been stayed, were transferred to MDL 2185. As at 31 December 2018, 28 actions on behalf of 113 plaintiffs remained pending in MDL 2185. Canadian class actions Following various legal proceedings, on 26 February 2016, a plaintiff seeking to assert claims under Canadian law against BP on behalf of a class of Canadian residents who allegedly suffered losses because of their purchase of BP ordinary shares and ADSs filed a motion in the Court of Appeal for Ontario to lift a stay on the action. The plaintiff’s motion was granted on 29 July 2016. On 1 September 2017 the court granted in part and denied in part BP’s motion for summary judgment, limiting the case to three alleged misstatements and narrowing the class period. On 3 April 2018, the Court of Appeal for Ontario affirmed that decision. 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. On 5 April 2017, BP moved to dismiss the State of Yucatan’s claims, and the court granted BP's motion to dismiss on 6 March 2018. On 19 April 2013, the Mexican federal government filed a civil action against BP and others in MDL 2179. The complaint sought a determination that each defendant was liable under OPA 90 for damages that included 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. The claims in this civil action were resolved by agreement effective 15 February 2018 and dismissed on 28 March 2018. On 18 October 2012, before a Mexican Federal District Court located in Mexico City, a class action complaint was filed against BP America Production Company (BPAPC) and other BP subsidiaries. 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. On 15 May 2018, BP was formally served with the post-class certification complaint. On 27 June 2018, BP answered the complaint by seeking dismissal on various grounds including that no oil reached Mexican waters or land and there was no economic or environmental harm in Mexico. On 3 December 2015 and 29 March 2016, Acciones Colectivas de Sinaloa (ACS) filed two class actions (which have since been consolidated) in a Mexican Federal District Court on behalf of several Mexican states against BPXP, BPAPC, and other purported BP subsidiaries. In these class actions, plaintiffs seek an order requiring the BP defendants to repair the damage to the Gulf of Mexico, to pay penalties, and to compensate plaintiffs for damage to property, to health and for economic loss. BPXP was formally served with the action on 8 December 2017. BPXP opposed class certification and sought dismissal on 1 February 2018, principally on the basis that that no oil reached Mexican waters or land and there was no economic or environmental harm in Mexico. BPAPC was formally served with the BP Annual Report and Form 20-F 2018 «See Glossary 297 action in October 2018 and filed an opposition to class certification and requested dismissal on 28 December 2018. 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. 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. On 27 September 2018, the OSH Review Commission issued its decision, which reduced the citations to two remaining, and reduced the penalty to $7,000. OSHA has decided not to appeal this decision. 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. On July 31, 2018 the Ninth Circuit granted the parties’ motion to dismiss the appeal voluntarily ending the litigation. 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. Scharfstein v. BP West Coast Products, LLC A class action lawsuit was filed against BP West Coast Products, LLC (BPWCP) 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 BPWCP 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 against BPWCP for the amount of $417.3 million. On 31 May 2018 the Oregon Court of Appeals affirmed the trial court’s ruling. BP filed a Petition for Review to the Oregon Supreme Court which was denied on 8 November 2018. In March 2019, BP and the Plaintiffs agreed to a settlement of the class action lawsuit, subject to final court approval. BP intends to file a petition for a writ of certiorari to the US Supreme Court in order to preserve BP’s appeal rights pending final court approval of the settlement. BP’s provisions for litigation and claims includes a provision for this lawsuit. 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. In May 2018, the US government announced its planned withdrawal from the Joint Comprehensive Plan of Action (JCPOA) under which the US and the EU had implemented temporary, limited and reversible relief of certain sanctions related to Iran. The US government tasked OFAC with implementing the full re-imposition of both primary and secondary sanctions in respect of Iran by the end of a wind-down period. As a result of the JCPOA, BP had considered and developed possible business opportunities in relation to Iran, engaged in discussions with Iranian government officials and other Iranian nationals and attended conferences. BP will continue to monitor and assess business opportunities in Iran which are compliant with EU and US laws applicable to BP including potentially attending meetings in connection with this purpose. On 30 November 2018, BP completed the sale of certain of its assets in the North Sea, including its ownership stake, and the transfer of its role as operator, in the North Sea Rhum field (Rhum) joint arrangement to Serica Energy plc (Serica). Prior to that date, Rhum was owned under a 50:50 unincorporated joint arrangement between BP and Iranian Oil Company (U.K.) Limited (IOC). 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 the Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA). On 3 December 2018 BP entered into an agreement with, among others, SOCAR and NICO pursuant to which SOCAR shall pay to BP 298 «See Glossary BP Annual Report and Form 20-F 2018 Exploration Shah Deniz Limited (BPXSD), as the Shah Deniz Operator, an amount in respect of compensation for NICO’s waiver of its right to lift its share of Shah Deniz condensate. Such amounts shall be used to cover cash calls to NICO in respect of operating costs due from NICO to BPXSD. On 30 November 2018, OFAC issued a new licence in relation to these arrangements. BP holds an interest in a non-BP operated Indian joint venture« that 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 sells lubricants in Cuba through a 50:50 joint arrangement and trades in small quantities of lubricants. During 2014 the US and the EU imposed sanctions on certain Russian activities, individuals and entities, including Rosneft. Certain sectoral sanctions also apply to entities in which entities on the relevant sectoral sanctions list own a certain percentage interest, being either 33% or 50% depending on certain criteria. In August 2017, Russia related sanctions were passed in the US which target among other things: (i) Russian energy export pipelines; (ii) privatisation of state owned assets in Russia; and (iii) certain international offshore Arctic, deepwater and/or shale exploration and production oil projects. We are not aware of any material adverse effect on our current income and investment in Russia or elsewhere as a consequence of those sanctions. BP maintains bank accounts and has registered and paid required fees to maintain registrations of patents and trademarks in certain Sanctioned Countries. BP has equity interests in non-operated joint arrangements« with air fuel sellers, resellers, and fuel delivery services around the world. From time to time, the joint arrangement operator or other partners may sell or deliver fuel to airlines from Sanctioned Countries or flights to Sanctioned Countries, without BP's involvement. BP has no control over the activities non-controlled associates may undertake in Sanctioned Countries or with persons from Sanctioned Countries. Disclosure pursuant to Section 219 of ITRA To our knowledge, none of BP’s activities, transactions or dealings are required to be disclosed pursuant to ITRA Section 219, with the following possible exceptions: • Prior to 30 November 2018, Rhum, located in the UK sector of the North Sea, was operated by BP Exploration Operating Company Limited (BPEOC), a non-US subsidiary of BP, and Rhum was owned under a 50:50 unincorporated joint arrangement between BPEOC and Iranian Oil Company (U.K.) Limited (IOC) which was initially established in 1974. During 2018, BP recorded gross revenues of $177.3 million related to its interests in Rhum. BP had a net profit of $87.7 million for the year ended 31 December 2018. • BP has sought to carry out its role as operator of the Rhum joint arrangement in compliance with US sanctions and has obtained a series of specific OFAC licences relating to the ongoing operation of the Rhum field. • In November 2017, BPEOC entered into an agreement with IOC for the sale and purchase of an IOC entitlement to Forties blend crude oil. The parties agreed to set off the purchase price - £29.89 million ($39.88 million equivalent) - against IOC’s share of operating costs incurred or to be incurred by BPEOC as operator of the Rhum field under the Rhum joint operating agreement. 604,976 net barrels of Forties blend crude oil was loaded at a North Sea terminal in January 2018 and delivered to BP’s Rotterdam refinery. Upon delivery at BP’s Rotterdam refinery, the Forties blend crude oil 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. • During 2018, BPEOC received £223,693 ($298,456 equivalent) (net of tariffs) from BPEOC Forties Pipeline System in respect of monies owed to IOC in relation to the purchase of IOC’s share of Onshore Raw Gas at the Kinneil terminal of the Forties Pipeline System. BP and IOC agreed to set off the £223,693 ($298,456 equivalent) against IOC’s share of operating costs incurred or to be incurred by BPEOC as operator of the Rhum field under the Rhum joint operating agreement. • During 2018, BPEOC received £2.79 million ($3.73 million equivalent) (net of tariffs) from a non-US third party in respect of the sale to such non-US third party of certain NGLs redelivered from the St Fergus terminal. These NGLs had been acquired by BPEOC from IOC at the St. Fergus terminal. BP and IOC agreed to set off the £2.79 million ($3.73 million equivalent) against IOC’s share of operating costs incurred by BPEOC as operator of the Rhum field under the Rhum joint operating agreement. • As noted above, on 30 November 2018, BP completed the sale of its ownership stake in the Rhum joint arrangement and transferred its role as operator to Serica. Prior to the sale, on 5 October 2018, Serica and BP received a conditional licence from OFAC relating to the ongoing operation of the Rhum field. The licence was valid until 31 October 2019 and was conditional upon arrangements being put in place before 5 November 2018 relating to the interests in Rhum held by IOC. An updated licence from OFAC on substantially the same terms and a letter of comfort permitting all non-US persons to support Rhum activities in compliance with US secondary sanctions were issued on 2 November 2018. On the same date the conditions in such OFAC licence in respect of the interest in Rhum held by IOC were met in full. These conditions were satisfied through arrangements which provide that all benefits accruing from and relating to IOC’s interest in Rhum will be held in escrow, by a trust and management company (Rhum Management Company) set up for this purpose, for such period as US sanctions apply. The arrangements are designed to ensure that neither IOC nor any direct or indirect parent company of IOC (including any member of the Government of Iran) will derive any economic benefit from Rhum, or exercise any decision-making powers in respect of Rhum, during that period. From satisfaction of the OFAC licence conditions on 2 November 2018, BP dealt with the Rhum Management Company in respect of Rhum joint venture matters. • In December 2018, BP made a cash transfer of £2.69 million ($3.59 million equivalent) to Rhum Management Company. This transfer represented the net amount of IOC funds in the Rhum joint venture account which had not, to that date, been set off against IOC’s share of operating costs incurred by BPEOC as operator of the Rhum field under the Rhum joint operating agreement. • BP does not expect to enter into any further similar arrangements with IOC or any member of the Government of Iran in relation to the Rhum field. BP will continue to purchase from Serica’s liftings from Rhum or provide services to Serica as the operator of Rhum. • On 17 July 2018 BP Iran Limited terminated its lease of an office in Tehran. The office had been used for administrative activities. In 2018, taxes, including rental tax payments associated with the Tehran office, with an aggregate US dollar equivalent value of approximately $11,000, 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. • During 2018, 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 $3,000. In addition, certain BP employees met with Iranian government officials and other Iranian nationals outside of Iran. No gross revenues or net profits were attributable to these activities, save where otherwise disclosed. BP will continue to monitor and assess business opportunities in Iran which are compliant with EU BP Annual Report and Form 20-F 2018 «See Glossary 299 and US laws applicable to BP including potentially attending meetings in connection with this purpose. directors whom the board has determined to be independent, in the manner described above. Material contracts On 4 April 2016 the district court approved the Consent Decree among BP Exploration & Production Inc., BP Corporation North America Inc., BP p.l.c., the United States and the states of Alabama, Florida, Louisiana, Mississippi and Texas (the Gulf states) which fully and finally resolved any and all natural resource damages (NRD) claims of the United States, the Gulf states, and their respective natural resource trustees and all Clean Water Act (CWA) penalty claims, and certain other claims of the United States and the Gulf states. Concurrently, the definitive Settlement Agreement that BP entered into with the Gulf states (Settlement Agreement) with respect to State claims for economic, property and other losses became effective. BP has filed the Consent Decree and the Settlement Agreement as exhibits to its Annual Report on Form 20-F 2018 filed with the SEC. For further details of the Consent Decree and the Settlement Agreement, see Legal proceedings in BP Annual Report and Form 20- F 2015. Property, plant and equipment BP has freehold and leasehold interests in real estate and other tangible assets in numerous countries, but no individual property is significant to the group as a whole. For more on the significant subsidiaries of the group at 31 December 2018 and the group percentage of ordinary share capital see Financial statements – Note 37. For information on significant joint ventures« and associates« of the group see Financial statements – Notes 16 and 17. Related-party transactions Transactions between the group and its significant joint ventures and associates are summarized in Financial statements – Note 16 and Note 17. In the ordinary course of its business, the group enters into transactions with various organizations with which some of its directors or executive officers are associated. Except as described in this report, the group did not have any material transactions or transactions of an unusual nature with, and did not make loans to, related parties in the period commencing 1 January 2018 to 15 March 2019. 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 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 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 The BP board governance principles prescribe the composition, main tasks and requirements of each of the committees (see the board committee reports on pages 75-86). 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 75). 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 300 «See Glossary BP Annual Report and Form 20-F 2018 and procedures are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud within the company, if any, have been detected. Further, in the design and evaluation of our disclosure controls and procedures our management necessarily was required to apply its judgement in evaluating the costs and benefits of possible control and procedure design options. Also, we have investments in unconsolidated entities. As we do not control these entities, our disclosure controls and procedures with respect to such entities are necessarily substantially more limited than those we maintain with respect to our consolidated subsidiaries. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. The company’s disclosure controls and procedures have been designed to meet, and management believes that they meet, reasonable assurance standards. The company’s management, with the participation of the company’s group chief executive and chief financial officer, has evaluated the effectiveness of the company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b) as of the end of the period covered by this annual report. Based on that evaluation, the group chief executive and chief financial officer have concluded that the company’s disclosure controls and procedures were effective at a reasonable assurance level. Management’s report on internal control over financial reporting Management of BP is responsible for establishing and maintaining adequate internal control over financial reporting. BP’s internal control over financial reporting is a process designed under the supervision of the principal executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of BP’s financial statements for external reporting purposes in accordance with IFRS. As of the end of the 2018 fiscal year, management conducted an assessment of the effectiveness of internal control over financial reporting in accordance with the criteria in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting relating to internal control over financial reporting. Based on this assessment, management has determined that BP’s internal control over financial reporting as of 31 December 2018 was effective. Management’s assessment of the effectiveness of internal control over financial reporting excluded Petrohawk Energy Corporation, which was acquired on 31 October 2018. Petrohawk financial statements constitute 10.3% and 4.0% of net and total assets respectively, 0.2% of revenues, and 0.05% of net income of the consolidated financial statement amounts as of and for the year ended 31 December 2018. This exclusion is in accordance with the general guidance issued by the SEC that an assessment of a recent business combination may be omitted from management’s report on internal control over financial reporting in the first year of consolidation. 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 2018 has been audited by Deloitte, an independent registered public accounting firm, as stated in their report appearing on page 127 of BP Annual Report and Form 20-F 2018. Changes in internal control over financial reporting There were no changes in the group’s internal control over financial reporting that occurred during the period covered by the Form 20-F that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. Principal accountant's fees and services The audit committee has established policies and procedures for the engagement of the independent registered public accounting firm, Deloitte LLP, to render audit and certain assurance services. The policies provide for pre-approval by the audit committee of specifically defined audit, audit-related, non-audit and other services that are not prohibited by regulatory or other professional requirements. Deloitte is engaged for these services when its expertise and experience of BP are important. Most of this work is of an audit nature. The policy has been updated such that non-audit tax services provided by the audit firm from 2017 onwards are prohibited. 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); provision of, or access to, Deloitte publications, workshops, seminars and other training materials; provision of reports from data gathered on non-financial policies and information; provision of the independent third party audit in accordance with US Generally Accepted Government Auditing Standards, over the company’s Conflict Minerals Report – where such a report is required under the SEC rule ‘Conflict Minerals’, issued in accordance with Section 1502 of the Dodd Frank Act; and assistance with understanding non-financial regulatory requirements. BP operates a two-tier system for audit and non-audit services. For audit related services, the audit committee has a pre-approved aggregate level, within which specific work may be approved by management. Non-audit services are pre-approved for management to authorize per individual engagement, but above a defined level must be approved by the chairman of the audit committee or the full committee. In response to the revised regulatory guidelines of the UK Financial Reporting Council, the audit committee reviewed and updated its policies with effect from 1 January 2017 and in 2018 further updated its policies to clarify the engagement of the incoming auditor, Deloitte, and the outgoing auditor (and auditor of Rosneft) Ernst & Young to ensure independence. The defined maximum level for pre- approval has been reduced in line with FRC guidance on ‘non-trivial’ engagements. The audit committee has delegated to the chairman of the audit committee authority to approve permitted services provided that the chairman reports any decisions to the committee at its next scheduled meeting. Any proposed service not included in the approved service list must be approved in advance by the audit committee chairman and reported to the committee, or approved by the full audit committee in advance of commencement of the engagement. The audit committee evaluates the performance of the auditor each year. The audit fees payable to Deloitte are reviewed by the committee in the context of other global companies for cost effectiveness. The committee keeps under review the scope and results of audit work and the independence and objectivity of the auditor. External regulation and BP policy requires the auditor to rotate its lead audit partner every five years. See Financial statements – Note 36 and Audit committee report on page 79 for details of fees for services provided by the auditor. Directors’ report information This section of BP Annual Report and Form 20-F 2018 forms part of, and includes certain disclosures which are required by law to be included in, the Directors’ report. Indemnity provisions BP Annual Report and Form 20-F 2018 «See Glossary 301 effective. The federal government and the Gulf states may jointly elect to accelerate the payments under the Consent Decree in the event of a change of control or insolvency of BP p.l.c., and the Gulf states individually have similar acceleration rights under the Settlement Agreement. For further details of the Consent Decree and the Settlement Agreement, see Legal proceedings in BP Annual Report and Form 20-F 2015. Greenhouse gas emissions The disclosures in relation to greenhouse gas emissions are included in Sustainability – Climate change on page 45. 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 159 Not applicable 302 Not applicable 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 2018. During the year, a review of the terms and scope of the policy was undertaken. The policy was renewed during 2018 and continued into 2019. 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 53, Liquidity and capital resources on page 277 and Financial statements – Notes 29 and 30. Exposure to price risk, credit risk, liquidity risk and cash flow risk The disclosures in relation to exposure to price risk, credit risk, liquidity risk and cash flow risk are included in Financial statements – Note 29. Important events since the end of the financial year Disclosures of the particulars of the important events affecting BP which have occurred since the end of the financial year are included in the Strategic report as well as in other places in the Directors’ report. Likely future developments in the business An indication of the likely future developments in the business of the company is included in the Strategic report. Research and development An indication of the activities of the company in the field of research and development is included in Innovation in BP on page 40. 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 51. 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 4 April 2016, the district court approved the Consent Decree, at which time the Consent Decree and Settlement Agreement became 302 «See Glossary BP Annual Report and Form 20-F 2018 Cautionary statement In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, BP is providing the following cautionary statement. This document contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past, events and circumstances - with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, (i) certain statements in the Chairman’s letter (pages 6-7), the Group chief executive’s letter (page 8), the Strategic report (inside cover and pages 1-56), Additional disclosures (pages 273-304) and Shareholder information (pages 305-314), including but not limited to statements under the headings ‘The changing energy mix’, ‘How we run our business’, ‘Our strategy’ and ‘Global energy markets’ and including but not limited to statements regarding plans and prospects relating to near- and long- term growth, organic capital expenditure, organic growth, the strength of BP’s balance sheet, maintaining a robust cash position, working capital, operating cash flow and margins, capital discipline, growth in sustainable free cash flow and shareholder distributions and future dividend and optional scrip dividend payments; plans and expectations regarding share buybacks, including to offset the impact of dilution from the scrip programme since the third quarter 2017 by the end of 2019; expectations regarding world energy demand, including the growth in relative demand for renewables, oil and gas, and the proportional growth of renewables; expectations with respect to the world energy mix, production, consumption and emissions to 2040; plans and expectations regarding BP’s portfolio, including having a distinctive portfolio, BP’s active management of the portfolio and the flexibility of the portfolio; plans and expectations with respect to disciplined investment; plans and expectations with respect to the Upstream, including growing advantaged oil and gas, being competitive in every basin and producing resilient and competitive barrels; plans and expectations with respect to BP’s transformation agenda; plans and expectations to deliver 2021 financial targets; expectations with respect to reserves bookings from new discoveries; plans and expectations regarding BP’s quality of execution, including to get more from a unit of capital compared to peers; plans and expectations with respect to BP’s refining and petrochemicals portfolio; plans and expectations with respect to creating distinctive retail offers in the Downstream; plans and expectations with regard to new technologies, including their efficiency and impact on production; plans and expectations with respect to BP’s investments in Chargemaster, StoreDot and FreeWire, including for BP to become the leading fuel provider for both conventional and electric vehicles and supporting electric vehicle adoption; plans and expectations with respect to BP’s investment in solar energy and biofuels, including to invest $200 million in Lightsource BP over a three-year period; plans and expectations with respect to the commercial optimization programme; plans and expectations to run safe and reliable operations; plans and expectations regarding BP’s acquisition of onshore-US oil and gas assets from BHP, including expectations regarding the funding and timing of further purchase price payments, future performance and operations and related divestments; plans and expectations to reduce emissions in operations and the low carbon future, including to target zero net growth in operational emissions to 2025 and the Advancing Low Carbon accreditation programme; plans and expectations with respect to evaluating the creation of a joint venture with SOCAR; plans and expectations regarding BP’s low carbon businesses, including in Brazil and India; plans and expectations with respect to Fulcrum BioEnergy’s commercial operations; plans to grow third-party technology licensing income; plans and expectations regarding charges in Other businesses and corporate in 2019 and proceeds from divestments and disposals, including to have more than $10 billion of divestments over the next two years; expectations regarding the determination of business economic loss claims in respect of the 2012 PSC settlement and expectations with respect to the timing and amount of future payments relating to the Gulf of Mexico oil spill including 2012 PSC settlement payments; plans and expectations regarding sales commitments of BP and its equity-accounted entities; expectations regarding underlying production and capital investment; plans and expectations with respect to gearing including to target gearing within a 20-30% band; expectations regarding oil prices; expectations regarding the return on average capital employed; expectations with respect to the cash break even point; plans and expectations regarding the US onshore, including to increase the liquid hydrocarbon proportion and to upgrade and reposition BPX Energy; plans with regard to BP’s exploration budget; plans and expectations regarding the resiliency of downstream businesses; expectations regarding the effective tax rate in 2019; plans to produce 900,000boe/d from new major projects by 2021 and expectations regarding operating cash margins of this production; plans to start up five major projects in 2019; plans and expectations with respect to expected project start-ups between 2019 and 2021; plans and expectations regarding investment, development, and production levels and the timing thereof with respect to projects and partnerships in Australia, Azerbaijan, Brazil, China, Egypt, India, Indonesia, Libya, Mexico, Mauritania, Russia, São Tomé and Príncipe, Senegal, Turkey, Trinidad & Tobago, Oman, the UK North Sea, the Gulf of Mexico, and the continental United States; expectations regarding the Trans Anatolian Natural Gas Pipeline; plans and expectations regarding social investment; plans and expectations regarding relationships with governments, customers, partners, suppliers and communities; plans and expectations regarding the dual energy challenge and the energy transition, including BP’s progressive and pragmatic approach and planned investments; plans and expectations regarding shareholder resolutions; plans and expectations with respect to BP’s public reporting of ambitions, plans and progress; plans and expectations regarding innovation in BP, including the development of BPme, Wolfspar, a land seismic recording system, APEX, Plant Operations Advisor and wind energy storage systems; plans and expectations regarding plant reliability and base decline, including for base decline to remain between 3-5%; plans and expectations regarding the Tangguh gas facility; expectations regarding discounts for North American heavy crude oil, refining margins and refining turnarounds; plans to undertake joint exploration and development with Rosneft, including to explore oil and gas licence areas in Sakha (Yakutia); expectations regarding pensions and other post-retirement benefits; expectations regarding payments under contractual obligations; 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; policies and goals related to risk management plans; plans regarding activities, dealings and transactions relating to Iran; plans and projections regarding oil and gas reserves, including the turnover time of proved undeveloped reserves to proved developed reserves; expectations regarding the costs of environmental restoration programmes; 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; 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 57-86) and the Directors’ remuneration report (pages 87-109) with regard to the anticipated future composition of the board of directors and the effects thereof; the board’s goals and areas of focus, including changes to KPIs and those goals stemming from the board’s annual evaluation; plans and expectations regarding directors’ share ownership and remuneration; plans regarding the governance and remuneration processes; and goals, activities and areas of focus of board committees, are all forward looking in nature. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward looking statements; the receipt of BP Annual Report and Form 20-F 2018 «See Glossary 303 relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new projects onstream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; production-sharing agreements effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations and policies, including related to climate change; changes in social attitudes and customer preferences; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately determined to be payable and the timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non- compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyberattacks or sabotage; and other factors discussed elsewhere in this report including under Risk factors (pages 55-56). 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. 304 «See Glossary BP Annual Report and Form 20-F 2018 Shareholder information 306 Share pricings and listings 306 Dividends 306 Shareholder taxation information 308 Major shareholders 309 Annual general meeting 309 Memoradum and Articles of Association 312 Purchases of equity securities by the issuer and affiliated purchasers 313 Fees and charges payable by ADS holders 313 Fees and payments made by the Depositary to the issuer 313 Documents on display 314 Shareholding administration 314 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 2017 BP Annual Report and Form 20-F 2018 279 305 Share prices and listings Markets and market prices The primary market for BP’s ordinary shares is the London Stock Exchange (LSE) (trading symbol 'BP'). BP’s ordinary shares are a constituent element of the Financial Times Stock Exchange 100 Index. 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 (trading symbol 'BP'), for which JPMorgan Chase Bank, N.A. is the depositary (the Depositary) and transfer agent. The Depositary’s principal office is 383 Madison Avenue, Floor 11, New York, NY, 10179, US. Each ADS represents six ordinary shares. ADSs are listed on the NYSE. ADSs are evidenced by American depositary receipts (ADRs), which may be issued in either certificated or book entry form. BP's securities are also traded in the form of a global depositary certificate representing BP ordinary shares on the Frankfurt, Hamburg and Dusseldorf Stock Exchanges. On 11 March 2019, 922,206,611 ADSs (equivalent to approximately 5,533,239,666 ordinary shares or some 27.31% of the total issued share capital, excluding shares held in treasury) were outstanding and were held by approximately 81,329 ADS holders. Of these, about 80,393 had registered addresses in the US at that date. One of the registered holders of ADSs represents some 1,207,639 underlying holders. On 11 March 2019 there were approximately 235,594 ordinary shareholders. Of these shareholders, around 1,540 had registered addresses in the US and held a total of some 4,112,535 ordinary shares. Since a number of the ordinary shares and ADSs were held by brokers and other nominees, the number of holders in the US may not be representative of the number of beneficial holders or their respective country of residence. Dividends 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 10. A Scrip Dividend Programme (Scrip Programme) was approved by shareholders in 2010 and was renewed for a further three years at the 2018 AGM. It enables BP ordinary shareholders and ADS holders to elect to receive dividends by way of new fully paid BP ordinary shares (or ADSs in the case of ADS holders) instead of cash. The operation of the Scrip Programme is always subject to the directors’ decision to make the Scrip Programme offer available in respect of any particular dividend. Should the directors decide not to offer the Scrip Programme in respect of any particular dividend, cash will be paid automatically instead. Future dividends will be dependent on future earnings, the financial condition of the group, the Risk factors set out on page 55 and other matters that may affect the business of the group set out in Our strategy on page 10 and in Liquidity and capital resources on page 277. The following table shows dividends announced and paid by the company per ADS for the past five years. Dividends per ADSa 2013 2015 2014 UK pence US cents UK pence US cents UK pence US cents UK pence US cents UK pence US cents 2018 UK pence US cents 2016 2017 March 36.01 54 34.24 57 40.00 60 42.08 60 48.95 60 43.01 60 June September December Total 35.01 54 34.84 58.5 39.18 60 41.50 60 46.54 60 44.66 60 34.58 54 35.76 58.5 39.29 60 45.35 60 45.73 60 47.58 61.50 34.80 57 38.26 60 39.81 60 47.59 60 44.66 60 48.15 61.50 140.40 219 143.10 234 158.28 240 176.52 240 185.88 240 183.40 243 a Dividends announced and paid by the company on ordinary and preference shares are provided in Financial statements – Note 10. There are currently no UK foreign exchange controls or restrictions on remittances of dividends on the ordinary shares or on the conduct of the company’s operations, other than restrictions applicable to certain countries and persons subject to EU economic sanctions or those sanctions adopted by the UK government which implement resolutions of the Security Council of the United Nations. Shareholder taxation information This section describes the material US federal income tax and UK taxation consequences of owning ordinary shares or ADSs to a US holder who holds the ordinary shares or ADSs as capital assets for tax purposes. It does not apply, however, inter alia to members of special classes of holders some of which may be subject to other rules, including: tax-exempt entities, life insurance companies, dealers in securities, traders in securities that elect a mark-to-market method of accounting for securities holdings, investors liable for alternative minimum tax, holders that, directly or indirectly, hold 10% or more of the company’s 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. 306 «See Glossary BP Annual Report and Form 20-F 2018 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, was entitled to a tax credit on cash dividends paid on ordinary shares or ADSs of the company equal to one-ninth of the cash dividend. From 6 April 2016 the dividend tax credit was replaced by a new tax- free dividend allowance and dividends paid by the company on or after 6 April 2016 do not carry a UK tax credit. The dividend allowance was £5,000 but this has been reduced to £2,000 as of 6 April 2018. The dividend allowance of £2,000 means there is no UK tax due on the first £2,000 of dividends received. Dividends above this level are subject to tax at 7.5% for basic tax payers, 32.5% for higher rate tax payers and 38.1% for additional rate tax payers. Although the first £2,000 of dividend income is not subject to UK income tax, it does not reduce the total income for tax purposes. Dividends within the dividend allowance still count towards basic or higher rate bands, and may therefore affect the rate of tax paid on dividends received in excess of the £2,000 allowance. For instance, if an individual has an annual gross salary of £50,000 and also receives a dividend of £12,000 they will be subject to the following scenario. The individual's personal allowance and the basic rate tax band will be used up by the gross salary. The remaining part of the salary and the whole of the dividend will be subject to tax at the higher rate, although the dividend allowance will reduce the amount of dividend subject to tax. The dividend of £12,000 will be reduced by the dividend allowance of £2,000 leaving taxable dividend income of £10,000. The dividend will be taxed at 32.5% so that the total tax payable on the dividends is £3,250. How the shareholder pays the tax arising on the dividend income depends on the amount of dividend income and salary they receive in the tax year. If less than £2,000 they will not need to report anything or pay any tax. If between £2,000 and £10,000, the shareholder can pay what they owe by: contacting the helpline; asking HMRC to change their tax code – the tax will be taken from their wages or pension or through completion of the ‘Dividends’ section of their tax return, where one is being filed. If over £10,000 they will be required to file a self-assessment tax return and should complete the ‘Dividends’ section with details of the amounts received. US federal income taxation A US holder is subject to US federal income taxation on the gross amount of any dividend paid by the company out of its current or accumulated earnings and profits (as determined for US federal income tax purposes). Dividends paid to a non-corporate US holder that constitute qualified dividend income will be taxable to the holder at a preferential rate, provided that the holder has a holding period in the ordinary shares or ADSs of more than 60 days during the 121-day period beginning 60 days before the ex-dividend date and meets other holding period requirements. Dividends paid by the company with respect to the ordinary shares or ADSs will generally be qualified dividend income. For US federal income tax purposes, a dividend must be included in income when the US holder, in the case of ordinary shares, or the Depositary, in the case of ADSs, actually or constructively receives the dividend and will not be eligible for the dividends-received deduction generally allowed to US corporations in respect of dividends received from other US corporations. US ADS holders should consult their own tax 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. 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. BP Annual Report and Form 20-F 2018 «See Glossary 307 For gains on or after 23 June 2010, the UK Capital Gains Tax rate will be dependent on the level of an individual’s taxable income. Where total taxable income and gains after all allowable deductions are less than the upper limit of the basic rate income tax band of £34,500 (for 2018/19), the rate of Capital Gains Tax will be 10%. For gains (and any parts of gains) above that limit the rate will be 20%. From 6 April 2008, entitlement to the annual exemption is based on an individual’s circumstances (taking into account Domicile status, remittance basis of taxation and number of years in the UK). For individuals who are entitled to the exemption for 2018/19, this has been set at £11,700. Corporation tax on chargeable gains is levied at 19 per cent for companies from 1 April 2017. US federal income taxation A US holder who sells or otherwise disposes of ordinary shares or ADSs will recognize a capital gain or loss for US federal income tax purposes equal to the difference between the US dollar value of the amount realized on the disposition and the US holder’s tax basis, determined in US dollars, in the ordinary shares or ADSs. Any such capital gain or loss generally will be long-term gain or loss, subject to tax at a preferential rate for a non-corporate US holder, if the US holder’s holding period for such ordinary shares or ADSs exceeds one year. Gain or loss from the sale or other disposition of ordinary shares or ADSs will generally be income or loss from sources within the US for foreign tax credit limitation purposes. The deductibility of capital losses is subject to limitations. We do not believe that ordinary shares or ADSs will be treated as stock of a passive foreign investment company (PFIC) for US federal income tax purposes, but this conclusion is a factual determination that is made annually and thus is subject to change. If we are treated as a PFIC, unless a US holder elects to be taxed annually on a mark- to-market basis with respect to ordinary shares or ADSs, any gain realized on the sale or other disposition of ordinary shares or ADSs would in general not be treated as capital gain. Instead, a US holder would be treated as if he or she had realized such gain rateably over the holding period for ordinary shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain was allocated, in addition to which an interest charge in respect of the tax attributable to each such year would apply. Certain ‘excess distributions’ would be similarly treated if we were treated as a PFIC. Additional tax considerations Scrip Programme 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. Purchases of ordinary shares, as opposed to ADSs, through the CREST system of paperless share transfers will be subject to stamp duty reserve tax at 0.5%. The charge will arise as soon as there is an agreement for the transfer of the shares (or, in the case of a conditional agreement, when the condition is fulfilled). The stamp duty reserve tax will apply to agreements to transfer ordinary shares even if the agreement is made outside the UK between two non- residents. Purchases of ordinary shares outside the CREST system are subject either to stamp duty at a rate of £5 per £1,000 (or part, unless the stamp duty is less than £5, when no stamp duty is charged), or stamp duty reserve tax at 0.5%. Stamp duty and stamp duty reserve tax are generally the liability of the purchaser. A subsequent transfer of ordinary shares to the Depositary’s nominee will give rise to further stamp duty at the rate of £1.50 per £100 (or part) or stamp duty reserve tax at the rate of 1.5% of the value of the ordinary shares at the time of the transfer. For ADR holders electing to receive ADSs instead of cash, after the 2012 first quarter dividend payment, HM Revenue & Customs no longer seeks to impose 1.5% stamp duty reserve tax on issues of UK shares and securities to non- EU clearance services and depositary receipt systems. US Medicare Tax A US holder that is an individual or estate, or a trust that does not fall into a special class of trusts that is exempt from such tax, is subject to a 3.8% tax on the lesser of (1) the US holder’s ‘net investment income’ (or ‘undistributed net investment income’ in the case of an estate or trust) for the relevant taxable year and (2) the excess of the US holder’s modified adjusted gross income for the taxable year over a certain threshold (which in the case of individuals is between $125,000 and $250,000, depending on the individual’s circumstances). A holder’s net investment income generally includes its dividend income and its net gains from the disposition of shares or ADSs, unless such dividend income or net gains are derived in the ordinary course of the conduct of a trade or business (other than a trade or business that consists of certain passive or trading activities). If you are a US holder that is an individual, estate or trust, you are urged to consult your tax 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 2018 Range of holdings 1-200 201-1,000 1,001-10,000 10,001-100,000 100,001-1,000,000 Over 1,000,000a Totals Number of ordinary shareholders Percentage of total ordinary shareholders Percentage of total ordinary share capital excluding shares held in treasury 53,495 79,856 90,654 10,801 948 689 236,443 22.63 33.77 38.34 4.57 0.40 0.29 100.00 0.01 0.22 1.41 1.11 1.77 95.48 100.00 a Includes JPMorgan Chase Bank, N.A. holding 27.32% 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. 308 «See Glossary BP Annual Report and Form 20-F 2018 Register of holders of American depositary shares (ADSs) as at 31 December 2018a 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 Percentage of  total ADS holders Percentage of  total ADSs 48,763 21,504 11,266 501 7 1 82,042 59.44 26.21 13.73 0.61 0.01 0.00 100.00 0.28 1.11 3.17 0.91 0.13 94.40 100.00 a One ADS represents six 25 cent ordinary shares. b One holder of ADSs represents 1,169,280 underlying shareholders. As at 31 December 2018 there were also 1,286 preference shareholders. Preference shareholders represented 0.42% and ordinary shareholders represented 99.58% of the total issued nominal share capital of the company (excluding shares held in treasury) as at that date. As at 31 December 2018, we had been notified pursuant to DTR5 that BlackRock, Inc. held 6.84% of the voting rights attached to the issued share capital of the company. Between 1 January 2019 and 11 March 2019, we received notification of the following interests pursuant to DTR5. On 12 February 2019, BlackRock, Inc. notified BP that it held 7.29% of the voting rights attached to the issued share capital of the company. On 19 February 2019, BlackRock, Inc. notified BP that it held 7.28% of the voting rights attached to the issued share capital of the company. We are also aware that, as at 11 March 2019, BlackRock, Inc. held 6.61% and The Vanguard Group, Inc. held 3.45% of the ordinary issued share capital of the company. Under the US Securities Exchange Act of 1934 BP is aware of the following interests as at 11 March 2019: Holder JPMorgan Chase Bank N.A., depositary for ADSs, through its nominee Guaranty Nominees Limited BlackRock, Inc. Holding of ordinary shares Percentage of ordinary share capital excluding shares held in treasury 5,533,239,667 1,339,183,607 27.31 6.61 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 11 March 2019: Holder Holding of 8% cumulative first preference shares Percentage of class The National Farmers Union Mutual Insurance Society Limited 945,000 13.10 Hargreaves Lansdown Asset Management Limited Canaccord Genuity Group Inc. Prudential plc Holder The National Farmers Union Mutual Insurance Society Limited Prudential plc 628,471 587,885 528,150 8.70 8.10 7.30 Holding of 9% cumulative second preference shares Percentage of class 987,000 644,450 18.00 11.80 Safra Group Hargreaves Lansdown Asset Management Limited Canaccord Genuity Group Inc. 320,000 317,789 283,135 5.80 5.80 5.20 As at 11 March 2019, the total preference shares in issue comprised only 0.42% of the company’s total issued nominal share capital (excluding shares held in treasury), the rest being ordinary shares. Annual general meeting The 2019 AGM will be held on Tuesday 21 May 2019 at 11.00am. A separate notice convening the meeting is distributed to shareholders, which includes an explanation of the items of business to be considered at the meeting. All resolutions for which notice has been given will be decided on a poll. Deloitte LLP have expressed their willingness to continue in office as auditors and a resolution for their reappointment is included in the Notice of BP Annual General Meeting 2019. Memorandum and Articles of Association The following summarizes certain provisions of the company’s Memorandum and Articles of Association and applicable English law. This summary is qualified in its entirety by reference to the UK Companies Act 2006 (the Act) and the company’s Memorandum and Articles of Association. The Memorandum and Articles of Association are available online at bp.com/usefuldocs. The company’s Articles of Association may be amended by a special resolution at a general meeting of the shareholders. At the annual general meeting (AGM) held on 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 and shareholders voted to adopt new Articles of Association at the AGM held on 16 April 2015. At the AGM held on 21 May 2018 shareholders voted to adopt new Articles of Association to reflect developments in market practice and to provide clarification and additional flexibility where necessary or appropriate. Objects and purposes BP is a public company limited by shares, incorporated under the name BP p.l.c. and is registered in England and Wales with the registered number 102498. The provisions regulating the operations of the company, known as its ‘objects’, were historically stated in a company’s memorandum. The Act abolished the need to have object provisions and so at the AGM held on 15 April 2010 shareholders approved the removal of its objects clause together with all other provisions of its Memorandum that, by virtue of the Act, are treated as forming part of the company’s Articles of Association. Directors and secretary The business and affairs of BP shall be managed by the directors. The company’s Articles of Association provide that directors may be appointed by the existing directors or by the shareholders in a general meeting. Any person appointed by the directors will hold office only until the next general meeting, notice of which is first given after their appointment and will then be eligible for re-election by the shareholders. A director may be removed by BP as provided for by applicable law and shall vacate office in certain circumstances as set out in the Articles of Association. In addition the company may, by special resolution, remove a director before the expiration of his/her period of office and, subject to the Articles of Association, may by ordinary resolution appoint another person to be a director instead. There is no requirement for a director to retire on reaching any age. The Articles of Association place a general prohibition on a director voting in respect of any contract or arrangement in which the director has a material interest other than by virtue of such director’s interest in shares in the company. However, in the absence of some other material interest not indicated below, a director is entitled to vote and to be counted in a quorum for the purpose of any vote relating to a resolution concerning the following matters: • The giving of security or indemnity with respect to any money lent or obligation taken by the director at the request or benefit of the company or any of its subsidiary undertakings. • Any proposal in which the director is interested, concerning the underwriting of company securities or debentures or the giving of any security to a third party for a debt or obligation of the company or any of its subsidiary undertakings. BP Annual Report and Form 20-F 2018 «See Glossary 309 • 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. The Articles of Association provide entitlement to the directors’ pensions and death and disability benefits to the directors’ relations and dependants respectively. The circumstances in which a director’s office will automatically terminate include: when a director ceases to hold an executive office of the company and the directors resolve that he should cease to be a director; if a medical practitioner provides an opinion that a director has become incapable of acting as a director and may remain so incapable for a further three months and the directors resolve that he should cease to be a director; and if all of the other directors vote in favour of a resolution stating that the person should cease to be a director. The company secretary has express powers to delegate any of the powers or discretions conferred on him or her. Dividend rights; other rights to share in company profits; capital calls If recommended by the directors of BP, shareholders of BP may, by resolution, declare dividends but no such dividend may be declared in excess of the amount recommended by the directors. The directors may also pay interim dividends without obtaining shareholder approval. No dividend may be paid other than out of profits available for distribution, as determined under IFRS and the Act. Dividends on ordinary shares are payable only after payment of dividends on BP preference shares. Any dividend unclaimed after a period of 10 years from the date of declaration of such dividend shall be forfeited and reverts to BP. If the company exercises its right to forfeit shares and sells shares belonging to an untraced shareholder then any entitlement to claim dividends or other monies unclaimed in respect of those shares will be for a period of twelve months after the sale. The company may take such steps as the directors decide are appropriate in the circumstances to trace the member entitled and the sale may be made at such time and on such terms as the directors may decide. The directors have the power to declare and pay dividends in any currency provided that a sterling equivalent is announced. It is not the company’s intention to change its current policy of paying dividends in US dollars. At the company’s AGM held on 15 April 2010, shareholders approved the introduction of a Scrip Dividend Programme (Scrip Programme) and to include provisions in the Articles of Association to enable the company to operate the Scrip Programme. The Scrip Programme was renewed at the company’s AGM held on 21 May 2018 for a further three years. The Scrip Programme enables ordinary shareholders and BP ADS holders to elect to receive new fully paid ordinary shares (or BP ADSs in the case of BP ADS holders) instead of cash. The operation of the Scrip Programme is always subject to the directors’ decision to make the scrip offer available in respect of any particular dividend. Should the directors decide not to offer the scrip in respect of any particular dividend, cash will automatically be paid instead. The directors may determine in relation to any scrip dividend plan or programme how the costs of the programme will be met, the minimum number of ordinary shares required in order to be able to participate in the programme and any arrangements to deal with legal and practical difficulties in any particular territory. Apart from shareholders’ rights to share in BP’s profits by dividend (if any is declared or announced), the Articles of Association provide that the directors may set aside: • A special reserve fund out of the balance of profits each year to make up any deficit of cumulative dividend on the BP preference shares. • A general reserve out of the balance of profits each year, which shall be applicable for any purpose to which the profits of the company may properly be applied. This may include capitalization of such sum, pursuant to an ordinary shareholders’ resolution, and distribution to shareholders as if it were distributed by way of a dividend on the ordinary shares or in paying up in full unissued ordinary shares for allotment and distribution as bonus shares. Any such sums so deposited may be distributed in accordance with the manner of distribution of dividends as described above. Holders of shares are not subject to calls on capital by the company, provided that the amounts required to be paid on issue have been paid off. All shares are fully paid. Share transfers and share certificates The directors may permit transfers to be effected other than by an instrument in writing and that share certificates will not be required to be issued by the company if they are not required by law. The company may charge an administrative fee in the event that a shareholder wishes to replace two or more certificates representing shares with a single certificate or wishes to surrender a single certificate and replace it with two or more certificates. All certificates are sent at the member’s risk. 310 «See Glossary BP Annual Report and Form 20-F 2018 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 determined by the directors. If any shareholders’ meeting is adjourned for lack of quorum, notice of the time and place of the adjourned meeting may be given in any lawful manner, including electronically. Powers exist for action to be taken either before or at the meeting by authorized officers to ensure its orderly conduct and safety of those attending. The directors have power to convene a general meeting which is a hybrid meeting, that is to provide facilities for shareholders to attend a meeting which is being held at a physical place by electronic means as well (but not to convene a purely electronic meeting). The provisions of the Articles of Association in relation to satellite meetings permit facilities being provided by electronic means to allow those persons at each place to participate in the meeting. Limitations on voting and shareholding There are no limitations, either under the laws of the UK or under the company’s Articles of Association, restricting the right of non-resident or foreign owners to hold or vote BP ordinary or preference shares in the company other than limitations that would generally apply to all of the shareholders and limitations applicable to certain countries and persons subject to EU economic sanctions or those sanctions adopted by the UK government which implement resolutions of the Security Council of the United Nations. Disclosure of interests in shares The Act permits a public company to give notice to any person whom the company believes to be or, at any time during the three years prior to the issue of the notice, to have been interested in its voting shares requiring them to disclose certain information with respect to those interests. Failure to supply the information required may lead to disenfranchisement of the relevant shares and a prohibition on their transfer and receipt of dividends and other payments in respect of those shares and any new shares in the company issued in respect of those shares. In this context the term ‘interest’ is widely defined and will generally include an interest of any kind whatsoever in voting shares, including any interest of a holder of BP ADSs. BP Annual Report and Form 20-F 2018 «See Glossary 311 Called-up share capital Details of the allotted, called-up and fully-paid share capital at 31 December 2018 are set out in Financial statements – Note 31. In accordance with institutional investor guidelines, the company deems it appropriate to grant authority to the directors to allot shares and other securities and to disapply pre-emption rights by way of shareholders resolutions at each AGM in place of authority granted by virtue of the company's Articles of Association. At the AGM on 21 May 2018, authorization was given to the directors to allot shares in the company and to grant rights to subscribe for, or to convert any security into, shares in the company up to an aggregate nominal amount as set out in the Notice of Meeting 2018. These authorities were given for the period until the next AGM in 2019 or 21 August 2019, whichever is the earlier. These authorities are renewed annually at the AGM. Company records and service of notice In relation to notices not covered by the Act, the reference to notice by advertisement in a national newspaper also includes advertisements via other means such as a public announcement. Purchases of equity securities by the issuer and affiliated purchasers In November 2017 BP began a share repurchase or buyback programme (the programme). The sole purpose of the programme is to reduce the issued share capital of the company to offset the ongoing dilutive effect of scrip dividends over time, as announced by the company on 31 October 2017. Authorization for the programme was renewed at the company’s 2018 AGM covering the period until the date of the company's 2019 AGM. The maximum number of ordinary shares to be purchased will not exceed 1.99 billion ordinary shares, which is the maximum number of ordinary shares permitted to be purchased by the company pursuant to the authority granted by shareholders at the company's 2018 AGM . The shares purchased will be cancelled. The following table provides details of ordinary share purchases made (1) under the programme and (2) by the Employee Share Ownership Plans (ESOPs) and other purchases of ordinary shares and ADSs made to satisfy the requirements of certain employee share-based payment plans. 2018 January February 6 – February 28 March 8 – March 21 April May 1 – May 11 June 6 – June 27 July August 3 – August 30 September 4 – September 21 October November 1 – November 28 December 2019 January February 5 – February 21 March 11 Total number of shares purchaseda Average price paid per share $ Number of shares purchased by ESOPs or for certain employee share-based plansb Number of shares purchased as part of the buyback programmec Maximun approximate dollar value of shares yet to be purchased under the programme $ million Nil 12,574,000 5,500,000 Nil 7,765,798 3,230,500 Nil 6,788,050 12,497,354 Nil 2,603,190 Nil Nil 2,753,983 717,995 6.69 6.62 7.50 7.66 7.24 7.22 24,000 Nil 12,550,000 5,500,000 463,650 Nil 7,302,148 3,230,500 Nil Nil 6,788,050 12,497,354 6.84 269,000 2,334,190 7.10 7.14 120,000 Nil 2,633,983 717,995 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A a All share purchases were of ordinary shares of 25 cents each and/or ADSs (each representing six ordinary shares) and were on/open market transactions. b Transactions represent the purchase of ordinary shares by ESOPs and other purchases of ordinary shares and ADSs made to satisfy requirements of certain employee share-based payment plans. c The company announced its intent to commence the programme on 31 October 2017 and announced further details and commencement of the programme on 15 November 2017. At the AGM on 21 May 2018, authorization was given to the company to repurchase up to 1.99 billion ordinary shares, for the period ending on the date of the AGM in 2019 or 21 August 2019, whichever is the earlier. This authorization is renewed annually at the AGM. The total number of ordinary shares repurchased during 2018 under the programme was 50,202,242 at a cost of $355 million (including fees and stamp duty) representing 0.25% of BP’s issued share capital excluding shares held in treasury on 31 December 2018. All ordinary shares repurchased in 2018 under the programme were cancelled in order to reduce BP’s issued share capital. 312 «See Glossary BP Annual Report and Form 20-F 2018 Fees and charges payable by ADS holders The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of the distributable property to pay the fees. The charges of the Depositary payable by investors are as follows: Type of service Depositary actions Fee Depositing or substituting the underlying shares Selling or exercising rights 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. $5.00 per 100 ADSs (or portion thereof) evidenced by the new ADSs delivered. $5.00 per 100 ADSs (or portion thereof). Withdrawing an underlying share Acceptance of ADSs surrendered for withdrawal of deposited securities. $5.00 for each 100 ADSs (or portion thereof) evidenced by the ADSs surrendered. Expenses of the Depositary Dividend fees Expenses incurred on behalf of holders in connection with: • Stock transfer or other taxes and governmental charges. • Delivery by cable, telex, electronic and facsimile transmission. • Transfer or registration fees, if applicable, for the registration of transfers of underlying shares. • Expenses of the Depositary in connection with the conversion of foreign currency into US dollars (which are paid out of such foreign currency). ADS holders who receive a cash dividend are charged a fee which BP uses to offset the costs associated with administering the ADS programme. Global Invest Direct (GID) Plan New investors and existing ADS holders can buy or sell BP ADSs by enrolling in BP’s GID Plan, sponsored and administered by the Depositary. Expenses payable are subject to agreement between the company and the Depositary by billing holders or by deducting charges from one or more cash dividends or other cash distributions. The Deposit Agreement provides that a fee of $0.05 or less per ADS can be charged. The current fee is $0.02 per BP ADS per calendar year (equivalent to $0.005 per BP ADS per quarter per cash distribution). Cost per transaction is $2.00 for recurring, $2.00 for one-time automatic investments, and $5.00 for investment made by check, plus $0.12 commission per share. Documents on display BP Annual Report and Form 20-F 2018 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. The SEC maintains an internet site at http://www.sec.gov that contains reports and other information regarding issuers, including BP, that file electronically with the SEC. BP's SEC filings are also available at bp.com/sec. BP discloses in this report (see Corporate governance practices (Form 20-F Item 16G) on page 300) significant ways (if any) in which its corporate governance practices differ from those mandated for US companies under NYSE listing standards. 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 2018. The Depositary reimbursed to the company, or paid amounts on the company’s behalf to third parties, or waived its fees and expenses, of $16,582,418.54 for the year ended 31 December 2018. 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 2018. Category of expense reimbursed, waived or paid directly to third parties Amount reimbursed, waived or paid directly to third parties for the year ended 31 December 2018 $ Fees for delivery and surrender of BP ADSs Dividend feesa Total 647,683.39 15,934,735.15 16,582,418.54 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. BP Annual Report and Form 20-F 2018 «See Glossary 313 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, Link Asset Services The Registry, 34 Beckenham Road, Beckenham, Kent BR3 4TU, UK Freephone in UK 0800 701107 From outside the UK +44 (0)371 277 1014 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 2019 shareholder calendara 30 April 2019 First quarter results announced 10 May 2019 Record date (to be eligible for the first quarter interim dividend) 21 May 2019 Annual general meeting 21 Jun 2019 First quarter interim dividend payment for 2019 5 Jul 2019 8% and 9% preference shares record date 30 Jul 2019 Second quarter results announced 31 Jul 2019 8% and 9% preference shares dividend payment 9 Aug 2019 20 Sep 2019 Record date (to be eligible for the second quarter interim dividend) Second quarter interim dividend payment for 2019 29 Oct 2019 Third quarter results announced 8 Nov 2019 Record date (to be eligible for the third quarter interim dividend) 20 Dec 2019 Third quarter interim dividend payment for 2019 a All future dates are provisional and may be subject to change. For the full calendar see bp.com/financialcalendar. 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 4.3 Exhibit 4.4 Exhibit 4.7 Exhibit 4.10 Exhibit 8 Exhibit 11 Exhibit 12 Exhibit 13 Exhibit 15.1 Exhibit 15.2 Exhibit 15.3 Exhibit 15.4 Exhibit 15.5 Exhibit 15.6 Exhibit 15.7 Exhibit 15.8 Memorandum and Articles of Association of BP p.l.c.*******† The BP Executive Directors’ Incentive Plan******† 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*******† Subsidiaries (included as Note 37 to the Financial Statements) Code of Ethics*† Rule 13a – 14(a) Certifications† Rule 13a – 14(b) Certifications#† Consent of DeGolyer and MacNaughton† Report of DeGolyer and MacNaughton† Consent of Netherland, Sewell & Associates† Report of Netherland, Sewell & Associates† Consent Decree*******† Gulf states Settlement Agreement*******† Consent of Ernst & Young LLP† Consent of Deloitte LLP (included on page 127) Exhibit 101 Interactive data files * ** *** 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 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 BP p.l.c. and its subsidiaries under any one instrument does not exceed 10% of their total assets on a consolidated basis. The company agrees to furnish copies of any or all such instruments to the SEC on request. 314 «See Glossary BP Annual Report and Form 20-F 2018 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. b/d Barrels per day. boe/d Barrels of oil equivalent per day. 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 or Mb/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 or Mte Million tonnes. MteCO2 Million tonnes of CO2 equivalent. MW Megawatt. NGLs Natural gas liquids. PSA Production-sharing agreement. PTA Purified terephthalic acid. RC Replacement cost. SEC The United States Securities and Exchange Commission. Definitions Unless the context indicates otherwise, the definitions for the following glossary terms are given below. Non-GAAP measures are sometimes referred to as alternative performance measures. 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. A reconciliation to GAAP information is provided on page 320. We are unable to present reconciliations of forward-looking information for adjusted ETR to ETR on profit or loss for the period, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include the taxation on inventory holding gains and losses, non- operating items and fair value accounting effects, that are difficult to predict in advance in order to include in a GAAP estimate. 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 Total cash capital expenditure as stated in the group cash flow statement. 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 22 and in Downstream on page 28. 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. BP Annual Report and Form 20-F 2018 315 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. Divestment proceeds Disposal proceeds as per the group cash flow statement. Dividend yield Sum of the four quarterly dividends announced in respect of the year as a percentage of the year-end share price 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. A reconciliation to GAAP information is provided on page 320. 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 physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into. IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences. BP enters into contracts for pipelines and other transportation, storage capacity, oil and gas processing and liquefied natural gas (LNG) that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses. The way that BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. Under management’s internal measure of performance the inventory, transportation and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period. The fair values of derivative instruments used to risk manage certain oil, gas and other contracts, are deferred to match with the underlying exposure and the commodity contracts for business requirements are accounted for on an accruals basis. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole. A reconciliation to GAAP information is provided on page 320. 316 BP Annual Report and Form 20-F 2018 In addition, from 2018 fair value accounting effects include changes in the fair value of the near-term portions of LNG contracts that fall within BP’s risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments (used to risk manage the near-term portions of the LNG contracts) are fair valued under IFRS. The fair value accounting effect reduces timing differences between recognition of the derivative financial instruments used to risk manage the LNG contracts and the recognition of the LNG contracts themselves, which therefore gives a better representation of performance in each period. Comparative information has not been restated on the basis that the effect was not material. Free cash flow Operating cash flow less net cash used in investing activities, as presented in the group cash flow statement. Full dividend Full dividend is cash dividend plus cash equivalent value of scrip dividend. Gearing See Net debt and net debt ratio definition. Gross debt ratio Gross debt ratio is defined as the ratio of gross debt to the total of gross debt plus shareholders' equity. 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 and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in projects which expand the group’s activities through acquisition. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 275. Inventory holding gains and losses The difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. See Replacement cost (RC) profit or loss definition below. Joint arrangement An arrangement in which two or more parties have joint control. Joint control Contractually agreed sharing of control over an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Joint operation A joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. Joint venture A joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Liquids Comprises crude oil, condensate and natural gas liquids. For the Upstream segment, it also includes bitumen. LNG train An LNG train is a processing facility used to liquefy and purify natural gas in the formation of LNG. Major projects Have a BP net investment of at least $250 million, or are considered to be of strategic importance to BP or of a high degree of complexity. Net 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 27 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 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 276. BP Annual Report and Form 20-F 2018 317 Operating cash flow Net cash provided by (used in) operating activities as stated in the group cash flow statement. When used in the context of a segment rather than the group, the terms refer to the segment’s share thereof. Operating cash flow excluding Gulf of Mexico oil spill payments Non-GAAP measure. It is calculated by excluding post-tax operating cash flows relating to the Gulf of Mexico oil spill as reported in Financial statements – Note 2 from net cash provided by operating activities as reported in the group cash flow statement. BP believes net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill is a useful measure as it allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is net cash provided by operating activities. Organic free cash flow is operating cash flow excluding Gulf of Mexico oil spill payments less organic capital expenditure. Operating cash margin Operating cash margin is operating cash flow divided by the applicable number of barrels of oil equivalent produced, at $52/bbl flat oil prices. Expected operating cash margins are calculated over the period 2016-2025. 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 and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure less inorganic capital expenditure. BP believes that this measure provides useful information as it allows investors to understand how BP’s management invests funds in developing and maintaining the group’s assets. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 275. We are unable to present reconciliations of forward-looking information for organic capital expenditure to total cash capital expenditure, because without unreasonable efforts, we are unable to forecast accurately the adjusting item, inorganic capital expenditure, that is difficult to predict in advance in order to derive the nearest GAAP estimate. Organic sources of cash and organic uses of cash Non-GAAP measure. Organic sources of cash is the sum of operating cash flow, excluding Gulf of Mexico oil spill payments, and proceeds of loan repayments. Organic uses of cash is the sum of organic capital expenditure, dividends and share buybacks. The nearest equivalent measure on an IFRS basis for organic sources of cash is net cash provided by operating activities and the nearest equivalent measures on an IFRS basis for organic uses of cash are total cash capital expenditure, dividends paid to BP shareholders and net issue (repurchase) of shares. Production-sharing agreement (PSA) / Production-sharing contract An arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery. Readily marketable inventory (RMI) RMI is inventory held and price risk-managed by our integrated supply and trading function (IST) which could be sold to generate funds if required. It comprises oil and oil products for which liquid markets are available and excludes inventory which is required to meet operational requirements and other inventory which is not price risk-managed. RMI is reported at fair value. Inventory held by the Downstream fuels business for the purpose of sales and marketing, and all inventories relating to the lubricants and petrochemicals businesses, are not included in RMI. BP believes that disclosing the amounts of RMI and paid-up RMI is useful to investors as it enables them to better understand and evaluate the group’s inventories and liquidity position by enabling them to see the level of discretionary inventory held by IST and to see builds or releases of liquid trading inventory. Paid-up RMI excludes RMI which has not yet been paid for. For inventory that is held in storage, a first-in first-out (FIFO) approach is used to determine whether inventory has been paid for or not. Unpaid RMI is RMI which has not yet been paid for by BP. RMI, RMI at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided on page 322. 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. Refining net cash margin per barrel Refining 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. Refinery utilization Refinery utilization is calculated as annual throughput (thousands of barrels per day) divided by crude distillation capacity. 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. A reconciliation to GAAP information is provided on page 274. RC profit or loss per share Non-GAAP measure. Earnings per share is defined in Financial statements – Note 11. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the RC profit 318 BP Annual Report and Form 20-F 2018 or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 320. Reserves replacement ratio The extent to which the year’s production has been replaced by proved reserves added to our reserve base. The ratio is expressed in oil-equivalent terms and includes changes resulting from discoveries, improved recovery and extensions and revisions to previous estimates, but excludes changes resulting from acquisitions and disposals. Return on average capital employed Non-GAAP measure. Return on average capital employed (ROACE) is underlying replacement cost profit, after adding back non-controlling interest and interest expense net of tax (for the comparative periods interest expense was net of notional tax at an assumed 35%), divided by average capital employed, excluding cash and cash equivalents and goodwill. Interest expense is finance costs excluding the unwinding of the discount on provisions and other payables before tax. BP believes it is helpful to disclose the ROACE because this measure gives an indication of the company's capital efficiency. The nearest GAAP measures of the numerator and denominator are profit or loss for the period attributable to BP shareholders and average capital employed respectively. The reconciliation of the numerator and denominator is provided on page 321. 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, costly damage to equipment or exceeding defined quantities. 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. 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 acquisitions and divestments and entitlement impacts in our production-sharing agreements. Underlying RC profit or loss Non-GAAP measure. RC profit or loss after adjusting for non- operating items and fair value accounting effects. See page 276 and 320 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. Underlying profit in the group chief executive’s letter on page 8 refers to full year underlying RC profit for the group. A reconciliation to GAAP information is provided on page 274. Underlying replacement cost (RC) profit or loss per share Non-GAAP measure. Earnings per share is defined Financial statements – Note 11. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to BP shareholders rather than profit or loss attributable to BP shareholders. BP believes it is helpful to disclose the underlying RC profit or loss per share because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in BP’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to BP shareholders. A reconciliation to GAAP information is provided on page 320. Upstream plant reliability BP-operated Upstream plant reliability is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of Mexico weather related downtime. Upstream unit production cost Upstream unit production cost is calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for BP subsidiaries only and do not include BP’s share of equity- accounted entities. Wellwork Activities undertaken on previously completed wells with the primary objective to restore or increase production. West Texas Intermediate (WTI) A light sweet crude oil, priced at Cushing, Oklahoma, which serves as a benchmark price for purchases of oil in the US. Working capital Movements in inventories and other current and non-current assets and liabilities as stated in the group cash flow statement. Trade marks Trade marks of the BP group appear throughout this report. They include: ACTIVE, Aral, ARCO, BP, BPme, BP Ultimate, Castrol, Castrol EDGE BIO-SYNTHETIC, Castrol GTX ECO, Castrol Opitgear, PTAir Trade marks: Butamax – a registered trade mark of Butamax Advance Biofuels LLC. Fulcrum and Fulcrum BioEnergy – registered trade marks of Fulcrum BioEnergy, Inc. M&S Simply Food – a registered trade mark of Marks & Spencer plc. MyAuchan – a registered trade mark of Auchan. REWE to Go – a registered trade mark of REWE. BP Annual Report and Form 20-F 2018 319 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 316. Upstream Unrecognized (gains) losses brought forward from previous perioda Favourable (adverse) impact relative to management’s measure of performance Exchange translation gains (losses) on fair value accounting effects Unrecognized (gains) losses carried forward Downstreamb Unrecognized (gains) losses brought forward from previous perioda Favourable (adverse) impact relative to management’s measure of performance Unrecognized (gains) losses carried forward Favourable (adverse) impact relative to management’s measure of performance – by region Upstream US Non-US Downstreamb US Non-US Taxation credit (charge) 2018 2017 $ million 2016 (419) (39) 3 (455) (151) 95 (56) (35) (4) (39) (155) 250 95 56 12 68 (393) 27 2 (364) (71) (135) (206) 192 (165) 27 (29) (106) (135) (108) 12 (96) 263 (637) (19) (393) 377 (448) (71) (379) (258) (637) (321) (127) (448) (1,085) 329 (756) a 2018 brought forward fair value accounting effect balances include a $55-million adjustment between Upstream and Downstream as part of the transfer of the NGL business between segments. 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 2018 2017 14,367 (39) 14,328 6,845 95 6,940 19,322 56 19,378 5,194 27 5,221 7,356 (135) 7,221 9,582 (108) 9,474 $ million 2016 1,211 (637) 574 5,610 (448) 5,162 655 (1,085) (430) Reconciliation of basic earnings per ordinary share to RC profit (loss) per share and to underlying RC profit per share Profit (loss) for the yeara Inventory holding (gains) losses, before tax Taxation charge (credit) on inventory holding gains and losses RC profit (loss) for the year Net (favourable) adverse impact of non-operating items and fair value accounting effects, before tax Taxation charge (credit) on non-operating items and fair value accounting effects Underlying RC profit for the year a Profit attributable to BP shareholders. 2018 46.98 4.01 (0.99) 50.00 2017 17.20 (4.32) 1.14 14.02 Per ordinary share – cents 2016 0.61 (8.52) 2.58 (5.33) 2015 (35.39) 10.31 (3.10) (28.18) 2014 20.55 33.78 (10.43) 43.90 16.93 18.94 35.99 82.23 44.79 (3.23) 63.70 (1.65) 31.31 (16.87) 13.79 (21.83) 32.22 (22.69) 66.00 320 «See Glossary BP Annual Report and Form 20-F 2018 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 US tax reform 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 US tax reform Adjusted for the impact of the reduction in the rate of the UK North Sea supplementary charge Adjusted ETR 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 (2018 average $165,491 million) Less: Goodwill Cash and cash equivalents 2018 (7,145) 198 (7,343) 522 121 — 2017 (3,712) (225) (3,487) 1,184 (859) — (7,986) (3,812) 2018 2017 43 (1) 42 (5) 1 — 38 52 3 55 (9) (8) — 38 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 (947) 1,917 (2,864) 4,171 — — (2,313) (7,035) 2015 33 1 34 (15) — 12 31 % 2014 19 7 26 10 — — 36 2018 9,383 603 2,737 12,723 1,583 195 14,501 101,548 65,799 167,347 12,204 22,468 132,675 2017 2016 2015 3,389 (628) 3,405 6,166 924 79 7,169 100,404 63,230 163,634 11,551 25,586 126,497 115 (1,114) 3,584 2,585 635 57 3,277 96,843 58,300 155,143 11,194 23,484 120,465 (6,482) 1,320 11,067 5,905 576 82 6,563 98,387 53,168 151,555 11,627 26,389 113,539 $ million 2014 3,780 4,293 4,063 12,136 546 223 12,905 112,642 52,854 165,496 11,868 29,763 123,865 Average capital employed excluding goodwill and cash and cash equivalents ROACE 129,586 123,481 117,002 118,702 133,882 11.2 % 5.8% 2.8% 5.5% 9.6% a Calculated on a post-tax basis (for 2017 interest expense was net of notional tax at an assumed 35%). BP Annual Report and Form 20-F 2018 «See Glossary 321 Readily marketable inventory (RMI) Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by BP`s integrated supply and trading function (IST) which could be sold to generate funds if required. Details of RMI balances and a reconciliation to GAAP information is set out below. Further information on RMI, RMI at fair value, paid-up RMI and unpaid RMI is provided on page 318. At 31 December RMI at fair value Paid-up RMI Reconciliation of non-GAAP information At 31 December Reconciliation of total inventory to paid-up RMI Inventories as reported on the group balance sheet Less: (a) inventories which are not oil and oil products and (b) oil and oil product inventories which are not risk- managed by IST RMI on IFRS basis Plus: difference between RMI at fair value and RMI on an IFRS basis RMI at fair value Less: unpaid RMI at fair value Paid-up RMI 2018 4,202 1,641 $ million 2017 5,661 2,688 2018 $ million 2017 17,988 19,011 (14,066) (13,929) 3,922 280 4,202 (2,561) 1,641 5,082 579 5,661 (2,973) 2,688 The Directors’ report on pages 57-86, 110-111, 210-237 and 273-322 was approved by the board and signed on its behalf by Jens Bertelsen, company secretary on 29 March 2019. BP p.l.c. Registered in England and Wales No. 102498 322 «See Glossary BP Annual Report and Form 20-F 2018 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/ Jens Bertelsen Company secretary 29 March 2019 BP Annual Report and Form 20-F 2018 323 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 Page n/a n/a 274, 306 n/a n/a 55-56 2-3, 19-42, 151-160, 165, 168-170, 278-283, 291, 309 2-36, 43-54, 139, 156-159, 279-283, 291-296, 301 200, 325 21, 26-27, 36, 137, 165, 169-170, 235-237, 279-290, 300 None 16-17, 19-36, 55-56, 130, 133-150, 151-153, 156-159, 168-170, 179, 181-191, 275-277, 291-296, 298-299 16, 20, 132-133, 140, 165, 170-173, 179-185, 232-234, 277-278 9, 40, 44, 159 9-11, 18, 19-21, 25-27, 30 180-181, 277-278 278 303-304 58-67, 71 16-17, 87-109, 198 58-62, 68-86, 198 51, 199 51, 87-109, 172-178, 198-199 308-309 168-170, 300 n/a Consolidated statements and other financial information 126-128, 129-209, 296-298, 306 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 n/a 306 n/a 306 n/a n/a n/a n/a 309-312 300 306 306-308 n/a n/a 313 n/a 181-185 n/a n/a n/a 313 None None 126-127, 300-301 62, 75, 300 300 80, 199, 301 None 312 n/a 300 n/a 129-209 314 324 BP Annual Report and Form 20-F 2018 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 2018. A cross reference to Form 20-F requirements is included on page 324. This document contains the Strategic report on the inside front cover and pages 1-56 and the Directors’ report on pages 57-86, 110-111, 210-237 and 273-322. 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 87-109. The consolidated financial statements of the group are on pages 113-209 and the corresponding reports of the auditor are on pages 114-128. The parent company financial statements of BP p.l.c. are on pages 238 -271. The Directors’ statements (comprising the Statement of directors’ responsibilities; Risk management and internal control; Longer-term viability; Going concern; and Fair, balanced and understandable), the independent auditor’s report on the annual report and accounts to the members of BP p.l.c., the parent company financial statements of BP p.l.c. and corresponding auditor’s report and a non-GAAP measure of operating cash flow excluding Gulf of Mexico oil spill payments« in the tables on pages 13, 16, 19 and 20 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 2018 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 2018, 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, Advancing the energy transition, 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. In the US, the company’s securities are traded on the New York Stock Exchange (NYSE) in the form of ADSs (see page 306 for more details) and in Germany in the form of a global depositary certificate representing BP ordinary shares traded on the Frankfurt, Hamburg and Dusseldorf Stock Exchanges. The term ‘shareholder’ in this report means, unless the context otherwise requires, investors in the equity capital of BP p.l.c., both direct and indirect. As 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. Acknowledgements Design: SALTERBAXTER MSLGROUP Typesetting: BP and SALTERBAXTER MSLGROUP Printing: Pureprint Group Limited, UK, ISO 14001, FSC® certified and CarbonNeutral® Photography: Aaron Tait, Andrew Gombert, Arnhel De Serra, Bob Wheeler, Christopher Churchill, Graham Trott, Marc Morrison, Richard Davies, Rupert Warren, Stuart Conway, Yesenia Rodriguez Paper: This document is printed on Revive 100 Offset paper and board. Revive 100 Offset is paper from 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. BP Annual Report and Form 20-F 2018 «See Glossary 325   BP’s corporate reporting suite includes information about our financial and operating performance, sustainability performance and also on global energy trends and projections. Annual Report and Form 20-F 2018 Sustainability Report 2018 Details of our financial and operating performance in print and online. Details of our sustainability performance with additional information online. bp.com/annualreport bp.com/sustainability Advancing the energy transition How the energy world is changing, our low carbon ambitions and how we’re helping advance the transition. bp.com/energytransition Financial and Operating Information 2014-2018 Five-year financial and operating data in PDF and Excel format. bp.com/financialandoperating BP Energy Outlook Provides our projections of future energy trends and factors that could affect them out to 2040. bp.com/energyoutlook Statistical Review of World Energy 2019 An objective review of key global energy trends. bp.com/statisticalreview Technology Outlook BP social media How technology could influence the way we meet the energy challenge into the future. bp.com/technologyoutlook Join the conversation, get the latest news, see photos and films from the field and find out about working with us. 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@issuerdirect.com UK and rest of world BP Distribution Services Tel: +44 (0)870 241 3269 bpdistributionservices@ bp.com Feedback Your feedback is important to us. You can email the corporate reporting team at corporatereporting@bp.com 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 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 8 © BP p.l.c. 2019 

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