BP
Annual Report 2020

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 2 0 from IOC to IEC bp Annual Report and Form 20-F 2020 We have set our strategy to transform from an International Oil Company to an Integrated Energy Company focused on delivering solutions for customers. This is a major, necessary step in support of our purpose to reimagine energy for people and our planet, and our ambition to become a net zero company by 2050 or sooner and help the world get to net zero. After more than a century defined by oil and gas through two core businesses, upstream and downstream, we set our strategy to become a very different energy company in the next decade. This means we plan to Significantly scale-up our low carbon energy business Transform our customer mobility and convenience offer Focus our oil, gas and refining portfolio Drive down emissions as part of our net zero ambition We remain committed to delivering long-term value for stakeholders – including shareholders – through a compelling investor proposition. As we reinvent bp, we remain committed to performing while we transform, maintaining our focus on safety, operational excellence and financial discipline. About bp Through our scale, reach and range of activities we deliver heat, light and mobility products and services to customers around the world, and we plan to do so increasingly, in ways that we believe will help drive the transition to a lower carbon future. We have operations in Europe, North and South America, Australasia, Asia and Africa. ˜7% upstream unit production costs« reduction 2020 in numbers $20.3bn $5.7bn loss for the year attributable to bp shareholders underlying replacement cost loss« 94% 96% upstream plant reliability« refining availability« $12.2bn $5.5bn operating cash flow« divestment proceeds« $72.7bn finance debt $38.9bn net debt« 2.4mmboe/d 1,900 upstream production excluding Rosneft strategic convenience sites« 14.1GW total developed renewables to FID« and renewables pipeline« bp net 9% reduction in estimated emissions from the carbon in our Upstream oil and gas production« Our quick read provides a concise summary of the annual report, highlighting strategy, performance and sustainability information. Our reporting centre brings together all our key reports, including our sustainability report and energy outlook. Glossary Like any industry, ours has its own unique language. For that reason, words and terms marked with « are defined in the glossary. bp.com/annualreport bp.com/reportingcentre See page 341 Strategic report Strategic report Our purpose: reimagining energy Chairman’s letter Chief executive officer’s letter Energy markets Reinventing bp: Our strategy Our business model Our strategic focus areas Our financial frame and investor proposition Pursuing a strategy that is consistent with the Paris goals Our organizational model Our financial reporting segments Key performance indicators Group performance Sustainability Section 172 statement How we manage risk Risk factors Corporate governance Introduction from the chairman Board of directors Leadership team Board activities Decision making by the board How the board has engaged with shareholders, the workforce and other stakeholders Governance framework Learning, development and induction Board evaluation People and governance committee Audit committee Safety and sustainability committee Geopolitical committee Directors’ remuneration report Remuneration committee Directors’ statements Financial statements Consolidated financial statements of the bp group Notes on the financial statements Supplementary information on oil and natural gas (unaudited) Parent company financial statements of BP p.l.c. 2 4 6 8 15 16 18 22 26 36 38 39 42 48 63 64 67 72 74 78 80 82 86 88 90 91 92 94 100 102 103 105 127 129 160 231 259 301 Additional disclosures 331 Shareholder information Glossary 341 Non-GAAP measures reconciliations 348 350 Signatures 351 Cross-reference to Form 20-F 352 Information about this report 352 Exhibits bp Annual Report and Form 20-F 2020 01 Our ambition is to be a net zero company by 2050 or sooner and to help the world get to net zero. We’ve set out 10 net zero aims, five to help bp get to net zero and five to help the world get there too. Five aims to get bp to net zero Five aims to help the world get to net zero Our purpose for people and our planet. We want to help the world reach net zero and improve people’s lives. We will aim to dramatically reduce carbon in our operations and in our production, and grow new low carbon businesses, products and services. We will advocate for fundamental and rapid progress towards the Paris climate goals and aim to be an industry leader in the transparency of our reporting. We know we don’t have all the answers and will listen and work with others. We want to be an energy company with purpose; one that is trusted by society, valued by shareholders and motivating for everyone who works at bp. We believe we have the experience and expertise, the relationships and the reach, the skill and the will to do this. 02 bp Annual Report and Form 20-F 2020 Strategic report Our strategy is to become an Integrated Energy Company focused on delivering solutions for customers. We expect to be a very different bp by 2030 by implementing this strategy. To deliver our strategy we must operate within a resilient financial frame. We believe our strategy and financial frame support the delivery of our investor proposition. Strategic frame Financial frame Investor proposition Low carbon electricity and energy Convenience and mobility Resilient and focused hydrocarbons Integrating energy systems Partnering with countries, cities and industries Driving digital and innovation See page 15 for more information on our strategy. A sustainability frame linking our purpose and Our sustainability frame The sustainability frame we set out in September 2020 links our strategy to our purpose – to reimagine energy for people and planet. It focuses on three areas: net zero, people and planet. See page 48 for more information on our sustainability frame. A coherent approach to capital allocation 1 Resilient dividend 2 Strong balance sheet 3 Investing at scale in the energy transition 4 Investing to maximize value in resilient hydrocarbons 5 Share buyback commitment See page 22 for more information on our financial frame. Committed distributions Profitable growth Sustainable value See page 23 for more information on our investor proposition. E n g a g i n g stakeholders Our values and foundations E mbedding int o o u r D N A bp Annual Report and Form 20-F 2020 03 Chairman’s letter While this is a journey that will require patience, our goal is that bp over time will become a more valuable company for its shareholders and bring wider benefits for society. 7.9% annual dividend yield« ordinary share (2019 6.9%) $6.4bn total dividends distributed to bp shareholders (2019 $8.3bn) 04 bp Annual Report and Form 20-F 2020 Dear fellow shareholders, 2020: the year of the pandemic In every sense, 2020 was an extraordinary year. The worst pandemic in a century has cost well over 2 million lives and caused worldwide economic and social disruption. While vaccination programmes are now building momentum, the path to recovery remains uncertain. Because demand for energy is closely linked to human activity, our sector was deeply affected. The combination of a steep fall in share values for almost all oil and gas companies and a new bp distribution policy significantly affected your shareholder returns. As chairman of your board, I am conscious of my responsibilities to bp’s shareholders. When the board decided to reset our distribution policy, it did so with a view to your long-term interests. Our priorities were, and remain, weathering the immediate challenge of the pandemic; paying a resilient dividend; strengthening our balance sheet; investing into the energy transition; investing in our resilient hydrocarbons business and, after that, returning surplus cash« to shareholders through buybacks. The board was unanimous in its support for this course of action, which will help establish bp as an Integrated Energy Company. I hope that bp’s new investor proposition and financial frame give reasons for optimism about bp’s long-term prospects. As we turn to 2021, the board’s focus is on supporting bp’s leadership team to deliver our new strategy, and on building renewed shareholder confidence through strategic progress and operational and financial performance. 2020 was also tough for our people. My board colleagues and I are proud of them. Their commitment – on rigs, in refineries, across retail stations and everywhere else in bp – helped keep the world’s lights on and allowed us to provide many emergency services with free or heavily discounted fuel. Despite new COVID-19-related practical challenges, our people maintained the safety of bp’s operations. That is a testament to their careful work. bp’s new purpose 2020 was a remarkable year for bp for other reasons too. With the backing of the board, our new CEO, Bernard Looney, introduced a new company purpose: reimagining energy for people and our planet. That purpose – together with our strong culture and values – underpins the net zero ambition that we set out last year, together with our new strategy, financial frame and investor proposition. It also informed bp’s reinvention – the selection of a new leadership team, and the replacement of bp’s upstream/downstream model with a new, integrated group structure. Change of this scale necessitated a reorganization of how we work. That reorganization will ultimately see close to 10,000 colleagues leaving bp. Saying goodbye has been difficult, but the result is a leaner, flatter, nimbler company – better able to realize the opportunities of the energy transition. Macro-economic developments have only strengthened the board’s belief that the direction in which we are taking bp is the right one – including China’s new net zero target, the EU’s Green Deal, the UK’s plan for a green industrial revolution, and the US’s recommitment to the Paris Agreement. Today, global energy markets are even further down the path of fundamental change – and bp is well-positioned to help to speed the world’s journey to net zero. A year of engagement While this is a journey that will require patience, our goal is that bp over time will become a more valuable company for its shareholders and bring wider benefits for society. Of course, the journey to net zero is, in part, one of discovery. For that reason, the board and bp’s leadership team know that we must be fully open to advice, learning and challenge. 2020 was therefore a year of engagement with our stakeholders, and I am grateful for the inputs we received – which helped us shape our new strategy, financial frame and investor proposition, sustainability frame and position on biodiversity. We will keep listening, and we count on you to share your feedback with us as we travel the road to net zero together. Strategic report Evolution of the board As the company evolves, the board’s composition will evolve too – reflecting the need for new experiences and skills aligned with bp’s new direction. During the year, the board said goodbye to our former CEO, Bob Dudley, and to Brian Gilvary, our former CFO. Sir Ian Davis, Nils Andersen and Dame Alison Carnwath have also stepped down from the board, and we shall shortly say farewell to Brendan Nelson. Collectively and individually they served with distinction – bp is very fortunate to have had their wise advice and strong leadership. We are just as fortunate to welcome Tushar Morzaria, Karen Richardson and Johannes Teyssen to bp’s board for the first time. Closing thanks I would like to thank Bernard Looney, his leadership team and everyone in bp for their work during 2020. Throughout this challenging year, they showed characteristic determination. Finally, I thank you, our shareholders. I am grateful both for the continued support we received during 2020, and also for the support of our new shareholders. During 2020, we received investment and other endorsement from those who told us they would not have considered supporting bp were it not for the transformation we have begun. We look forward to repaying the faith you have placed in bp. Helge Lund, Chairman 22 March 2021 bp Annual Report and Form 20-F 2020 05 Chief executive officer’s letter 06 bp Annual Report and Form 20-F 2020 I want to pay particular tribute to those on the frontline of our business who have kept our plants and platforms running, our shops and forecourts open, and energy flowing to the world. Dear shareholders, The year 2020 will be remembered above all for the pain, sadness and loss of life caused by COVID-19. At bp, our thoughts are with the families and loved ones of the colleagues we have lost. Thousands more on our teams have had the virus, and life under lockdown has meant additional challenges, and anxiety for everyone. I want to pay particular tribute to those on the frontline of our business who have kept our plants and platforms running, our shops and forecourts open, and energy flowing to the world. They have sacrificed so much and earned our deepest respect and appreciation. Responding to brutal conditions We began our transformation from an International Oil Company to an Integrated Energy Company against this backdrop, along with lower oil and gas prices, lower refining margins and unprecedented falls in demand for our retail and aviation fuels. Our response included lowering costs, strengthening the balance sheet with an innovative hybrid bond issue, and advancing our strategy to become $20.3bn loss attributable to bp shareholders a more diversified, resilient and lower carbon company. As part of our strategy planning process, we reviewed our portfolio and development plans. This work – informed by bp’s views of the long-term price environment – led to significant impairment charges and non-cash exploration write-offs in the second quarter. For shareholders, all this was reflected in a reset dividend and a diminished share price. I recognize the financial impact this must have had on you. However, I wholeheartedly believe we will not just restore, but will enhance the long-term sustainable value of your company through the actions we are taking to reinvent bp. And despite the most brutal operating conditions I can remember in almost 30 years in this industry, we have made considerable operational and strategic progress. Performing while transforming The loss of $20.3 billion we reported for the year is clearly disappointing. However, it in no way reflects the heroic efforts of the bp team in extremely difficult circumstances, or their deep commitment to performing while transforming: Most importantly – our safety performance continued to improve. Reliability of 94% for bp’s operated plants« and refining availability« of 96% represents remarkably strong performance, especially given the challenges faced by our frontline staff. Capital was reset and we delivered at the lower end of the range. We made good progress towards our net debt« target, including the contribution from high grading our portfolio and $6.6 billion of divestment and other proceeds received during the year. New oil and gas production came on from four major projects« – in India, Oman, the UK and the US. Natural gas from the Shah Deniz field in the Caspian Sea arrived in Italy following final completion of the historic Southern Gas Corridor project. And we doubled our retail network in growth markets to around 2,700 retail sites«, plus the addition of around 300 strategic convenience sites«. Reinventing bp This performance is even more remarkable given that we have been carrying out the most extensive reorganization in bp’s 112-year history. We have retired the upstream/downstream business model that has served bp very well. In its place we have introduced a leaner, flatter structure, stripping away tiers of management and lowering the workforce towards a target of around 10,000 fewer jobs. My role is now five layers at most away from more than half of our employees. That means people’s ideas and voices can be more easily heard – and decisions taken much faster. We are now more centralized, more agile, and better integrated. This enables us to maximize value creation in a rapidly evolving market through economies of scale, and by exploiting synergies and driving continuous improvement in operational performance. We are now organized around four business groups. Production & operations is the operating heart of the company – and is focusing our resilient hydrocarbons portfolio on value. Customers & products is growing our convenience and mobility offers for an increasing number of customers. Gas & low carbon energy is growing to help meet rapidly increasing clean energy demand. Innovation & engineering acts as a catalyst, opening up new and disruptive business models and driving our digital transformation. And our trading & shipping business and regions, cities & solutions team knit together the offers of our four core groups to drive greater value creation. Reimagining energy Completing our transformation to a net zero Integrated Energy Company will take time. But we are led by our purpose – to reimagine energy for people and our planet – and motivated by the opportunity we see in the energy transition. Trillions of dollars of investment will be needed over the next 30 years in replumbing and rewiring the global energy system. We now have offshore wind partnerships in the US with Equinor and in the UK with EnBW – two of the best regions globally for the world’s fastest-growing source of energy. Our solar development joint venture«, Lightsource bp, is growing prolifically. We are working with Ørsted to develop green hydrogen for our Lingen refinery. We have joined forces with the mobility Strategic report platform DiDi to build a network of electric vehicle chargers in China, by far the world’s biggest market for EVs. And we have a growing list of low carbon partnerships with cities such as Aberdeen and Houston and some of the world’s leading companies, including Amazon, Microsoft, Qantas and Uber. A compelling investor proposition We are fully focused at all times on the bottom line of the business – on executing our strategy while operating safely, reliably and with discipline. We continue to build resilience and strength in the balance sheet as conditions remain challenging and uncertain while vaccines roll out, the pandemic recedes, and economies look to recover. At the same time, we are transforming to create value from the energy transition over the long term. We see tremendous business opportunity in providing people with the reliable, affordable, clean energy they want and need. Our net zero ambition is clearly the right thing for society, but we know it does not give us a free pass in a fast-changing world. We have to show you the evidence that we can compete fiercely and add value – in service of the compelling investor proposition we believe we offer: Committed distributions – including the dividend as the number one priority; Profitable growth; and Sustainable value. This is all in service of growing long-term shareholder value, that is our job. And I promise to keep you well informed as we execute our plans. As ever, thank you for your continued support – I will never take that for granted. And I look forward to any feedback you might have. Thank you. Bernard Looney, Chief executive officer 22 March 2021 bp Annual Report and Form 20-F 2020 07 Energy markets Global context The business environment is fundamentally changing. The world is on an unsustainable path and its carbon budget is running out. Energy markets have begun a process of significant, lasting change in response to this – shifting increasingly towards low carbon and renewables. And in 2020 we saw further changes, as COVID-19 spread across the globe. COVID-19 The COVID-19 pandemic has affected individuals, countries and businesses. The spread of the pandemic quickly plunged the world economy into recession and reshaped social norms and attitudes. Globally, businesses have had to change established assumptions and introduce new models and ways of working. For bp, it has had an adverse impact on our business, including on the demand for our products and on their prices. But the more we understand about the consequences for the global economy – and the inevitable uncertainty it brings – the more convinced we are that our ambition and strategy are taking us in the right direction for bp, for our employees, our shareholders and society. Impact on the economy The global economy is estimated to have contracted 4.3% in 2020, the steepest decline in economic activity since 1946, caused by COVID-19. In advanced economies the recovery from the initial contraction was dampened by resurgences of COVID-19 cases, leading to an annual contraction of 5.4%. Most emerging markets, excluding China, also experienced deep recessions, with growth of -5% in 2020, while in China the economy grew by 2%a. a World Bank Global Economic Prospects, January 2021. Our response As COVID-19 continues to affect communities around the world, we have focused our effort on three priorities. 1 Protecting our people. 2 Supporting communities where we live and work. 3 Strengthening our finances. Our leadership teams were in daily discussions to respond to the conditions in the countries where we operate as the pandemic unfolded. We had a three-tier response model with executive-level, business, country and incident management steering committees. Some examples are given on the next page. Mobilizing safely in the North Sea In 2020 bp managed more than 15,000 journeys by people mobilizing to and from our North Sea assets. As the COVID-19 pandemic took hold in the UK, the bp North Sea team quickly implemented wide-ranging and robust COVID-19-specific measures to protect the safety and wellbeing of offshore colleagues. The ‘Safe Passage’ programme was introduced during the first UK lockdown to help individuals travel to Aberdeen for mobilization as safely as possible. The programme provided door-to-door transport, accommodation during the journey to Aberdeen and hotels in the city dedicated to bp staff and contractors. We introduced pre-mobilization COVID-19 testing in Aberdeen, one of the first operators in the North Sea to do this. Social distancing and enhanced hygiene and cleaning regimes continue to play a vital role in protecting the health and wellbeing of our offshore teams. Specialist ‘C-MED’ medevac helicopters, equipped with an on-board medic and configured to enable social distancing, were introduced to safely transport individuals suspected of contracting the virus back to shore for further treatment and support. 08 bp Annual Report and Form 20-F 2020 1 Protecting our people Our first priority is the safety and health of our people. Our people involved in, or supporting, critical operations continued at their normal workplace during the pandemic and we put additional processes in place to help protect them. These included operating robust protocols for health and pre-mobilization checks, PPE, travel and workplace access, social distancing and isolation. Employees who were able to work from home were asked not to come into their workplace and we put business travel restrictions in place. Many office-based workers continue to work from home at the time of publication and are likely to do so for the foreseeable future as ways of working change. We liaised closely with industry peers and other organizations to regularly test our approach on specific safety issues. And we created a global COVID-19 OneMap, providing our businesses with current local COVID-19 risk profiles including rates of infection, vaccines rates and procurement. 2 Supporting communities Providing essential support for the communities where our people live and our businesses operate was a priority throughout our response to COVID-19. We offered support to governments and partners, using our expertise and resources to support the relief effort. The bp Foundation donated $2 million to the World Health Organization’s COVID-19 Solidarity Response Fund, which supports medical professionals and patients worldwide by providing critical aid and supplies. The fund also helps track and understand the spread of COVID-19 and supports efforts to develop tests, treatments and vaccines. 3 Strengthening our finances The economic consequences of COVID-19 for the world remain uncertain at the time of publication. In response to this uncertainty, we took deliberate steps to strengthen our finances – reinforcing liquidity, rapidly reducing spending and costs, driving our cash balance point lower. Divestment programme We delivered our plans for $15 billion of announced divestments, which commenced at the start of 2019, in June 2020 – a year earlier than expected. Supplying free fuel for emergency services vehicles In 2020 we supplied more than 10 million litres of free fuel to emergency service vehicles across the UK. We ran programmes during 2020 and 2021 offering free fuel to UK emergency vehicles – including police, fire, blood transportation, emergency NHS ambulances and NHS Trust non-emergency vehicles. Under the programmes, emergency services vehicles issued with either a bp Plus or Allstar fuel card could fill up without charge at bp’s network of 1,200 retail sites across the UK, including charging of electric vehicles through bp pulse. In 2020 we set a new target of $25 billion of proceeds between the second half of 2020 and 2025, of which we’ve completed or agreed transactions for over half of this target. This includes the agreed sale of a 20% interest in Oman’s Block 61 and proceeds from the divestments of our petrochemicals business and Alaska interests. We have a deep hopper of potential future divestment options. As we execute this programme, we will continue to be focused on value. Capital expenditure Capital expenditure« for 2020 was $14 billion, around 28% lower than 2019. Organic capital expenditure« for 2020 was $12 billion, in line with the guidance given in April. Liquidity Finance debt was $72.7 billion and net debt« was $38.9 billion at the end of 2020. We are actively managing the profile of our debt portfolio. We issued perpetual hybrid bonds with a US dollar equivalent value of $11.9 billion in June 2020, and we bought back an aggregate US dollar equivalent value of $8 billion of debt in the third quarter of 2020, January 2021 and March 2021. bp had around $44 billion of liquidity, consisting of cash and cash equivalents (net of restricted cash) plus undrawn revolving credit facilities committed credit and bank facilities, at the end of 2020. In April 2020 Moody’s reaffirmed BP p.l.c.’s A1 credit rating and revised its outlook from stable to negative. The short-term P-1 rating was also reaffirmed. Strategic report In January 2021 S&P revised its outlook on BP p.l.c. from stable to negative and affirmed BP p.l.c.’s long- and short-term corporate credit rating of A-/A-2. From January 2021, Fitch Ratings has provided a solicited long-term corporate credit rating to BP p.l.c. of A with stable outlook. In February 2021, Fitch Ratings assigned BP p.l.c. a short-term corporate credit rating of F1. bp’s financial performance, including cash flows and net debt, has been and will continue to be impacted by the extent and duration of the current market conditions and the effectiveness of the actions that it and others take, including its financial interventions. It is difficult to predict when current supply and demand imbalances will be resolved and what the ultimate impact of COVID-19 will be. See page 22 for more information on capital allocation. We have addressed our response to COVID-19 in further detail throughout this report: See page 63 Our stakeholders. See page 64 How we manage risk. See page 67 Risk factors. See page 87 Workforce engagement. bp Annual Report and Form 20-F 2020 09 Energy markets continued Energy economics Oil The COVID-19 pandemic resulted in a sharp contraction in oil sector demand and production in 2020. Global oil consumptiona decreased by 8.8mmb/d to 91.2mmb/d for the year (-8.8%) as global lockdown measures reduced mobility and took a toll on economic activity. On the supply side, unprecedented co-ordinated output cuts from OPEC+, coupled with curtailed non-OPEC supply, reduced global oil productiona by 6.6mmb/d to 93.9mmb/d. Dated Brent« prices averaged $41.84/bbl in 2020 – a 35% decrease from 2019 levels and almost 26% below the 2016-18 average. Prices fluctuated during 2020, reaching a peak of almost $70/bbl in January on OPEC+ supply restraints and the decline in Libyan output. Prices hit a low of almost $13/bbl in April as lockdown measures were put in place globally. In the second half of the year prices hovered around the $40-45/bbl range, before hitting $50/bbl in December. Urals prices in North West Europe (Rotterdam) averaged $41.71/bbl in 2020. The discount to dated Brent was $0.13/bbl below 2019 ($1.25/bbl). 8.8% decrease in global oil consumption in 2020 Natural gas Gas spot prices dropped in all three key regional markets in 2020. Refining marker margin We track the refining margin environment using a global refining marker margin« (RMM)c. Henry Hub« prices decreased to $2.08/ mmBtu in 2020 from $2.63/mmBtu in 2019. US gas prices varied substantially during 2020, dropping in the second quarter of 2020 due to the impact of the lockdown, before recovering in the fourth quarter as production declined due to the earlier oil price drop and lower oil and gas drilling activityb. The UK National Balancing Point« hub price also dropped significantly from 34.70 pence per therm in 2019, down to 24.93 pence per therm in 2020, due to a combination of a mild winter 2019/20, global LNG oversupply, demand drop and record-high storage levelsb. Asian spot prices declined from $5.49/mmBtu in 2019, down to $4.39/mmBtu on the back of global LNG oversupply and LNG supply capacity growth, especially in the USc. They recovered in the fourth quarter on the back of strong Asian LNG demand and LNG supply issues. Global gas demand dropped by an estimated 2.5% in 2020, while China’s gas demand continued to grow. Meanwhile, LNG trade increased modestly during 2020b. 2.5% estimated decrease in global gas demand in 2020 COVID-19 significantly impacted the downstream sector during 2020. Weaker demand drove product stocks to record highs. OECD commercial product stocks peaked in August at over 1,650Mbbls, almost 150Mbbls higher than a year ago. Since then stocks have declined but are still above historical levels. In 2020 COVID-19 impacted demand through different channels. During the initial global lockdown period, the drop in demand was concentrated in road and air travel – hitting gasoline and jet fuel the hardest. As more measured domestic social distancing policies evolved, road mobility and hence gasoline demand recovered, while jet demand remained depressed. The broader negative impact on the economy also dampened diesel demand given the close link between commercial and industrial diesel uses and economic activity. The resulting refining margins have, therefore, remained extremely weak since the beginning of the pandemic, with RMM averaging $6.7/bbl in 2020, far lower than the level in 2019 ($13.2/bbl). Moreover, the weak margin environment combined with continued capacity additions in developing markets has prompted a raft of third-party closure announcements. Some industry rationalization is expected given the step change in demand, but this is not likely to be sufficient to see a sustained rebound in margins to pre-COVID-19 levels. $6.7/bbl global RMM average in 2020 a IEA Oil Market Report, January 2021©. b Platts 2020 Review and 2021 Outlook, and IHS Markit: Waterborne LNG Export-Import Data Tables. c The RMM may not be representative of the margin achieved by bp in any period because of bp’s particular refinery configurations and crude and product slates. In addition, the RMM does not include estimates of energy or other variable costs. 10 bp Annual Report and Form 20-F 2020 Strategic report Our Energy Outlook Our bp Energy Outlook considers three main scenarios that explore the possible pathways the energy transition may take over the next 30 years. The uncertainty is substantial and these scenarios are not predictions of what is likely to happen or what bp would like to happen. Rather they explore the possible implications of different judgements and assumptions concerning the nature of the energy transition. Three scenarios to explore the energy transition Rapid Net Zero Business-as-usual One of many possible scenarios that can be considered ‘consistent with Paris’, in line with a ‘well below 2 degrees’ pathwaya. In this scenario emissions from energy use fall by around 70%, with a fall of approximately 80% in the developed world and 65% in the emerging world. In which global energy systems emissions fall by 95% by 2050 versus 2018, in line with a ‘1.5 degrees’ pathwaya. Changes in societal actions and behaviours are a key driver in this scenario. A continuation of recent trends without major change in the pace or direction of policy tightening; this scenario is not ‘consistent with Paris’ and results in a reduction in global energy greenhouse gas emissions of only 10% by 2050 versus 2018. CO2 emissions from energy use Gt of CO2 40 35 30 25 20 15 10 5 0 -5 1980 1990 2000 2010 2020 2030 2040 2050 History Rapid Net Zero Business-as-usual IPCC 2 Median IPCC 1.5 Median This chart compares the three main scenarios from the bp Energy Outlook 2020: Rapid, Net Zero and Business-as-usual, with the range of scenarios included in the Intergovernmental Panel on Climate Changeb, which were judged to be consistent with meeting the Paris climate goalsc. Well below 2ºC 1.5ºC Scenarios for strategic decision making We have been using scenarios at bp to inform strategy, manage risk and improve decision making for many years. The scenarios we used to inform our new ambition and strategy were based on a collaborative approach between our economists, strategists and our senior management team. a For more information on Paris-consistent pathways, see page 26. b The Intergovernmental Panel on Climate Change (IPCC) is the United Nations’ body for assessing the science related to climate change. It is the leading source of data that summarizes the potential pathways to achieve the Paris goals. The IPCC compiles a database of the published results on mitigation pathways from modelling teams around the world. c Ranges show 10th and 90th percentiles of IPCC scenarios. See bp Energy Outlook 2020 for more information. bp Annual Report and Form 20-F 2020 11 Energy markets continued Some scenarios start from today and project forward over a timeframe in which the current structure of the energy system helps to inform the pace and nature of the transition path. Other scenarios start in the distant future, breaking free from the inherent inertia in the energy system (and potentially our thinking), and look back to the present from that new perspective. In thinking about appropriate scenarios to inform our new strategy, we used both approaches. The scenarios chosen to explore the range of uncertainty surrounding the future of the global energy system span a broad range of energy transition paths. Importantly, the scenarios are not predictions of what is likely to happen or what bp would like to happen. Rather they consider the possible implications of different judgements and assumptions and so help to design a strategy which is resilient to the wide range of uncertainty we face. By considering various time horizons, we can identify key milestones or signposts which might emerge over the next five, 10 or 30 years and inform our view of the key sources of uncertainty affecting the global energy system. We actively monitor for changes in the external environment, and refresh or review our scenarios as needed in response to these signals. How we create scenarios We quantify these scenarios in the bp Energy Outlook 2020 using our global energy modelling system. This comprises of a suite of models developed over the past 10 years to help us understand supply and demand dynamics of the global energy system. The modelling framework uses historical data based on the bp Statistical Review of World Energy, IEA energy balances and a range of other energy and non-energy data sets. The model combines supply, end-use demand, and production in intermediate sectors, including power and hydrogen, to create global energy outlooks. Each scenario is determined by a set of key assumptions including population and economic growth, pace of technological change, resource constraints and government policies. Prices are used to balance supply and demand. The modelling techniques used vary by sector and include a combination of econometric modelling, least-cost optimization, adoption curves and consumer choice modelling. The regional coverage varies by sector but at its most aggregated the model produces views for 14 regions, across six sectors, more than 20 energy and technology sources and associated CO2 emissions from each. It produces annual data out to 2050. Scenarios are generated based on our own judgements alongside views from external organizations. For example, population growth from the United Nations, economic growth supported by views from Oxford Economics, resource availability based on Rystad Energy’s global upstream database, power modelling informed by Aurora Energy Research and global system dynamics based on a proprietary TIMES integrated assessment model. All scenarios typically take into account historical evidence, current policies, user judgement and specialist projections. In developing the scenarios, we benchmark our views against scenarios from external organizations including from the Intergovernmental Panel on Climate Change’s (IPPC) 2019 Special Report on Global Warming of 1.5°C, IEA’s World Energy Outlook 2020 and IHS Markit’s Energy and Climate Scenarios. How scenarios inform our strategy The scenarios described in the bp Energy Outlook 2020 helped inform bp’s strategy process, alongside a wide range of other analyses and information. As we developed the strategy, the scenarios were reviewed and refined to ensure they remained relevant, for example, they were completely refreshed to account for the possible implications of COVID-19, and they remained challenging for example, by including a scenario in which global emissions from energy reach near zero by 2050. The aim of the scenarios is to aid our understanding of how the pace and nature of the energy transition may affect the global energy system and so help our strategy be robust and resilient to the range of uncertainty we face. Given that, we believe that it is neither useful nor sensible to try to identify one scenario as being more or less likely than another. 12 bp Annual Report and Form 20-F 2020 In the bp Energy Outlook 2020, COVID-19 is assumed to have a persistent impact on economic activity and energy demand. Strategic report Global energy demand across the scenarios Although the three energy outlook scenarios differ in many respects, some trends are common across them and across the wide range of other analyses and information we refer to. Global energy demand continues to grow, at least for a period, driven by increasing prosperity and living standards in the emerging world, and there are three common trends in how the structure of energy demand changes over time. Importance of fossil fuels declines The share of fossil fuels in global primary energy falls from around 85% in 2018 to between 65% and 20% by 2050 in the three scenarios. World continues to electrify The rapid growth in renewables is supported by the increasing role of electricity in total final energy consumption in the three scenarios. Rapid growth in renewable energy Increases in renewable energy dominate growth in primary energy, with its share increasing from 5% in 2018 to between 20% and 60% by 2050 in the three scenarios. Shares of primary energy Shares of total final comsumption Shares of primary energy 100% 80% 60% 40% 20% 0% 100% 80% 60% 40% 20% 0% 100% 80% 60% 40% 20% 0% 2018 2025 2030 2035 2040 2045 2050 2018 2025 2030 2035 2040 2045 2050 2018 2025 2030 2035 2040 2045 2050 Rapid Net Zero Business-as-usual Rapid Net Zero Business-as-usual Rapid Net Zero Business-as-usual Changing structure of the global energy system In addition to the changing structure of energy demand, the scenarios also highlight how global markets may change if and when there is a transition to a lower carbon energy system, with a more diverse energy mix, greater consumer choice, more localized energy markets, and increasing levels of integration and competition. Share of primary energy in Rapid 100% 80% 60% 40% 20% 0% 1900 1915 1930 1945 1960 1975 1990 2005 2020 2035 2050 Oil Coal Natural gas Other non-fossil fuels Renewables bp Annual Report and Form 20-F 2020 13 Energy markets continued Our beliefs on the energy transition Three features are common across our Energy Outlook scenarios and they form a set of three core beliefs as to how energy demand is likely to change over the next three decades. The world will electrify, with renewables a clear winner Customers will redefine convenience and mobility, driven by electrification, digital and fleets Oil and gas challenged but will remain part of the energy mix for decades And those core beliefs lead to three more about how the energy system will have to change in response to evolving demand, out to 2050. Energy systems will become increasingly multi-technology, integrated and local Customers – countries, cities, industries and corporates – will demand bespoke energy solutions Digital will continue to transform our lives – creating opportunities to drive innovation, unlock value and engage new customers and markets These core beliefs underpin our new strategy. bp.com/energyoutlook 14 bp Annual Report and Form 20-F 2020 Reinventing bp: our strategy Our strategy An Integrated Energy Company delivering solutions for customers. Focuses on three areas of activity: low carbon electricity and energy, convenience and mobility, and resilient and focused hydrocarbons. Each focus area represents an attractive opportunity in its own right. Taken individually, they are not unique to bp. But we plan to leverage three sources of differentiation to help us amplify value: integrating energy systems, partnering with countries, cities and industries, and driving digital and innovation. Strategic report From IOC to IEC We began 2020 operating under our previous strategy, announced in 2017, which focused on four strategic priorities: Growing advantaged oil and gas in the Upstream. Market-led growth in the Downstream. Venturing and low carbon across multiple fronts. Modernizing the whole group. In February 2020, we announced our new ambition to be a net zero company by 2050 or sooner and to help the world get to net zero. And in August we announced a new strategy to get us there, which builds on the foundations we’ve developed since 2017. By following this strategy, we expect bp to be a very different energy company by 2030. Low carbon electricity and energy Convenience and mobility Resilient and focused hydrocarbons Integrating energy systems Partnering with countries, cities and industries Driving digital and innovation Our strategy is underpinned by our new sustainability frame and by advocating for policies that support net zero. A sustainability frame linking our purpose and See page 48 for more about our sustainability frame. bp Annual Report and Form 20-F 2020 15 Reinventing bp – our business model Delivering value for bp, our shareholders and society Business model inputs Skills in the world of energy, built up over more than 110 years. Understanding of energy markets and how they move. Thousands of expert scientists, engineers and technologists. People with outstanding capabilities in trading, shipping, marketing and innovation. Strong relationships with leading companies, universities and governments. Thriving energy transition, convenience and mobility partnerships and businesses that we are growing all over the world. A resilient financial frame and a disciplined approach to capital allocation. Strategic activities Low carbon electricity and energy Convenience and mobility Through our gas & low carbon energy business, we aim to grow scale. Our low carbon businesses are complemented by integrated gas, which has an important role in the energy transition. Our customers & products business group is an integral part of our growth and returns strategy. We aim to put customers at the heart of everything we do. How we aim to create value Growing our renewables portfolio, including offshore wind and solar. Building an integrated low carbon electricity position in select developed and emerging markets. Growing our integrated gas position, building on our high-value equity upstream gas, our LNG portfolio« and our marketing capability. Scaling our bioenergy business, focusing on biofuels, biogas and biopower. Accelerating to take early positions in hydrogen and carbon capture, use and storage. Expanding and scaling our differentiated fuels and lubricants offers in growth markets (see page 24), aiming to help shape these markets over time to lean into the transition to low carbon mobility. Redefining convenience through partnerships with some of the world’s leading brands and continuing to develop innovative offers, making buying our retail goods and fuels even more convenient for customers. Developing next-gen mobility solutions, including electrification, sustainable fuels and hydrogen. Safety is our core value. It underpins our business model and permeates everything we do. See page 59 for our safety performance in 2020. 16 bp Annual Report and Form 20-F 2020 Resilient and focused hydrocarbons Through our production & operations business, we aim to produce the affordable hydrocarbon energy and products the world needs, and generate cash to fund our operations and our transformation to an Integrated Energy Company. Always putting safety first. Aiming to eliminate life-changing injuries and the most serious process safety events. Reducing emissions, aligned with our aims, while delivering the energy the world needs. Transforming operations and improving efficiency. Maintaining a resilient portfolio through investment efficiency and high grading. Flexibly deploying talent to our most valuable opportunities and to solve our biggest issues. Reinventing our business model As we transition from an International Oil Company to an Integrated Energy Company, we are reinventing our old business model, which comprised three main activities: Finding and generating energy. Refining, manufacturing and marketing. Delivering products and services. Sources of differentiation Integrating energy systems We are focused on driving integration in everything we do. Through integration we bring everything together, to create end-to-end solutions for our customers. 214TWh traded electricity in 2020 Partnering with countries, cities and industries By leveraging relationships and building new partnerships we aim to provide integrated energy and mobility solutions to help cities and industries reduce carbon emissions while creating exciting business opportunities. 10-15 city partners aim by 2030 Driving digital and innovation We innovate with a strong focus on digital to drive operational efficiencies, enable our workforce and engage better with our customers. This includes building new businesses through bp ventures and Launchpad. 38 bp ventures and Launchpad businesses in total Strategic report Our new business model is more integrated and faces the energy transition head on. We believe it can deliver for the changing demands of stakeholders, with an absolute focus on operational excellence, so that our businesses are safe, reliable and efficient. Delivering value for our stakeholders Employees Investors Society Suppliers and partners Customers Governments and regulators By delivering value to our stakeholders we can achieve our purpose. for people and our planet. See page 36 for details of our organizational model. bp Annual Report and Form 20-F 2020 17 Reinventing bp – our strategic focus areas Strategic focus areas Metrics We aim to grow our renewables and bioenergy businesses, seek early positions in hydrogen and carbon capture utilization and storage and strengthen our gas position. These activities form an integrated low carbon portfolio that will help transform bp as we transition from an International Oil Company to an Integrated Energy Company. See page 20 for an example of our strategy in action. In order to advance our purpose and ambition, we have identified three strategic focus areas, and we’ve set targets and aims against these out to 2025 and 2030. These provide the basis for a common set of enduring objectives for bp as we transform the organization consistent with the long-term energy transition. Some examples of how we performed in 2020 are also set out here. As we deliver our strategy, we will focus on maximizing value through operational and commercial excellence, see pages 36-38 for more information. We will continue to focus on customers and respond to their changing needs. We aim to redefine convenience and scale up our differentiated offers in growth markets and next-gen mobility solutions, including electrification, sustainable fuels and hydrogen. Developed renewables to final investment decision« Bioenergy production« LNG portfolio« Traded electricity« Customer touchpoints« Strategic convenience sitesb« Retail sites in growth marketsb« Castrol sales and other operating revenues« Electric vehicle charge pointsa« See page 24 for an example of our strategy in action. Margin share from convenience and electrificationb« Unit production costs« Upstream productionc Upstream plant reliability« Refining throughput Refining availability« Our hydrocarbons business is essential to our transformation to an Integrated Energy Company. The cash flow from our oil, gas and refining activities enable our strategy, allowing us to invest in the energy transition and support our two growth areas – low carbon electricity and energy, and convenience and mobility. See page 34 for an example of our strategy in action. 18 bp Annual Report and Form 20-F 2020 2020 3.3GW 2019 2.6GW 30Kb/d 2019 23Kb/d 20Mtpa 2019 15Mtpa 214TWh 2019 250TWh 2025 20GW 2030 50GW 50Kb/d >100Kb/d 25Mtpa 30Mtpa 350TWh 500TWh 11.5 million 2019 >10 million >15 million >20 million 1,900 2019 1,600 2,700 2019 1,300 $5.4bn 2019 >$6.5bn 10,100 2019 >7,500 27.6% 2019 ~25% >2,300 >3,000 7,000 >8,000 ~$7.5bn >$8bn >25,000 >70,000 ~35% ~50% $6.39/boe 2019 $6.84/boe ~$6/boe 2.4mmboe/d 2019 2.6mmboe/d ~2mmboe/d ~1.5mmboe/d 94% 2019 94.4% 1.6mmb/d 2019 1.7mmb/d 96% 2019 94.9% 96% >96% <1.5mmb/d ~1.2mmb/d 96% >96% Strategic report Performing while transforming bp and Equinor strategic US offshore wind partnership, see page 20. Partnered with Microsoft to progress our respective sustainability aims, including plans to supply Microsoft with renewable energy and extend its cloud-based services within bp. Lightsource bp, in which we have a 50% share, has more than doubled its global presence from five to 14 countries and grown its development pipeline from 1.6GW to 17GW, since joining with bp in 2016. Formed the Northern Endurance Partnership, with five energy companies, to develop the offshore infrastructure to transport and store millions of tonnes of carbon dioxide emissions safely in the UK North Sea. Partnered with Ørsted and plan to develop an industrial-scale project to produce hydrogen from water, powered by wind. Joined with Aberdeen City Council to help achieve its net zero vision to reduce carbon emissions and become a climate-positive city. Agreed to extend our relationship with Amazon, to supply additional renewable energy to power its operations, and Amazon Web Services, enabling the acceleration of bp’s programme to digitize its infrastructure and operations. More than doubled retail sites in growth markets to 2,700. Added ~300 strategic convenience sites across our retail network, bringing the total to 1,900. Announced the start of our new mobility joint venture« in India with Reliance, Jio-bp, see page 24. Increased the number of electric vehicle charge points to 10,100 and began the rollout of ultrafast charging points across the UK and Germany. Rolled out 1,400 electric vehicle charge points as part of our joint venture with DiDi in China. Increased margin share from convenience and electrification to 27.6%. a Reported to the nearest 100. b The nearest GAAP measures of the numerator and denominator are RC profit before interest and tax for Downstream. A reconciliation to GAAP information is provided on page 318. We’re on track to deliver on our growth target since 2016 of 900mboe/d from new major projects« by the end of 2021, with 700mboe/d of production capacity on line by the end of 2020. And we started up four major projects: Atlantis in the Gulf of Mexico, see page 34, Ghazeer in Oman, Vorlich in the North Sea, and KG D6 R Cluster in India. Completed the Southern Gas Corridor pipeline system, with the Trans Adriatic pipeline beginning gas deliveries. Tested the green completions concept on our Ghazeer wells, sending hydrocarbons to a production facility instead of flaring them. Sold our petrochemicals business to INEOS. Ceased fuel production at our Kwinana refinery to convert it into an import terminal. Agreed to sell a 20% interest in Oman’s Block 61. c Relative to 2019, we expect our hydrocarbon production to be around 40% lower by 2030 reflecting active management and high-grading of the portfolio, including divestment of non-core assets. We will not undertake exploration activity in new countries. bp Annual Report and Form 20-F 2020 19 Reinventing bp – our strategy in action 20 bp Annual Report and Form 20-F 2020 Strategic report Low carbon electricity and energy We’re teaming up with Equinor to form a new strategic partnership to develop offshore wind projects in the US. We believe we can achieve more together, working to become leaders in the fastest-growing renewables sector and helping the world get to net zero. Why offshore wind? Offshore wind is growing at around 20% a year globally and is recognized as a core part of reducing global emissions. This was bp’s first ever offshore wind venture and marks an important step in the delivery of our strategy to rapidly grow our renewable electricity and energy portfolio. Building on this progress in 2021, bp and Energie Baden-Wuerttemberg AG (EnBW) were selected as the preferred bidder for two major leases in the UK Offshore Wind Round 4, marking our entry into the largest offshore wind power sector in the world. Our partnership with Equinor will play a vital role in allowing us to deliver our aim of rapidly scaling up our renewable energy capacity, and in doing so help deliver the energy the world wants and needs. Dev Sanyal EVP, gas & low carbon energy What we’re doing The partnership includes development of four assets in two existing offshore wind leases on the US East Coast. And we expect to pursue further opportunities for offshore wind in the US. We’re investing $1.1 billion for a 50% share in two leases: Empire Wind and Beacon Wind. Empire Wind, NY, is expected to have 2GW generating capacity, once operational. Beacon Wind, MA, is expected to have 2.4GW generating capacity, once operational. In January 2021, the Empire Wind 2 and Beacon Wind 1 projects were selected to provide New York State with 2.5GW of power – the biggest US offshore wind award to date – adding to the existing commitment to supply 0.8GW. Why it matters Our strategy aims to increase our annual low carbon investment tenfold by 2030 and rapidly grow our developed renewable generating capacity. The partnership will leverage bp’s trading expertise and onshore wind experience with Equinor’s sector-leading track record in offshore wind, and is expected to deliver value for our shareholders and help the world transition to low carbon energy. 2 million Together, these assets have the potential to generate power for more than 2 million US homes. See pages 24 and 34 for more examples of our strategy in action. bp Annual Report and Form 20-F 2020 21 Reinventing bp – our financial frame and investor proposition Our financial frame To reinvent bp and deliver our strategy, we must operate within a resilient financial frame, that combines a strong balance sheet with cash flow generation to support higher investment into transition businesses and compelling shareholder distributions. Our new financial frame aims to provide a stable foundation for bp, strengthening our balance sheet, and providing a clear approach to capital allocation. And through our disciplined approach to investment, we expect to create the opportunity to significantly increase our investment in low carbon activities in this decade, while also operating a high-quality base business. A coherent approach to capital allocation 1 Resilient dividend 2 Strong balance sheet 3 Investing at scale in the energy transition 4 Investing to maximize value in resilient hydrocarbons 5 Share buyback commitment A clear set of priorities Resilient dividend: We aim to fund a resilient dividend intended to remain fixed at 5.25 cents per ordinary share, per quarter, subject to the board’s discretion. Strong balance sheet: In the near term, we target deleveraging to $35 billion of net debt« and maintaining a strong investment grade credit rating thereafter. 22 bp Annual Report and Form 20-F 2020 Investing at scale in the energy transition: We plan to allocate sufficient capital to advance our energy transition strategy, with this allocation intended to rise once our near-term deleveraging target is achieved. We have a range of sector-specific internal rate of return hurdles for transition and low carbon investments between 10% and 15%. For renewable power, we look for returns of at least 8% to 10% levered. All of this is then optimized to make sure we are considering a sufficiently broad range of economic, strategic and sustainability criteria in the context of risk and enduring sources of competitive advantage. Investing to maximize value in resilient hydrocarbons: We aim to invest appropriately in our resilient and valuable hydrocarbons business to generate sustainable cash flow. We have set stringent hurdle rates for all final investment decisions. A payback of less than 10 years for all investments in upstream oil and refining. A payback of less than 15 years for upstream gas. Share buyback commitment: We are committing to return at least 60% of surplus cash« as share buybacks, having reached $35 billion net debt and subject to maintaining a strong investment grade credit rating. Investment in non-oil and gas As part of our net zero ambition (see page 49), we aim to increase the proportion of investment we make into our non-oil and gas businesses. We plan to increase investment in low carbon from around $750 million in 2020 to $3-4 billion by 2025 and to around $5 billion a year in 2030. Our 2020 capital expenditure« against our aim 5 non-oil and gas activities of around $750 million included a partial acquisition payment for the US offshore wind partnership with Equinor, see page 20, our investments in electrification and advanced mobility, and investment into activities through bp ventures and Launchpad. In 2020 Lightsource bp progressed multiple solar projects, including developments in Texas, Indiana, Colorado and Spain. bp Bunge now has capacity for 1.8 billion litres of ethanol production a year and is able to export over 1,200GWh of electricity to the national grid in Brazil. We expect overall low carbon spend to grow significantly in 2021. Capital expenditure for convenience and mobility grew to $2.2 billion in 2020, weighted towards growth and with a focus on new retail sites«, differentiated fuels and lubricants and next-gen mobility. We formed a joint venture with Reliance in India and plan to scale up to 5,500 retail sites by 2025, see page 24. We made significant progress towards our 2030 aim of more than 70,000 electric vehicle charge points« through the DiDi joint venture in China, investment in ultra-fast electric vehicle charging points in Germany, and bp pulse – the UK’s largest public charging network. Overall, bp transition and low carbon capital expenditure in 2020 was around 20% of the capital mix, and by 2030 we expect it to be as much as 50% of our capital expenditure, of which a significant majority will be low carbon. As a reminder, the CA100+ resolution« requires us to disclose: Our anticipated investment in oil and gas resources and reserves – this is anticipated to be less in 2021 than it was in 2020. Our anticipated investment in other energy sources and technologies, which is anticipated to be significantly greater than 2020 levels, as described above. Strategic report Our investor proposition We believe that our strategy and financial frame support the delivery of our investor proposition. Committed distributions Profitable growth Sustainable value through the resilient dividend and our commitment to share buybacks as measured by adjusted EBIDA per share« and ROACE« through investment in a company that is helping the world decarbonize 2021 guidance Upstream reported production excluding Rosneft Total capital expenditure« Depreciation, depletion and amortization Gulf of Mexico oil spill payments (post-tax) Other businesses and corporate underlying annual charge Underlying effective tax rate« a Includes an uplift in valuation of a venture investment of $0.3 billion. b Nearest equivalent GAAP measure: effective tax rate 17%. 2020 actual 2.4mmboe/d $14.1bn $14.9bn $1.6bn $1.0bna -14%b 2021 guidance Lower than 2020. Underlying production« slightly higher than 2020 ~$13bn Similar level to 2020 ~$1bn $1.2-1.4bn Higher than 40% bp Annual Report and Form 20-F 2020 23 Reinventing bp – our strategy in action 24 bp Annual Report and Form 20-F 2020 Strategic report Convenience and mobility We aim to become a leading player in India’s fuels and mobility market through our Jio-bp joint venture with Reliance. The joint venture« will bring together Reliance’s market-leading Jio brand presence with bp’s extensive global experience in convenience, fuel retailing and aviation operations. In addition, Castrol lubricants, India’s number one premium lubricant brand, will also be available across the network. What we’re doing Operating under the Jio-bp brand, we expect to grow Reliance’s current fuel retailing network of more than 1,400 retail sites« to 5,500 by 2025. The joint venture also plans to increase its aviation presence from 30 to 45 airports. Why we’re doing it India is set to be one of the fastest- growing fuels and lubricants markets in the world over the next 20 years, with the number of passenger cars forecast to grow nearly six-fold over that period. We see opportunities over time to shape low carbon mobility solutions for customers in India by supporting the electrification of two and three- wheel transport and providing battery management solutions. What sets us apart Jio-bp sites will seek to offer Indian consumers high-quality, differentiated fuels and tailored convenience services, benefiting from bp’s global convenience and mobility experience and Reliance’s scale, access and digital connection to millions of customers. Customers will also have access to loyalty offers and our Castrol lubricants. This new venture is a unique opportunity to build a leading, fast-growing business that can help meet India’s demands and create exciting new digital and low carbon options for the future. Bernard Looney Chief executive officer 5,500 Jio-bp retail sites expected by 2025 See pages 20 and 34 for more examples of our strategy in action. bp Annual Report and Form 20-F 2020 25 Reinventing bp – consistency with the Paris goals Pursuing a strategy that is consistent with the Paris goals What we mean by Paris consistent We aim to be recognized as a leader in transparency for our sector, in the knowledge that investors and other stakeholders are seeking to understand whether companies and their strategies, targets and aims are consistent with the world meeting the goals of the Paris Agreement on Climate Changea (the Paris goals). This is what we refer to as ‘Paris consistency’. We believe the world is on an unsustainable path – the carbon budget is running out – and needs to reach net zero greenhouse gas emissions. And we believe that there are a range of global pathways to achieve the Paris goals, with differing implications for regions, industries and sectors, so business strategies need to be flexible. Our approach to determining Paris consistency is based on three key principles. We believe that our strategy satisfies all three principles and therefore the board considers it to be consistent with the Paris goals. 1. Informed by Paris-consistent energy transition scenarios – a company’s strategy should be informed by Paris-consistent scenarios. We see the Intergovernmental Panel on Climate Change (IPCC) as the most authoritative source of information on the evolving science of climate change and we use it and other sources to inform our strategy. The IPCC highlights that there are a range of global pathways by which the world can meet the Paris goals, with differing implications for regions, industries and sectors. For many years to come oil and gas features in the energy mix in the IPCC’s suite of Paris-consistent scenarios, albeit progressively decarbonized and ultimately offset; the exact trajectory for oil and for gas varies from scenario to scenario. bp’s new strategy is informed by all of these considerations. It is designed to drive progressive decarbonization, while remaining flexible and adaptable to the many different potential pathways the energy transition may take, including various Paris-consistent pathways. 26 bp Annual Report and Form 20-F 2020 2. Contributing to net zero – whether a company’s strategy enables it to make a positive contribution to the world meeting the Paris goals. We believe that bp’s strategy enables us to make just such a contribution. It is designed to deliver value, while advancing bp towards meeting our net zero ambition and helping the world get to net zero too. Together, we believe this sets out a path that is consistent with the Paris goals. There are many different ways in which a company at the heart of the energy sector can make a meaningful contribution – including action on greenhouse gas emissions (GHG) measured by emissions metrics like Scope 1, 2 and 3. Paris consistency also includes consideration of a range of other activities, such as technology development, policy advocacy, low carbon collaboration and investments in low carbon. Our strategy seeks to address all of these by reshaping bp’s business around our three focus areas and three sources of differentiation, see page 15. Some ways of contributing are more readily measured by quantitative metrics than others – but all can be important, whether or not they translate into GHG reductions for the company. To illustrate this, in terms of low carbon investment, by 2030 we aim to increase the amount of renewable energy generating capacity we have developed to 50GW, as part of our increased capital expenditure on low carbon businesses. This aim supports the Paris goals by increasing the low carbon options available to energy consumers. However, it does not reduce our Scope 1, 2 or 3 emissions. And it may not result in a decrease in the overall intensity of bp’s marketed products, because that is dependent on the extent to which we market the resulting renewable power, which is a commercial consideration. Additionally, our strategy is underpinned by our aim to more actively advocate for policies that support net zero, including carbon pricing. Helping policy makers to design and put in place low carbon policies can help deliver our strategy and take advantage of the huge opportunities associated with achieving the Paris goals. Well-designed low carbon policies can advance the decarbonization of a whole economy – something potentially of far greater impact than anything a single company can achieve through its own portfolio. 3. Strategic resilience – a Paris-consistent strategy should position the company for success and resilience in a Paris-consistent world – a world that is progressing on one of the many global trajectories considered to be Paris consistent, and ultimately meets the Paris goals. We believe this means having a strategy that’s flexible enough to manage the inherent uncertainty in the range of potential global pathways, including those that can achieve the Paris goals. Our new strategy is designed to provide this flexibility. In setting the strategy, the board and management referred to the range of scenarios set out in the bp Energy Outlook 2020, see page 11. We see huge opportunity in the energy transition, including the Outlook’s ‘Rapid’ and ‘Net Zero’ scenarios, which we believe are two of many possible Paris-consistent pathways for the world. Our strategy also mitigates the risks associated with a scenario such as the Outlook’s ‘Delayed and Disorderly’ transition. As a result, our strategy is designed to be resilient across scenarios, including those that are Paris consistent, but is weighted towards a rapid transition. a Paris Agreement 1 Article 2.1(a) of the Paris Agreement states the goal of ‘Holding the increase in the global average temperature to well below 2°C above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels, recognizing that this would significantly reduce the risks and impacts of climate change’. 2 Article 4.1 of the Paris Agreement: In order to achieve the long-term temperature goal set out in Article 2, parties aim to reach global peaking of greenhouse gas emissions as soon as possible, recognizing that peaking will take longer for developing country parties, and to undertake rapid reductions thereafter in accordance with best available science, so as to achieve a balance between anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century, on the basis of equity, and in the context of sustainable development and efforts to eradicate poverty. Strategic report Responding to increased shareholder interest on Paris consistency In 2019 the board recommended that shareholders support a special resolution requisitioned by Climate Action 100+ (CA100+) on climate change disclosures. The CA100+ resolution passed with more than 99% of the vote. This is the second year we have included responses throughout the annual report. We have adopted a similar approach to the bp Annual Report and Form 20-F 2019. The CA100+ resolution, which includes safeguards such as protections for commercially confidential and competitively sensitive information, is on page 341. Key terms related to this resolution response are indicated with « and defined in the glossary on page 341. These should be reviewed with the following information. Element of the CA100+ resolution Related content Where Strategy that the board considers in good faith to be consistent with the Paris goals. How bp evaluates each new material capex investment« for consistency with the Paris goals and other outcomes relevant to bp strategy. Disclosure of bp’s principal metrics and relevant targets or goals over the short, medium and long term, consistent with the Paris goals. Anticipated levels of investment in: (i) Oil and gas resources and reserves. (ii) Other energy sources and technologies. bp’s targets to promote operational GHG reductions. Estimated carbon intensity of bp’s energy products and progress over time. Any linkage between above targets and executive pay remuneration. Our strategy Pursuing a strategy that is consistent with the Paris goals Our investment process Key performance indicators Sustainability: net zero targets and aims See ‘TCFD metrics and targets’ for an overview Our financial frame Sustainability: net zero targets and aims Sustainability: aim 3 Directors’ remuneration report 2020 annual bonus outcome 2021 remuneration policy on page 15 26 29 39 49 55 22 49 50 103 110 124 Portfolio resilience We are managing our portfolio to be resilient to the uncertainties surrounding the energy transition. By 2030 we expect to have a smaller, more resilient and focused oil and gas portfolio. This is supported by our evaluation of each new material capex investment for Paris consistency and our long-term price assumptions, which were reviewed in June 2020. We lowered our price assumptions and extended them to 2050 so that they are now consistent with our long-term time planning horizon, see page 28. We are building a portfolio that is more robust in a low carbon world. We believe that the diversification of our portfolio and decarbonizing our hydrocarbons business will make bp more resilient to Paris-consistent pathways. And this will allow us to continue to redeploy capital to support our strategy to become an Integrated Energy Company – aiming to deploy an appropriate mix of cash flow from hydrocarbons and capital released by divestments into ambitious plans for growth in our low carbon, convenience and mobility businesses, see page 18. Scale and reach Our global footprint and interests in multiple sources of energy provide resilience through exposure to different price environments, and our presence in over 70 countries enables access to new markets. Our track record of creating mutually beneficial strategic partnerships helps our resilience, and we are building new and deeper relationships with governments, cities and corporate customers at a scale that we believe is difficult for others to replicate. Our presence across the energy value chain and our ability to provide integrated energy solutions for our customers position us to succeed in a Paris-consistent world. Targets and aims Our strategy is supported by clear business plans, underpinned by specific short, medium and long-term targets and aims for 2025, 2030 and 2050 or sooner, including: Aiming to be net zero across our entire operations (Scopes 1 and 2). Aiming for the carbon in our upstream oil and gas production (Scope 3) to be net zero. Aiming to cut the life cycle carbon intensity of our marketed products by 50% (which includes the associated Scope 3 emissions). From a 2019 baseline, we aim to increase our annual low carbon investment ten-fold to around $5 billion a year, building out an integrated portfolio of low carbon technologies, including renewables, bioenergy and early positions in hydrogen and carbon capture, use and storage (CCUS). Over the same period, our oil and gas production is expected to reduce by at least 1 million barrels of oil equivalent a day, or 40%, from 2019 levels. bp Annual Report and Form 20-F 2020 27 Reinventing bp – our investment process Our investment process Key investment appraisal assumptions Brent oil ($/bbl) Henry Hub gas ($/mmBtu) RMM« Carbon price (US$/tCO2e) Central case real (2020) 2021 50 3.00 10 2025 50 3.00 12 2030 60 3.00 12 2040 60 3.00 10 2050 50 2.75 10 2021 2025 50 50 2030 100 2040 200 2050 250 Impairment testing As a result of the revision of long-term price assumptions used for investment appraisal, we also revised the price assumptions we use in value in-use impairment testing. These two price sets are now aligned. See pages 166-167 for more about oil and natural gas price assumptions used for impairment testing and relating sensitivity testing. Investment process price assumptions All investments are evaluated against our long-term price assumptions across a range of alternative prices (central, upper and lower) for oil, natural gas and refining margins. In addition, all investment cases above defined thresholds for anticipated annual greenhouse gas (GHG) emissions from operations must estimate those anticipated GHG emissions and include an associated carbon price into the investment economics. All price assumptions place some weight on scenarios in which the transition to a low carbon energy system is sufficiently rapid to meet the goals of the Paris Agreement, as well as scenarios in which the transition is not, or may not be, sufficiently rapid. They also place some weight on a range of other factors, which can drive prices, and are not related to the goals of the Paris Agreement. These price ranges do not link to specific scenarios or outcomes, but instead try to capture the range of different possibilities surrounding the future path of the global energy system. The nature of the uncertainty means that these price ranges inevitably reflect considerable judgement. The ranges are reviewed and updated on an annual basis as our understanding and judgement about the energy transition evolves. In addition to consideration of a range of price assumptions, investment cases are asked to present scenarios covering a range of variables, related to the economics of the investment, such as cost, resource, policy changes and schedule, to highlight the robustness of investment cases to a range of other factors. Price assumptions Revising long-term price assumptions Our price assumptions are determined for use in our investment appraisal processes. They are also used to inform decisions about internal planning processes and the impairment testing of assets for financial reporting. What the prices are As part of our strategy development we reviewed our portfolio and capital development plans. That work was informed by bp’s views of the long-term price environment and its balanced investment criteria. Together these create a framework that seeks to ensure investments align with our strategy and add shareholder value. Additionally, with the COVID-19 pandemic continuing throughout 2020, we see it having an enduring impact on the global economy, with demand for energy weaker than expected for a sustained period. We attach increasing weight to the possibility that the aftermath of COVID-19 will accelerate the pace of transition to a lower carbon economy and energy system, as countries seek to ‘build back better’ so their economies are more resilient and sustainable. As a result of all the above, we revised down our long-term price assumptions, and also extended them to 2050 to align with the horizon of our ambition. The next few years will likely see periods of market volatility as demand recovers against a backdrop of reduced levels of investment and we believe we are well positioned to benefit from any near-term increase in oil prices. The role of long-term price assumptions is to look through this near-term volatility and help ensure our future projects are resilient to the longer-term trends affecting our industry. Our revised investment appraisal long-term price assumptions are now an average of around $55/bbl for Brent« and $2.90 per mmBtu for Henry Hub« gas (2020 $ real), from 2021- 2050. We consider these lower long-term price assumptions to be broadly in line with a range of transition paths consistent with the Paris goals. However, they do not correspond to any specific Paris-consistent scenario. We also revised our carbon prices for the period to 2050, and these now include a price of $100/teCO2 in 2030 (2020 $ real). 28 bp Annual Report and Form 20-F 2020 Strategic report Investment governance and evaluating consistency with the Paris goals Governance bp’s investments fall within a governance framework. This seeks to ensure investments align with our strategy, fall within our prevailing financial frame, and add shareholder value. The governance framework also provides for investments to be assessed consistently and against a range of other outcomes relevant to our strategy, including a range of environmental and sustainability factors. Investments follow an integrated stage-gate process designed to enable us to choose and develop the most attractive investment cases. A balanced set of investment criteria is used, see page 30. This allows for the comparison and prioritization of investments across an increasingly diverse range of business models. The governance framework also specifies that proposed investments are tested, including against carbon prices for projected operational emissions, and are subject to assurance by functions independent of the business before a final investment decision (FID) is taken. See page 88 for more information on bp’s governance framework. Resource commitment meeting For capital investments above defined financial thresholds for organic or inorganic spend, the investment approval is conducted by the executive-level resource commitment meeting (RCM), which is chaired by the chief executive officer. The RCM reviews the merits of each such investment case against a balanced set of criteria and considers any key issues raised in the assurance process. The CA100+ resolution requires bp to disclose how we evaluate the consistency of new material capex investments« with (i) the Paris goals and (ii) a range of other outcomes relevant to bp’s strategy. bp’s evaluation of consistency of such investments with the Paris goals was undertaken by the RCM for new material capex investments sanctioned in 2020, see page 31. bp’s evaluation of an investment’s consistency with ‘a range of other relevant outcomes’ is achieved by considering its merits against bp’s balanced investment criteria as described on page 30. The role of the board The board assesses the impact of portfolio changes, such as strategic acquisitions and the allocation of capital. The board reviews capital investments that are more than $3 billion for resilient hydrocarbons, more than $1 billion for all transition or low carbon investments and, in addition, any significant inorganic acquisition that is exceptional or unique in nature. bp board Reviews investment cases more than $3 billion for resilient hydrocarbons, more than $1 billion for all transition or low carbon investments and any significant inorganic acquisition that is exceptional or unique in nature. Resource commitment meeting Approves investment decisions related to existing and new lines of business above $250 million organic and $25 million inorganic, or which exceeds the relevant EVP financial authority, and for any project considered strategically important such as new market entry. Investment allocation committees EVP level forums to review investment cases within a business group as per individual EVP financial authority (up to $250 million organic, $25 million inorganic capital investment). Business unit investment governance meetings SVP level forums which review investment cases within a business group, enabler or integrator up to the individual SVP financial authority. Cross-group meetings and forums Meetings and forums to allow cross-group discussions and integration. Includes Country Forums, Regional Energy Plan Forum, the Carbon Table and Digital Forum. The forums do not hold decision rights, but inform and underpin the decision-making process delivering integration opportunities across bp. bp Annual Report and Form 20-F 2020 29 Reinventing bp – our investment process Balanced investment criteria Six factors Strategic alignment Safety and risks Investment economics Investment criteria Sustainability Volatility and rateability Optionality and integration Strategic alignment For all investment cases, we consider whether the investment supports delivery of our strategy, see page 18. And if it involves distinctive capability that bp has, or intends to develop, and whether it adds to an existing ‘scale’ business within the portfolio or could help us create one. Investment economics We consider investment economics against a range of measures including internal rate of return, net present value, discounted payback, profitability index and investment efficiency, using a set of scenarios for commodity prices, margins and carbon prices (where relevant). Safety and risks Investment cases are required to describe risks unique to the project which have a significantly higher probability than usual or have a significantly greater impact (relative to the size of the project) were they to occur. Sustainability All investment cases are considered against appropriate environmental and sustainability considerations, and sustainability measures, including carbon. Investment cases above defined thresholds for anticipated annual greenhouse gas (GHG) emissions from operations must estimate those anticipated GHG emissions and include an associated carbon price in the investment economics. Investments are considered against stringent differentiated hurdle rates. 1. A payback of less than 10 years for all investments in upstream oil, refining and for fuels retail in mature markets; together with an internal rate of return hurdle. 2. A payback of less than 15 years for upstream gas; together with an internal rate of return hurdle. 3. We have a range of sector-specific internal rates of returns of between 10% and 15%. And finally, for renewable power we look for returns of at least 8% to 10% levered. Volatility and rateability Economic metrics are also considered in the context of the cash flow certainty of the investment assumptions. For example, a high-return deepwater tieback will have less certain and more volatile (oil-price linked) cash flows than a lower return but more certain renewable power project with a long-term power purchase agreement (and a fixed power price). Optionality and integration All investment cases are requested to quantify the strategic optionality that might be accessed through follow-on activity and regular cross-entity forums enable integration opportunities to be identified. For example, an offshore wind development may provide additional optionality for power offtake and integration into our digital platforms. All group-wide investment cases are required to set out the investment merits and are considered against a set of balanced criteria. This standardized approach creates a level playing field for decision making and allows portfolio-wide comparisons of investment cases. Further, the decision to endorse an investment based on the information provided represents bp’s evaluation that the investment is considered consistent with a range of other outcomes, relevant to bp’s strategy. In 2020 the standardized approach for investment cases was reviewed to place a greater focus on our strategy, sustainability and integration value. These changes, and associated nomenclature, ensure our investment framework is consistent with our strategy. When taking investment decisions, we consider six factors, although our decisions may also take other factors into account as appropriate. 30 bp Annual Report and Form 20-F 2020 Strategic report Evaluation process When evaluating the consistency of our 2020 new material capex investments« with the Paris goals, a focus of the evaluation criteria was on their competitiveness and financial robustness as the prices of different forms of energy and products adjust in response to the changing market environment. For new material capex investment decisions taken from September 2020, the evaluation used our revised central price assumptions of around $55/bbl for Brent« and $2.90 per mmBtu for Henry Hub« gas (2020 $ real), from 2021-2050. It also used our revised central carbon price assumptions, applied to the anticipated operational greenhouse gas emissions associated with the investment, for the period to 2050. These now include a price of $100/teCO2 in 2030 (2020 $ real), see page 28. Our resource commitment meeting (RCM) evaluates consistency with the Paris goals by considering them against a balanced set of investment criteria, see page 30. For each of the investment criteria, a qualitative explanation of each business case was considered and presented to the RCM or relevant investment committee, as per the description on page 29. Our new material capex investments are intended to support the delivery of bp’s strategy. In-scope investments are defined as: New: investment in a new project or extension of an existing project/asset, or share of an entity that is new to bp or a substantial increase in bp’s share. Material: more than $250 million capital investment. Capital expenditure: includes organic and inorganic. 2020 was an exceptional year, and one aspect of bp’s response was to reduce our planned capital expenditure, see page 9. As a result, there were only three new material capex investments – unusually low, and less than half the number in 2019. So bp decided to voluntarily conduct and disclose Paris-consistency evaluations for the four largest new capex investments which fell below our materiality threshold. We do not expect to disclose such evaluations of non- material investments in future years. To maintain consistency of approach, the conduct of these evaluations was delegated to a subset of the RCM. Quantitative evaluations Two quantitative guide levels were considered to inform the evaluation of Paris consistency. As stated in the bp Annual Report and Form 20-F 2019, we continue to develop our approach and in 2020 we made a number of improvements, including benchmarking investment economics against our agreed economic investment hurdles; evaluating investments on the revised price assumptions; and setting a lower carbon intensity guide. As our approach matures with experience, we may continue to adjust or supplement these. Investment economics The calculation of internal rate of return (IRR) and discounted payback uses the ‘central-price’ case for commodity prices and margins and the ‘central’ carbon price. Economic indicators are then benchmarked against the economic hurdles, see page 30. As a guide, we would normally target a minimum threshold of greater than 1.0x on this basis. For clarity, Paris-consistency evaluations for investment decisions made before September 2020 were measured against the previous long-term price assumptions and against the profitability index (PI) measure. For details, see the bp Annual Report and Form 20-F 2019, page 22. Environment and sustainability Where appropriate, we measure the operational carbon intensity« of the investment relative to that of the 2020 portfolio average for the segment or the related business activity (upstream, refining, offshore wind). As a guide, we would normally target a ratio of less than 100%, meaning that the investment is expected to reduce the average operational carbon intensity of that portfolio. The potential impact of new material capex investments on bp’s greenhouse gas emission targets is a further consideration. There may be instances when new material capex investments are evaluated as consistent with the Paris goals despite either or both of these guide levels not being met. bp Annual Report and Form 20-F 2020 31 Reinventing bp – our investment process The respective rankings of investment performance against each of the quantitative guide levels Investment economics Against economic hurdles Sustainability Carbon intensity (%) Guide Guide >$250 million Voluntary disclosures >$250 million Voluntary disclosures 1 The 2020 investments have been ranked against the two guides (as applicable to the evaluation of each investment). As a result, they are ordered differently in each graph above. 2 For one of the investments the operational carbon intensity was not calculated due to the nature of these investments. The projected operational carbon intensity of renewable power businesses is not considered necessary to quantify for these purposes as the relevant operational emissions would not be expected to be significant. Evaluation outcome As shown in the chart, each of the new material capex investments approved in 2020 met the evaluation guides, applicable to the type of investment at the time that the investment decision was made. Each of these investments was evaluated to be consistent with the Paris goals. Similarly, the four additional (non-material) new capex investments in 2020, referred to on page 33, also met the evaluation guides, with the exception of one investment not meeting the guide level for carbon intensity. This investment was evaluated to be consistent with the Paris goals, based on the role liquefied natural gas (LNG) plays in the energy transition, especially in the Asia Pacific region in which the project is located, and the strength of the investment economics – with a short payback period, delivering short-cycle cash returns and reducing the timeframe during which the investment would be exposed to uncertainties associated with Paris-consistent pathways. In addition, when this investment is benchmarked on the carbon intensity measure against other LNG projects, instead of the upstream portfolio average, it benchmarks towards the low end of the range. Each of the four additional capex investments was evaluated to be consistent with the Paris goals. 32 bp Annual Report and Form 20-F 2020 Strategic report Decisions taken in 2020 In 2020 three new material capex investment decisions qualified for evaluation of Paris consistency, using our materiality threshold of $250 million. In addition, because there was an unusually low number of new material capex investments in 2020, we also decided to evaluate the Paris consistency of the four largest new capex investments which fell below our materiality threshold. Herschel development Three-well tie-in to the existing Na Kika infrastructure in the US Gulf of Mexico. Lambert Deep GWF-3 Four-well subsea tieback to the existing Karratha gas plant in Australia. Shafag-Asiman exploration well Gas exploration well in the Shafag-Asiman field in Azerbaijan. US offshore wind acquisition Entry into the US offshore wind market through a strategic partnership with Equinor to develop four assets in existing wind leases. Qattameya Shallow Additional spend to bring the Qattameya gas field in Egypt online. Isabela 3 Single-well tie-in to the Na Kika platform in the US Gulf of Mexico. Galapagos Deep West well Exploration well in ‘Cretaceous Thicks’ play in the US Gulf of Mexico. bp Annual Report and Form 20-F 2020 33 Reinventing bp – our strategy in action 34 bp Annual Report and Form 20-F 2020 Strategic report Resilient and focused hydrocarbons In July 2020, we began production at our major project Atlantis Phase 3 in the US Gulf of Mexico safely and on time, despite the challenges of the COVID-19 pandemic. Since then, we have added a second well and are on schedule to start a third well by April 2021. Why it’s important Atlantis Phase 3 demonstrates our strategic shift towards resilient and focused hydrocarbons for value creation. The project uses world-class existing infrastructure located in the Atlantis field to increase production at higher margin. Drilling completions and offshore construction were executed with zero personal injuries. Harnessing digital and innovation The team used advanced seismic imaging expertise to identify the ‘field within a field’ and designed the new subsea system to access and deliver these barrels. What’s involved? The project includes a subsea production system for eight new wells tied into Atlantis, which is designed to boost the platform’s production. Building on our track record The start-up of this project marks an important milestone for our resilient and focused hydrocarbons businesses under our new strategy. We started up three other major projects« during 2020: Ghazeer in Oman, Vorlich in the UK North Sea and KG D6 R Cluster in India. We’re on track to deliver on our target since 2016 of 900mboe/d from new major projects by the end of 2021, with 700mboe/d of production capacity online by the end of 2020. Atlantis Phase 3 is a great example of how oil and gas projects support bp’s strategy by focusing our efforts in the basins we know best and close to existing infrastructure. Starlee Sykes SVP, Gulf of Mexico and Canada 400,000 hours worked offshore Zero injuries See pages 20 and 24 for more examples of our strategy in action. bp Annual Report and Form 20-F 2020 35 Reinventing bp – our organizational model To deliver our net zero ambition and strategy we are reinventing bp Our organizational model is designed to drive operational excellence and synergies through common processes and economies of scale. The model consists of four business groups… Gas & low carbon energy Brings our energy teams together to create focused low carbon energy solutions. It also pursues the development of decarbonization technologies and potential moves into new value chains such as hydrogen and carbon capture, use and storage. Responsible for: Integrated gas businesses. Onshore and offshore wind. bp’s 50% stake in Lightsource bp. Biopower and biofuels through bp’s 50% stake in bp Bunge Bioenergia. US biogas. Hydrogen and carbon capture, use and storage. Customers & products Focuses on customers as the driving force for innovating new business models and service platforms to deliver the convenience, mobility and energy products and services of the future. Responsible for: Convenience offerings at our retail sites«, including snacks, ready meals and coffee. Fuel sales to customers and businesses. Our Castrol lubricants brand sold through numerous channels. Our aviation fuelling business. Next-gen mobility, including our charging businesses. Refining & trading – our oil products businesses. Production & operations Brings the operations of our hydrocarbon business into one place. It is the operational heart of bp, from which we can produce the hydrocarbon energy and products the world needs – safely, cleanly and efficiently. Innovation & engineering Home to our central engineering, safety and operational risk assurance, and digital security authorities. I&E also aims to act as a catalyst for creating value from disruptive opportunities and new business models. Responsible for: Responsible for: Safe and reliable operations across all of our oil, gas and refining activities, including bpx energy and our strategic investments with Rosneft in Russia. Driving emissions down in our operations. Defining bp-wide operating, engineering and digital standards. Research and development. Digital expertise and transformation. Capturing, incubating and scaling ideas from across bp’s global innovation ecosystem, through bp ventures and Launchpad. We believe in becoming a company that provides integrated, low carbon energy solutions for our customers – bringing together different forms of energy to give the world what it wants: clean, affordable and firm energy. Dev Sanyal, EVP gas & low carbon energy We will unlock the power of collaborating as one customer- centric, digital and agile team, focused on meeting customers’ needs and delivering products and services fit for today, and a low carbon future. Our vision is to build a resilient hydrocarbons business that leads the industry. We maintain an uncompromising focus on safety and emissions and constantly challenge ourselves to improve efficiency. Emma Delaney, EVP customers & products Gordon Birrell, EVP production & operations We’ve gathered many of our most skilled engineers, technologists, scientists, and entrepreneurs into a single team with a purpose – enabling bp to thrive in the energy transition through innovation at pace and scale. David Eyton, EVP innovation & engineering 36 bp Annual Report and Form 20-F 2020 Strategic report See page 38 for more information on our financial reporting segments. working with three integrators, to facilitate collaboration and unlock value… Regions, cities & solutions brings together the best of bp to build enduring relationships with regions, countries, cities and corporations around the world to provide innovative, integrated and decarbonized energy solutions at scale to help the world reach net zero and improve people’s lives. Strategy & sustainability embeds sustainability at the top of the organization and forms a single group-wide approach to strategy and capital allocation. Trading & shipping harnesses the deep expertise of our existing supply, trading and shipping businesses. bp already has world-leading expertise in the integration of businesses, customers and markets. and four teams who serve as enablers of business delivery. Communications & advocacy helps translate bp’s strategy into a coherent narrative for staff and society, manages corporate reputation and leads policy, advocacy and campaigns. Finance stewards bp’s financial frame, maintains financial integrity and manages procurement activities. People & culture helps bp recruit world-class talent, develops them, and supports them to do their best work. Legal delivers legal support to bp, focused on material risk, value and growth. And of this team, 38% are women and 28% identify as racial and ethnic minorities. This is good progress, but still not good enough. As a leadership, we are not yet fully reflective of bp as a whole or the communities in which we operate. See page 57 for more information on diversity and inclusion in bp. From left to right: Emma Delaney EVP, customers & products Dev Sanyal EVP, gas & low carbon energy David Eyton EVP, innovation & engineering Gordon Birrell EVP, production & operations William Lin EVP, regions, cities & solutions Carol Howle EVP, trading & shipping Giulia Chierchia EVP, strategy & sustainability Bernard Looney Chief executive officer Geoff Morrell EVP, communications & advocacy Kerry Dryburgh EVP, people & culture Eric Nitcher EVP, legal Murray Auchincloss Chief financial officer See page 78 for our leadership team biographies. Leadership culture We are transforming the culture of bp. It’s all about people and that begins with leadership. In 2020 we undertook a fundamental review of our organization and selected new leaders from the executive level down. These top 120 leaders were selected because they reflected a number of key attributes required to drive bp’s transformation. A track record of delivery. Curious and open-minded. Purpose-driven. Lead through our values – especially safety. Empathetic. bp Annual Report and Form 20-F 2020 37 Reinventing bp – our financial reporting segments Changing how we report Our new financial reporting model functions across the organization to maximize commercial value along integrated value chains. As set out in our organization model on page 36, operationally, our hydrocarbon businesses, including refining, will be managed together. However, the financial results of our oil, gas and refining operations will be reported separately, acknowledging opportunities for commercial integration. Gas will be reported together with our low carbon businesses. This recognizes the potential for increasing integration of gas value chains with our low carbon businesses. Refining will be reported as part of the customers & products segment, recognizing the importance of maintaining our integrated fuels value chains. For more information on how our hydrocarbon operations are split between the oil production & operations, gas & low carbon energy, and customers & products segments visit bp.com. Gas & low carbon energya comprises regions with upstream businesses that predominantly produce natural gas, gas trading activities and the group’s renewables businesses, including biofuels, solar and wind. Gas-producing regions were previously reported in the Upstream segment, and our renewables businesses were previously reported as part of Other businesses and corporate. Oil production & operationsa comprises regions with upstream activities that predominantly produce crude oil, including bpx energy. These were previously reported in the Upstream segment. Customers & products comprises the group’s customer-focused businesses, spanning convenience and mobility, which includes fuels retail and next-gen offers such as electrification, as well as aviation, midstream, and Castrol lubricants. It also includes our oil products businesses, refining & trading. The petrochemicals business will also be reported in restated comparative information as part of customers & products up to its sale in December 2020. This segment is unchanged from the former Downstream segment with the exception of the disposal of our petrochemicals business. The Rosneft segment is unchanged and continues to include equity-accounted earnings from our strategic investment in Rosneft. Other businesses & corporate comprises our innovation & engineering business including bp ventures and Launchpad, regions, cities & solutions; and our corporate activities & functions. a The AGT and Middle East regions have been further subdivided by asset. See page 36 for our organizational model. Mapping our 2020 segment reporting to our 2021 financial reporting segmentsb Oil production & operations Gas & low carbon energy Customers & productsd Rosneft Other businesses & corporate Upstream Downstream Oil regionsc Gas Gas regionsc Gas marketing & trading Integrated gas & power Customers: convenience & mobility Convenience Mobility: fuels retail Mobility: next-gen Castrol Aviation, B2B, midstream Products: refining & trading Refining Oil & oil products trading Rosneft Other businesses & corporate Low carbon energy Low carbon electricity Bioenergy CCUS Hydrogen Rosneft bp ventures Launchpad Corporate activities b Not a comprehensive list of businesses reported in each segment. c Regions disclosed on bp.com under segment financial disclosure framework. d Includes respective low carbon results, such as bio co-processing. 38 bp Annual Report and Form 20-F 2020 Key performance indicators Measuring our progress Strategic report We assess our performance across a wide range of measures and indicators that are consistent with our strategy and investor proposition. Our key performance indicators (KPIs) provide a balanced set of metrics that give emphasis to both financial and non-financial measures. These help the board and leadership team assess performance against our strategic priorities and business plans. Our leadership team uses these measures to evaluate operating performance and make financial, strategic and operating decisions. Remuneration To help align the focus of our board and executive management with the interests of our shareholders, certain measures are used for executive remuneration. Key REM Used for 2020 remuneration policy See page 103 for more information. Safety Sustainable operations Tier 1 and 2 process safety eventsa We track tier 1 and tier 2 events and report the aggregated outcome. Tier 1 events are losses of primary containment from a process of greatest consequence, or causing harm to a member of the workforce, damage to equipment from a fire or explosion, a community impact or exceeding defined quantities. Tier 2 events are those of lesser consequence. Greenhouse gas emissions (MtCO2e) We provide data on greenhouse gas (GHG) emissions material to our business on a carbon dioxide-equivalent basis. This particular KPI comprises Scope 1 (direct) emissions of CO2 and methane, for 100% emissions from subsidiaries« and the percentage of emissions equivalent to our share of joint arrangements« and associates«, other than bp’s share of Rosneft. 2020 17 2019 26 2018 16 2017 18 2016 16 53 56 61 72 70 98 72 79 2020 2019 2018 2017 84 100 2016 41.3 46.0 46.5 49.4 50.1 Tier 1 process safety events Tier 2 process safety events 2020 performance We had fewer tier 1 and tier 2 process safety events compared with 2019. This may in part be a consequence of decreased activity during the COVID-19 pandemic, but we believe that other, more intentional, factors are also involved, such as our deepening focus on safety leadership, human performance, and the effectiveness of core safety processes, such as permit-to-work. 2020 performance Our Scope 1 (direct) equity share emissions decreased by 4.7MtCO2e to 41.3MtCO2e in 2020 (46.0MtCO2e in 2019). The reduction was associated with a number of factors such as divestments, including of our Alaska operations, sustainable emissions reductions, turnarounds, and the impact of COVID-19 on demand. Sustainable GHG emissions reductions (MtCO2e) This measure includes actions taken by our businesses to improve energy efficiency and reduce methane emissions and flaring – all leading to ongoing, quantifiable GHG reductions. These refer to the GHG emissions on an operational control basisb that would have occurred had we not made the change i.e. they could be absolute in nature or underlying. Since 2019, progress against this target is used as a factor in determining bonuses for eligible employeesc, including executives. 2020 2019 2018 2017 2016 0.132 2020 0.166 2019 0.198 2018 0.218 2017 0.211 2016 1.0 1.4 1.3 0.5 0.7 2020 performance We have seen a decrease in RIF compared with 2019 and maintain our focus to drive zero incidents. Since 2015, RIF rates have decreased around 46%. a This represents reported incidents occurring within bp’s operational HSSE reporting boundary. That boundary includes bp’s own operated facilities and certain other locations or situations. 2020 performance We delivered 1.0Mte of sustainable emissions reductions (SERs) from reduction projects such as flaring in Angola, reduction in water pump fuel gas usage in AGT and in lower emissions from power import at our Gelsenkirchen refinery. b Operational control data comprises 100% of emissions from activities that are operated by bp. c This figure was around 37,000 in February 2020. It is now around 28,600 (as at 10 March 2021) and has been revised in line with restructuring as part of reinvent bp and reflects a lower headcount overall. bp Annual Report and Form 20-F 2020 39 Changes to KPIs We have removed proved reserves replacement ratio from our KPIs, as it no longer serves as a useful measure of our strategic performance. Reported recordable injury frequencya Reported recordable injury frequency (RIF) measures the number of reported work-related employee and contractor incidents that result in a fatality or injury per 200,000 hours worked. Key performance indicators continued Sustainable operations Methane intensity (%) We define methane intensity as the amount of methane emissions from our upstream oil and gas operations as a percentage of the gas that goes to market from those operations. This applies to methane emissions within our operational control boundary, where we have the highest degree of control. Methane emissions from non-producing activities, such as exploration drilling, are excluded. In 2020 we set an intensity target of 0.20% by 2025, using a measurement approach. Downstream refining availability (%) Refining availability represents Solomon Associates’ operational availability for bp-operated refineries. The measure shows the percentage of the year that a unit is available for processing after deducting the time spent on turnaround activity and all mechanical, process and regulatory downtime. Refining availability is an important indicator of the operational performance of our downstream businesses. Upstream plant reliability (%) bp-operated upstream plant reliability is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and, where applicable, the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of Mexico weather-related downtime. 2020 2019 2018 0.12 2020 0.14 2019 0.16 2018 2017 2016 96.0 2020 94.9 2019 95.0 2018 95.2 2017 95.2 2016 94.0 94.4 95.7 94.7 95.3 2020 performance Our methane intensity in 2020 was 0.12%, an improvement from 0.14% in 2019. 2020 performance Refining availability was higher, reflecting continued strong operational performance in our portfolio. This performance is underpinned by our global reliability programmes. 2020 performance Operations were strong in 2020 with plant reliability remaining at 94%. Upstream unit production costs ($/boe) The upstream unit production cost is calculated as production cost divided by units of production. Production cost does not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for bp subsidiaries only and do not include bp’s share of equity-accounted entities. Major project delivery We monitor the progress of our major projects to gauge whether we are delivering our core pipeline of projects under construction on time. Diversity and inclusiond (%) Each year we report the percentage of women and individuals from countries other than the UK and the US among bp’s group leaders. Projects take many years to complete, requiring differing amounts of resource, so a smooth or increasing trend should not be anticipated. Major projects are defined as those with a bp net investment of at least $250 million, or considered to be of strategic importance to bp, or of a high degree of complexity. 2020 2019 2018 2017 2016 6.39 2020 6.84 2019 7.15 2018 7.11 2017 8.46 2016 4 5 6 7 6 2020 2019 2018 2017 2016 29 30 25 25 24 24 21 24 22 23 2020 performance Lower production costs compared with 2019 were mainly due to improved efficiency in our operations and divestment impacts. 2020 performance We started up four major projects in India, Oman, the UK and US. Women in group leadership People from beyond the UK and US in group leadership 2020 performance Both measures increased. As a global business we are committed to increasing the diversity of our workforce and leadership. d Relates to bp employees. 40 bp Annual Report and Form 20-F 2020 Strategic report Employee engagement (%) We conduct an annual employee survey to understand and monitor levels of employee engagement and identify areas for improvement. Financial performance Underlying replacement cost profit ($ billion) Underlying RC profit« is a useful measure for investors because it is one of the profitability measures bp management uses to assess performance. It assists management in understanding the underlying trends in operational performance on a comparable year- on-year basis. It reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses« from profit or loss. Adjustments are also made for non- operating items« and fair value accounting effects«. Operating cash flow ($ billion) Operating cash flow is net cash flow provided by operating activities, as reported in the group cash flow statement. Operating activities are the principal revenue-generating activities of the group and other activities that are not investing or financing activities. We believe it is helpful to disclose net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill because this measure allows for more meaningful comparisons between reporting periods. 2020 2019 2018 2017 2016 64 65 66 66 73 2020 2019 2018 2017 2016 -20.3 -5.7 4.0 10.0 9.4 12.7 3.4 6.2 0.1 2.6 2020 2019 2018 2017 2016 13.8 12.2 28.2 25.8 26.1 22.9 24.1 18.9 17.6 10.7 2020 performance The overall employee engagement score saw a marginal decline since last year. We are working to identify areas for improvement. Scores prior to 2017 are based on questions on priorities set out in 2012, so the numbers are not directly comparable. Profit (loss) for the year attributable to bp shareholders Underlying RC profit for the year (non-GAAP) Operating cash flow excluding amounts related to the Gulf of Mexico oil spill (non-GAAP)e Operating cash flow 2020 performance 2020 underlying RC loss was driven by lower oil and gas prices, significant exploration write-offs and refining margins and depressed demand. Loss for the year attributable to bp shareholders included significant impairments and exploration write-offs. See Financial statements – Notes 4 and 8 for more information. 2020 performance Operating cash flow was lower than 2019, reflecting lower oil and gas realizations, lower refining margins and fuels volumes partly offset by lower tax payments and lower working capital« build. e The dark green bars on the chart do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. Total shareholder return (%) Total shareholder return (TSR) represents the change in value of a bp shareholding over a calendar year. It assumes that dividends are reinvested to purchase additional shares at the closing price on the ex-dividend date. Return on average capital employed (%) Return on average capital employed« (non-GAAP) gives an indication of a company’s capital efficiency, dividing the underlying RC profit after adding back net interest by average capital employed, excluding cash and goodwill. See page 349 for more information including the nearest equivalent GAAP data. 2020 2019 2018 2017 2016 -41.4 -41.7 5.8 1.1 (4.6) 0.5 20.0 9.5 29.0 55.5 2020 2019 2018 2017 2016 -3.8 8.9 11.2 5.8 2.8 ADS basis Ordinary share basis 2020 performance Reduced TSR reflects a reduction in the share price and lower dividend in 2020. 2020 performance The decrease reflects loss due to the impact of lower oil and gas prices and significant weaker refining margin and depressed demand. bp Annual Report and Form 20-F 2020 41 Group performance Group performance Financial and operating performance Sales and other operating revenues Profit (loss) before interest and taxation Finance costs and net finance expense relating to pensions and other post-retirement benefits Taxation Non-controlling interests Profit (loss) for the year attributable to bp shareholders Inventory holding (gains) losses«, before tax Taxation charge (credit) on inventory holding gains and losses RC profit (loss)« for the year attributable to bp shareholders Net (favourable) adverse impact of non-operating items« and fair value accounting effects«, before tax Taxation charge (credit) on non-operating items and fair value accounting effects, and certain foreign exchange impacts on the group’s tax charge for the period Underlying RC profit (loss)« for the year attributable to bp shareholders $ million except per share amounts 2020 2019 2018 180,366 278,397 298,756 (21,740) 11,706 19,378 (3,148) 4,159 424 (3,552) (3,964) (164) (2,655) (7,145) (195) (20,305) 2,868 4,026 (667) 9,383 801 (667) 156 (198) (18,104) 3,515 9,986 16,649 8,263 3,380 (4,235) (1,788) (643) (5,690) 31.5 24.458 9,990 41.0 31.977 12,723 40.5 30.568 Dividends paid per share – cents – pence Results The loss for the year ended 31 December 2020 attributable to bp shareholders was $20.3 billion, compared with a profit of $4.0 billion in 2019. Adjusting for inventory holding losses, replacement cost (RC) loss was $18.1 billion, compared with a profit of $3.5 billion in 2019. After adjusting RC loss for a net charge for non-operating items of $12.2 billion and net adverse fair value accounting effects of $0.2 billion (both on a post-tax basis), underlying RC loss for the year ended 31 December 2020 was $5.7 billion. The result reflected lower oil and gas prices, significant exploration write-offs and lower refining margins and depressed demand. The profit for the year ended 31 December 2019 attributable to bp shareholders was $4.0 billion, excluding inventory holding gains, RC profit was $3.5 billion. After adjusting RC profit for a net charge for non-operating items of $7.2 billion and net favourable fair value accounting effects of $0.7 billion (both on a post-tax basis), underlying RC profit for the year ended 31 December 2019 was $10.0 billion, a decrease of $2.7 billion compared with 2018. The decrease was predominantly due to lower oil and gas prices in the Upstream segment and a significantly weaker environment in the Downstream segment. Non-operating items In 2020 the net charge for non-operating items was $12.2 billion, mainly related to impairment charges, a gain on the disposal of our petrochemicals business, certain exploration write-offs (reported within the ‘other’ category), and restructuring costs associated with the reinvent bp programme. The impairment charges mainly relate to producing assets and principally arose as a result of changes to the group’s oil and gas price assumptions. Impairment charges also include amounts relating to the disposal of the group’s interests in its Alaska business. In the face of many challenges in 2020, we strengthened our finances and drove progress towards our $35 billion net debt target. A resilient balance sheet, a coherent approach to capital allocation and a disciplined approach to investment are the principles which underpin our financial frame. Our strategy and financial frame are expected to drive strong growth, improved returns and a sustainable reallocation of our capital employed toward the energy transition, all in support of creating long-term value for shareholders. Murray Auchincloss Group chief financial officer 42 bp Annual Report and Form 20-F 2020 For more information For a discussion of bp’s financial and operating performance for the year ending 31 December 2018, see bp Annual Report and Form 20-F 2019, pages 36-38 and 50-65 and bp Annual Report and Form 20-F 2018, pages 19-39. Strategic report In 2019 the net charge was $7.2 billion, mainly related to impairment charges, principally resulting from the announcements to dispose of certain assets in the US and reclassification of accumulated foreign exchange losses from reserves to the income statement on the formation of the bp Bunge Bioenergia joint venture«. See pages 304 and 305 for more information on non-operating items and fair value accounting effects. Taxation The credit for corporate income taxes was $4,159 million in 2020 compared with a charge of $3,964 million in 2019. The decrease mainly reflects the loss in 2020. The effective tax rate (ETR) on the loss for the year in 2020 was impacted by the impairment charges and exploration write-offs. The ETRs for 2020 and 2019 were also impacted by various other one-off items. Adjusting for inventory holding impacts, non-operating items and fair value accounting effects, the underlying ETR in 2020 was lower than in 2019, mainly reflecting the exploration write-offs with a limited deferred tax benefit and the reassessment of deferred tax asset recognition. The underlying ETR for 2021 is expected to be higher than 40% but is sensitive to the impact that volatility in the current environment may have on the geographical mix of the group’s profits and losses. Underlying ETR is a non-GAAP measure. A reconciliation to GAAP information is provided on page 348. $(5.7)bn underlying replacement cost (RC) loss (2019 profit $10.0bn) $(20.3)bn loss attributable to bp shareholders (2019 profit $4.0bn) $13.8bn operating cash flow excluding Gulf of Mexico oil spill paymentsa« (2019 $28.2bn) a This does not form part of bp’s Annual Report on Form 20-F as filed with the SEC. $12.2bn operating cash flow« (2019 $25.8bn) Non-operating items Gains on sale of businesses and fixed assets Impairment and losses on sale of businesses and fixed assets Environmental and other provisions Restructuring, integration and rationalization costs Fair value gain (loss) on embedded derivatives Gulf of Mexico oil spill Other Total before interest and taxation Finance costs Taxation credit (charge) on non-operating items Taxation – impact of US tax reform Taxation – impact of foreign exchange Effective tax rate Effective tax rate (ETR) on profit or loss for the year Underlying ETR« 2020 2,874 (14,369) (212) (1,296) – (255) (2,554) (15,812) (625) (16,437) 4,345 – (99) (12,191) 2020 17 (14) $ million 2019 193 (8,075) (341) 2 – (319) (78) (8,618) (511) (9,129) 1,943 – – (7,186) % 2019 49 36 2018 456 (860) (758) (726) 17 (714) (372) (2,957) (479) (3,436) 510 121 – (2,805) 2018 43 38 bp Annual Report and Form 20-F 2020 43 Group performance continued Reporting The group’s organizational structure reflects the various activities in which bp is engaged. At 31 December 2020, bp reported Upstream, Downstream, Rosneft and Other businesses and corporate. Upstream’s activities included oil and natural gas exploration, field development and production; midstream transportation, storage and processing; and the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs). For further details of Upstream’s activities during the year see page 308. Downstream’s activities covered convenience and mobility offers, including next-gen mobility to our customers. It also included the refining, manufacturing, marketing, transportation, and supply and trading of crude oil, petroleum, lubricants and petrochemicals products. The Rosneft segment result includes equity- accounted earnings arising from bp’s interest in Rosneft. Other businesses and corporate comprised the biofuels and wind businesses, the group’s shipping and treasury functions, and corporate activities worldwide. In February 2020 bp announced plans for a future reorganization of the group’s operating segments. The group’s segmental reporting structure described above remained in place throughout 2020 and changes, as described on page 38, were effective from 1 January 2021. Sales and other operating revenues Upstream Downstream Other businesses and corporate Less: sales and other operating revenues between segments Total sales and other operating revenues RC profit (loss) before interest and tax Upstream Downstream Rosneft Other businesses and corporate Consolidation adjustment – UPII« Net (favourable) adverse impact of non-operating items and fair value accounting effects Upstream Downstream Rosneft Other businesses and corporate Underlying RC profit (loss) before interest and tax Upstream Downstream Rosneft Other businesses and corporate Consolidation adjustment – UPII bp average realizationsa Crude oilb Natural gas liquids Liquids« Natural gas US natural gas Total hydrocarbons« Average oil marker pricesc Brent« West Texas Intermediate« Average natural gas marker prices Average Henry Hub« gas priced $ million 2020 2019 2018 34,197 162,974 1,716 54,501 250,897 1,788 56,399 270,689 1,678 198,887 307,186 328,766 18,521 28,789 30,010 180,366 278,397 298,756 (21,547) 3,418 (149) (683) 89 4,917 6,502 2,316 (2,771) 75 (18,872) 11,039 16,506 (330) 205 (357) 16,024 (5,041) 3,088 56 (1,040) 89 (2,848) 6,241 (83) 103 1,491 7,752 11,158 6,419 2,419 (1,280) 75 18,791 $ per barrel 61.56 18.23 57.73 38.46 12.91 36.16 14,328 6,940 2,221 (3,521) 211 20,179 222 621 95 1,963 2,901 14,550 7,561 2,316 (1,558) 211 23,080 67.81 29.42 64.98 $ per thousand cubic feet 2.75 1.30 3.39 1.93 3.92 2.43 $ per barrel of oil equivalent 26.31 38.00 43.47 $ per barrel 41.84 39.25 64.21 57.03 71.31 65.20 $ per million British thermal units 2.08 2.63 3.09 pence per therm Average UK National Balancing Point gas price« 24.93 34.70 60.38 bp average refining marker margin (RMM)« 6.7 13.2 13.1 $/bbl 44 bp Annual Report and Form 20-F 2020 a Realizations are based on sales by consolidated subsidiaries« only, which excludes equity-accounted entities. b Includes condensate. c All traded days average. d Henry Hub First of Month Index. Strategic report Upstream Sales and other operating revenues for 2020 were lower due to lower liquids and gas realizations, lower gas marketing and trading revenues and were further impacted by lower sales volumes. RC loss before interest and tax for the segment included a net non-operating charge of $15,768 million. This primarily relates to impairments associated with revisions to the long-term price assumptions. See Financial statements – Note 5 for further information. Fair value accounting effects had an adverse impact of $738 million relative to management’s view of performance. The 2019 result included a net non-operating charge of $6,947 million, primarily related to impairment charges arising from disposal transactions. Fair value accounting effects had a favourable impact of $706 million relative to management’s view of performance. After adjusting for non-operating items and fair value accounting effects, the underlying RC result before interest and tax was lower in 2020 compared with 2019. This primarily reflected lower liquids and gas realizations and the impact of writing down certain exploration intangible carrying values. Downstream Sales and other operating revenues in 2020 were lower than in 2019, mainly due to lower crude and product prices and the demand impact of COVID-19. RC profit before interest and tax for 2020 included a net non-operating gain of $479 million. The gain reflected a profit of $2.3 billion on the sale of our petrochemicals business, which was partially offset by restructuring costs and impairments. In addition, fair value accounting effects for 2020 had an adverse impact of $149 million, compared with a favourable impact of $160 million in 2019. After adjusting for non-operating items and fair value accounting effects, underlying RC profit before interest and tax for the year was $3,088 million. The fuels business reported a lower underlying RC profit before interest and tax compared with 2019, due to an exceptionally weak refining environment, with COVID-19 restrictions impacting refining utilization and fuel volumes. The 2020 result also reflects a higher contribution from supply and trading. Our fuels marketing business demonstrated continued resilience, delivering significant profit in 2020, despite COVID-19 – which adversely impacted retail fuel and aviation volumes by 14% and 50% respectively. Rosneft RC loss before interest and tax for 2020 and RC profit before interest and tax for 2019 for the segment included a non-operating charge of $205 million for 2020 and $103 million for 2019. Refining loss in 2020 reflects the continued impact of historically low industry margins. Although refining availability« was strong at 96%, utilization was around 6% lower than 2019, due to the impact of COVID-19 on demand. These factors were partially offset by a lower level of turnaround activity and lower costs. In the fourth quarter of 2020, we announced plans to cease production at our Kwinana refinery and convert it to an import terminal, helping secure ongoing fuel supply for Western Australia. We continued to redefine convenience in 2020, delivering a 6% growth in convenience gross margin«. We also expanded our retail network by more than 1,400 sites, to a total of 20,300, including more than 1,900 strategic convenience sites«. And we completed the formation of Jio-bp, our Indian joint venture with Reliance, helping more than double the number of retail sites in growth markets«, see page 24. We also progressed our electrification agenda, growing our network to 10,100 bp and joint venture operated electric vehicle charge points«, see Our strategy on page 15. The lubricants business reported a lower underlying RC profit before interest and tax compared with 2019 and this reflected significant COVID-19 demand impacts, with volumes 15% lower for the year. We continued to expand our service offer in 2020, growing the number of Castrol branded independent workshops by more than 4,000 to over 28,000 globally. The petrochemicals business reported a lower underlying RC profit before interest and tax compared with 2019, reflecting the impact of COVID-19 on demand and a significantly weaker margin environment. In December we completed the divestment of bp’s petrochemicals business to INEOS for a total consideration of $5 billion. Final payments, totalling $1 billion, were received in February 2021. For more information see Additional information for Downstream on page 318. After adjusting for non-operating items, the underlying RC profit before interest and tax in 2020 primarily reflected lower oil prices and unfavourable foreign exchange and adverse duty lag effects compared with 2019 underlying profit. Financial and operating performance for 2020 also reflected the increased average economic interest that bp holds in Rosneft as a result of Rosneft’s share buyback programme and the transaction to sell Rosneft’s business in Venezuela in exchange for its own shares, which completed in April 2020. For more information see Additional information for Rosneft on page 320. Other businesses and corporate RC loss before interest and tax for the year ended 31 December 2020 was $683 million (2019 $2,771 million). The 2020 result included a net charge for non-operating items of $318 million, primarily relating to Gulf of Mexico oil spill related costs of $255 million and restructuring costs, partly offset by a gain on disposal (non-operating items in 2019 $1,491 million). In addition, fair value accounting effects had a favourable impact of $675 million. After adjusting for non-operating items and fair value accounting effects, the underlying RC loss before interest and tax for the year ended 31 December 2020 was $1,040 million (2019 $1,280 million). This result mainly reflected an uplift in valuation of a venture investment of $284 million. Outlook for 2021 From the oil supply side, limited growth from non-OPEC+ countries coupled with active market management from OPEC+ means that for 2021 we anticipate a normalization of the currently high inventory levels. Oil demand is anticipated to recover in 2021. The speed and degree of the rebound depends on governments’ policies and individuals’ self-imposed actions as vaccine distribution proceeds. bp Annual Report and Form 20-F 2020 45 Group performance continued Oil prices have risen since the end of October, supported by vaccine rollout programmes and continued active supply management by OPEC+ countries. Prices are expected to remain subject to the decisions of OPEC+, confidence in efforts to manage the rollout of vaccination and further virus control measures. We expect the US gas market to tighten in 2021 as supply declines and demand for LNG exports recovers. The current tightness on global LNG markets and higher US gas prices will lift other regional gas prices. US gas markets are likely to benefit from lower production and a recovery in international LNG demand driven by demand in Asia. In Downstream we expect the outlook for the first part of the year to remain challenged due to COVID-19, but to improve. While COVID-19 has had material impacts at the start of the year, with increased restrictions resulting in lower product demand, we expect this uncertainty to improve subject to the successful rollout of vaccination and virus control measures. Industry refining margins and utilization continue to remain restrained by uncertainty about the pace of demand recovery. The weak margin environment combined with continued capacity additions in developing markets has prompted a raft of third-party closure announcements. However, these closures are unlikely to be sufficient to see a sustained rebound in margins to pre-COVID levels in 2021. Full-year 2021 underlying production« is expected to be slightly higher than 2020 due to the ramp-up of major projects«, primarily in gas regions, partly offset by the impacts of reduced capital investment and decline in lower-margin gas assets. Reported production is expected to be lower due to the impact of the ongoing divestment programme. Other businesses and corporate charges for 2021, excluding non-operating items, fair value accounting effects and foreign exchange volatility impact, are expected to be $1.2-1.4 billion although the quarterly charge may vary quarter to quarter. Cash flow and net debt information Operating cash flow excluding Gulf of Mexico oil spill paymentsa Operating cash flow Net cash used in investing activities Net cash provided by (used in) financing activities Cash and cash equivalents at end of year Capital expenditure« Organic capital expenditure« Inorganic capital expenditure« Divestment and other proceeds Divestment proceeds« Other proceeds Debt Finance debt Net debt« Finance debt ratio« (%) Gearing« (%) Gearing including leases« (%) a This does not form part of bp’s Annual Report on Form 20-F as filed with the SEC. $ million 2020 2019 2018 13,770 12,162 (7,858) 3,956 31,111 28,199 25,770 (16,974) (8,817) 22,472 26,091 22,873 (21,571) (4,079) 22,468 (12,034) (2,021) (15,238) (4,183) (15,140) (9,948) (14,055) (19,421) (25,088) 5,480 1,106 6,586 72,664 38,941 45.9% 31.3% 36.0% 2,201 566 2,767 67,724 45,442 40.2% 31.1% 35.3% 2,851 666 3,517 65,132 43,477 39.1% 30.0% NA Operating cash flow for the year ended 31 December 2019 was $25.8 billion, $2.9 billion higher than 2018. Operating cash flow in 2019 reflected $2.7 billion of pre-tax cash outflows related to the Gulf of Mexico oil spill. Compared with 2018, operating cash flows in 2019 also reflected the favourable effect of an estimated $2.0 billion of lease payments being classified as financing cash flows from 1 January 2019 following the implementation of IFRS 16. Movements in working capital adversely impacted cash flow in the year by $2.9 billion, including an adverse impact on working capital from the Gulf of Mexico oil spill of $2.6 billion. Operating cash flow Operating cash flow for the year ended 31 December 2020 was $12.2 billion, $13.6 billion lower than 2019. Operating cash flow in 2020 reflects $1.8 billion of pre-tax cash outflows related to the Gulf of Mexico oil spill. Compared with 2019, operating cash flows in 2020 reflected lower oil and gas realizations, lower refining margins and lower fuels volumes partly offset by lower tax payments and lower working capital« build. Movements in working capital adversely impacted cash flow in the year by $0.1 billion, including an adverse impact on working capital from the Gulf of Mexico oil spill of $1.6 billion. Other working capital effects, principally a decrease in inventory and other current and non-current assets partially offset by a decrease in other current and non-current liabilities, had a favourable effect of $1.5 billion. bp actively manages its working capital balances to optimize and reduce volatility in cash flow. 46 bp Annual Report and Form 20-F 2020 Strategic report Net cash used in investing activities Net cash used in investing activities for the year ended 31 December 2020 decreased by $9.1 billion compared with 2019. The decrease mainly reflected lower capital expenditure, particularly due to payments of $3.5 billion in 2019 for the acquisition of unconventional onshore US oil and gas assets from BHP, and $3.9 billion of disposal proceeds from the petrochemicals divestment. Total capital expenditure for 2020 was $14.1 billion (2019 $19.4 billion), of which organic capital expenditure was $12.0 billion (2019 $15.2 billion) in line with the guidance given in April. Sources of funding are fungible, but the majority of the group’s funding requirements for new investment comes from cash generated by existing operations. We expect 2021 total capital expenditure, including organic capital expenditure, to be around $13 billion. Total divestment and other proceeds for 2020 amounted to $6.6 billion, including $3.9 billion of proceeds from the petrochemicals divestment and $1.1 billion other proceeds. Other proceeds represented a loan repayment relating to the TANAP pipeline refinancing; and proceeds in relation to the sale of interests in bp’s retail property portfolio in the UK and New Zealand. Total divestment and other proceeds for 2019 amounted to $2.8 billion, including $0.6 billion received in relation to the sale of an interest in bp’s retail property portfolio in Australia. The proceeds from the UK, New Zealand and Australia property transactions are reported within financing activities in the group cash flow statement. bp has completed or agreed transactions for over half of its target of $25 billion in proceeds by 2025. bp expects proceeds from divestments and other disposals of $4-6 billion in 2021, weighted towards the second half. Net cash provided by (used in) financing activities Net cash provided by financing activities for the year ended 31 December 2020 was $4.0 billion, compared with net cash used of $8.8 billion in 2019. This was mainly due to the issue of perpetual hybrid bonds with a US$ equivalent value of $11.9 billion. Group reserves and production (including Rosneft segment)a Estimated net proved reserves (net of royalties) Liquids (mmb) Natural gas (bcf) Total hydrocarbons (mmboe) Of which: Equity-accounted entitiesb Production (net of royalties) Liquids (mb/d) Natural gas (mmcf/d) Total hydrocarbons (mboe/d) Of which: Subsidiaries Equity-accounted entitiesc 2020 2019 2018 10,661 42,467 17,982 11,478 45,601 19,341 11,456 49,239 19,945 10,100 9,965 9,757 2,106 7,929 3,473 2,146 1,326 2,211 9,102 3,781 2,420 1,360 2,191 8,659 3,683 2,328 1,355 a Because of rounding, some totals may not agree exactly with the sum of their component parts. b Includes BP’s share of Rosneft. See Supplementary information on oil and natural gas on page 231 for further information. c Includes BP’s share of Rosneft. See Oil and gas disclosures for the group on page 312 for further information. Total dividends distributed to shareholders in 2020 were 31.5 cents per share, 9.5 cents lower than 2019. This amounted to a total distribution to shareholders of $6.3 billion in 2020. In 2019 the total distribution to shareholders was $8.3 billion, of which shareholders elected to receive $1.4 billion in shares under the scrip dividend programme. The board decided not to offer a scrip dividend alternative in respect of the 2020 dividends. Debt Finance debt at the end of 2020 increased by $4.9 billion from the end of 2019. The finance debt ratio at the end of 2020 increased to 45.9% from 40.2% at the end of 2019. Net debt at the end of 2020 decreased by $6.5 billion from the 2019 year-end position. Gearing at the end of 2020 increased to 31.3% from 31.1%, reflecting significant impairments and exploration write- offs, offset by the hybrid bond issue in June 2020. Net debt and gearing are non-GAAP measures. See Financial statements – Notes 26 and 27 for further information on finance debt and net debt. For information on financing the group’s activities see Financial statements – Note 29 and Liquidity and capital resources on page 306. Group reserves and production Total hydrocarbon proved reserves at 31 December 2020, on an oil equivalent basis including equity-accounted entities, decreased by 7% compared with 31 December 2019. Natural gas represented about 41% (47% for subsidiaries and 36% for equity-accounted entities) of these reserves. The change includes a net decrease from acquisitions and disposals of 1,069mmboe (decrease of 1,072mmboe within our subsidiaries and increase of 3mmboe within our equity-accounted entities). Acquisition and divestment activity occurred in our equity-accounted entities in Russia, and divestment activity in our subsidiaries in the US including Alaska. Total hydrocarbon production for the group was 8% lower compared with 2019. The decrease comprised an 11% decrease (6% decrease for liquids and 16% decrease for gas) for subsidiaries and a 2% decrease (4% decrease for liquids and 2% increase for gas) for equity-accounted entities. bp Annual Report and Form 20-F 2020 47 Sustainability Our approach to sustainability E n g a g i n g stakeholders Our values and foundations E mbedding int o o u r D N A Sustainability frame Sustainability is a critical foundation of our strategy. Our new sustainability frame links our strategy to our purpose – to reimagine energy for people and our planet. Our frame focuses on three areas where we believe we can make the biggest difference, with aims and objectives linked to the UN Sustainable Development Goals. Getting to net zero. Caring for our planet. Improving people’s lives. You can read more about our focus areas, sustainability foundations, our work to make sustainability more integral to our thinking and how we’re expanding our engagement with stakeholders at bp.com/sustainability Reporting on sustainability We updated our sustainability materiality assessment process in 2020 to take into account our new sustainability frame. You can read more about this process in the bp Sustainability Report 2020. For the purposes of this section we have covered material issues, along with additional non-financial information in the following areas: Net zero aims, see pages 49-51. Climate change and the environment, see pages 52-55. Safety, see pages 59-60. People and value to society, see pages 57-58. Business ethics and accountability, see page 61. bp non-financial reporting information statement Produced in compliance with Sections 414CA and 414CB of the Companies Act. Information incorporated by cross reference. Requirement a. Environmental matters b. Employees Relevant policies and standards Net zero aims TCFD (governance and risk) Sustainability frame Biodiversity position (online) Reinvent bp guidelines bp values and code of conduct (online) c. Social matters Sustainability frame d. Respect for human rights e. Anti-corruption and anti-bribery Description of principal risks relating to matters (a-e above) – Business and human rights policy (online) Modern slavery statement (online) Labour rights and modern slavery principles (online) Code of conduct (online) Anti-bribery and corruption policy Code of conduct (online) Business model description Business model – pages 16-17. Description of non-financial KPIs Key performance indicators – pages 39-41. Relevant information Information related to policies, any due diligence process and the outcome (a-e) Climate change and the environment – pages 53-57. Managing our environmental impacts – page 56. Our operating management system« (OMS) – page 60. Decision making by the board – page 82. People and society – pages 57-58. Safety – pages 59-60. Our values and code of conduct – page 61. How we engage with our stakeholders (Pulse survey) – page 63. How the board engaged with stakeholders (Workforce) – page 86. Managing our environmental impacts – page 56. Our operating management system – page 60. Value to society – page 58. Decision making by the board – page 82. Human rights – page 58. How we engage with our stakeholders (Our human rights policy) – page 63. Our values and code of conduct – page 61. Business ethics and accountability – page 61. Our partners in joint arrangements – page 60. How we manage risk – pages 64-66. Risk factors – pages 67-70. TCFD (climate-related risk management), pages 55-56. 48 bp Annual Report and Form 20-F 2020 Our net zero aims In February 2020 we set out our ambition to be a net zero company by 2050 or sooner. And to help the world get to net zero. This ambition is supported by 10 aims: five to help us become a net zero company, and five to help the world meet net zero. Taken collectively, these set out a path that we believe is consistent with the Paris goals. Strategic report Our net zero targets and aims at a glance Aims 2020 performance 2025 target 2030 aims 2050, or sooner, aims 16%a 9%ab 20% 30-35% 100% 20% 35-40% 100% 0.6%ab 5% >15% 50% 0.12%c $750me 0.20% (based on our new measurement approach)d $3-4bn Timeline to achieve 50% reduction to follow ~$5bn Aim 1 Aim 2 Aim 3 Aim 4 Aim 5 What we mean by net zero When we talk about helping the world get to net zero we mean achieving a balance between sources of anthropogenic emissions and removal by sinks of greenhouse gases, as set out in Article 4.1 of the Paris Agreementf. When talking about bp becoming a net zero company by 2050, or sooner, in the context of our new ambition and aims 1 and 2, this means achieving a balance between (a) the relevant Scope 1 and 2 emissions associated with our operations (aim 1), or Scope 3 emissions associated with carbon in bp’s net share of production of oil and gas excluding Rosneft (aim 2), and (b) the total of applicable deductions from activities such as sinks, for example carbon capture, use and storage (CCUS) and land carbon projects, which we allow for in our methodology. Our aim 1 is to be net zero across our entire operations on an absolute basis by 2050 or sooner. This aim relates to our Scope 1 (from running the assets within our operational control boundary) and Scope 2 (associated with producing the electricity, heating and cooling that is bought in to run those operations) GHG emissions. Our performance in 2020 Our combined Scope 1 and Scope 2 emissions, covered by aim 1, decreased by 16% from 54.4MteCO2e in 2019 to 45.5MteCO2e in 2020. Scope 1 (direct) emissions covered by aim 1 decreased by 15% to 41.7MteCO2e in 2020, from 49.2MteCO2e in 2019. Of those Scope 1 emissions, 39.8MteCO2e were from CO2 and 1.9MteCO2e from methane. Scope 2 (indirect) emissions decreased by 1.4MteCO2e, to 3.8Mte CO2e, a 27% reduction compared to 2019. Decreases resulted from SERs, reduced energy requirement following COVID-19 demand reduction and also include a 1MteCO2e reduction in reported emissions from our Whiting refinery, which in 2020 put an agreement in place to purchase electricity from our Whiting clean energy facility. Our aim 2 is to be net zero on an absolute basis across the carbon in our upstream oil and gas production« by 2050 or sooner. This is our Scope 3 aim and is on a bp equity share basis excluding Rosneft. Emissions are broadly equivalent to the GHG Protocol, Scope 3, category 11g, with the specific scope of upstream production volumes. Our performance in 2020 The estimated emissions from the carbon in our Upstream oil and gas production were equivalent to 328MteCO2e in 2020, a reduction of approximately 9% compared to 361MteCO2eb in 2019. a Reductions against the 2019 baseline. b The baseline year for our aims 1, 2 and 3 is 2019. Following publication of the bp Annual Report and Form 20-F 2019, some data improvements related to the reported 2019 figures for aims 2 and 3 were identified. Although these are not considered to be material, for each of aims 2 and 3 the 2019 figure has been adjusted. c The 2020 methane intensity is calculated using existing methodology and, while it reflects progress in reducing methane emissions, will not directly correlate with progress towards delivering the 2025 target under aim 4. d We aim to have this in place by end of 2023. e Aim 5 non-oil and gas activities included a partial acquisition payment for the US offshore wind partnership with Equinor, our investments in electrification and advanced mobility, and investment into activities through bp ventures and Launchpad. f Article 4.1 of the Paris Agreement: In order to achieve the long-term temperature goal set out in Article 2, Parties aim to reach global peaking of greenhouse gas emissions as soon as possible, recognizing that peaking will take longer for developing country parties, and to undertake rapid reductions thereafter in accordance with best available science, so as to achieve a balance between anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century, on the basis of equity, and in the context of sustainable development and efforts to eradicate poverty. g See ghgprotocol.org for the full list of categories. bp Annual Report and Form 20-F 2020 49 Sustainability continued Our aim 3 is to cut the carbon intensity of the products we sell by 50% by 2050 or sooner. This is a lifecycle carbon intensity approach, per unit of energy. It covers marketing sales of energy products and potentially, in future, certain other products, for example, associated with land carbon projects (79.3gCO2e/MJ in 2019a). In 2020, while we made progress in increasing the marketed sales of low carbon products, the reduction in the bp carbon intensity was largely a result of the reduction in sales of refined products, due to COVID-19. See the basis of reporting for the definition of marketed sales and the list of energy products covered at bp.com/basisofreporting. Our performance in 2020 Average emissions intensity of marketed energy products (gCO2e/MJ)« Average emissions intensity of marketed energy products Refined energy products Gas products Bio-products Power products 2020 2019 78.8 92.6 71.6 28.2 43.0 79.3 92.8 71.6 28.8 43.8 Streamlined energy and carbon reporting (SECR) information Further information on our greenhouse gas (GHG) emissionsb, energy consumption and energy efficiency is set out below and includes disclosures in respect of the SECR requirements. Operational controlc Scope 1 (direct) emissions UK and offshore Global (excluding UK and offshore) Scope 2 (indirect) emissionsd UK and offshore Global (excluding UK and offshore) Energy consumptione UK and offshore Global (excluding UK and offshore) Unit MteCO2e MteCO2e MteCO2e MteCO2e MteCO2e MteCO2e GWh GWh GWh Ratio of Scope 1 (direct) and Scope 2 (indirect) GHG emissions to gross productionf UK and offshore Global (excluding UK and offshore) teCO2e/te teCO2e/te teCO2e/te 2019 49.2 2018 48.8 2017 50.5 5.2 5.4 6.1 0.22 0.22 0.24 2020 41.7 1.7 40.0 3.8 0.04 3.77 180,004 7,005 172,999 0.20 0.17 0.20 Energy efficiency measures Since 2016 we have delivered 4.9Mte of sustainable emissions reductions (SERs)« across our operated sites. This is our key metric for tracking annual reductions in greenhouse gas (GHG) emissions from energy efficiency savings and direct GHG emissions. We set annual internal targets for the delivery of SERs across bp. In 2020 we delivered 1MteCO2e of SERs. These included reductions in flaring, direct methane emissions and energy efficiency savings. For example, our operations in the AGT region reduced fuel use for water injection pumps through energy efficiency optimization resulting in a 55kteCO2e reduction of Scope 1 emissions. Further SERs include those delivered by our US onshore operations, bpx energy of over 245kteCO2e – driving operational efficiencies and substantively reducing our methane emissions profile. Our assets in the Permian region delivered 94kteCO2e of SERs. The largest of these projects was construction and delivery of a centralized facility and electrification of certain operations combined with use of renewable electricity. bp equity sharebg Our Scope 1 (direct) equity share emissions decreased by 4.7MtCO2e to 41.3MtCO2e in 2020 (46.0MtCO2e in 2019). The reduction was associated with a number of factors such as divestments, including of our Alaska operations, turnarounds, and the impact of COVID-19 on demand. Scope 1 (direct) emissions Scope 2 (indirect) emissions Total 2020 2019 2018 41.3 4.2 45.5 46.0 5.7 51.7 46.5 5.7 52.2 a The baseline year for our aims 1, 2 and 3 is 2019. Following publication of the bp Annual Report and Form 20-F 2019, some data improvements related to the reported 2019 figures for aims 2 and 3 were identified. Although these are not considered to be material, for each of aims 2 and 3 the 2019 figure has been adjusted. b Our approach to reporting GHG emissions broadly follows the IPIECA/API/IOGP Petroleum Industry Guidelines for Reporting GHG Emissions. We calculate CO2 emissions based on the fuel consumption and fuel properties for major sources. We report CO2 and methane. We do not include nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur hexafluoride as they are not material to our operations and it is not practical to collect this data. c Operational control data comprises 100% of emissions from activities operated by bp, going beyond the IPIECA guidelines by including emissions from certain other activities such as contracted drilling activities. d Value rounded to one decimal place. e Energy content of flared or vented gas is excluded from energy consumption reported as although they reflect loss of energy resources, they do not reflect energy use required for production or manufacturing of products. f Gross production comprises upstream production, refining throughput and petrochemicals produced. g bp equity share data comprises 100% of emissions from subsidiaries and the percentage of emissions equivalent to our share of joint arrangements and associates, other than bp’s share of Rosneft. 50 bp Annual Report and Form 20-F 2020 Strategic report collaborations. We will continue to run recruitment campaigns and advertise our products, services and partnerships – although we aim for these to be increasingly low carbon. the membership. We will make the case for our views on climate change and we will be transparent where we differ. And where we can’t reach alignment, we will be prepared to leave. Our aim 4 is to install methane measurement at all our existing major oil and gas processing sites by 2023, publish the data, and then drive a 50% reduction in methane intensity« of our operations. And we will work to influence our joint ventures« to set their own methane intensity targets of 0.2%. In 2020 we set an intensity target of 0.20% by 2025, using a measurement approach. To reduce our methane intensity, we will focus on achieving reductions across our key methane sources. Our performance in 2020 Our methane intensity in 2020 was 0.12%, an improvement from 0.14% in 2019. In 2020 methane emissions from upstream operations, used to calculate our intensity, decreased by 22% to 71.6kt in 2020, down from 92.2kt in 2019. Marketed gas was 3,075bcf in 2020. This reduction in methane intensity was due to the Alaska and bpx energy divestments in 2020 and from SER projects and flaring reductions, the largest reductions being delivered in bpx energy and Angola. Our aim 5 is to increase the proportion of investment we make into our non-oil and gas businesses. Over time, as investment goes up in low and no carbon, we see it going down in oil and gas. We are aiming for up to an eight-fold scaling up of our investment in low carbon energy by 2025 and a ten-fold scaling up by 2030, to around $5 billion a year. In 2020 we invested $750 million, compared to more than $500 million in 2019. See page 22 for more on our investment in line with aim 5. We are involved in advocacy activities related to well-designed policies, primarily carbon pricing in the US, through our support for regional initiatives. bp.com/policyandadvocacy Our aim 7 is to incentivize our global workforce to deliver on our aims and mobilize them to become advocates for net zero. We want to help our employees understand what net zero means and the part they can play – through education and training programmes. We want to incentivize employees, which is why in 2019 we linked our annual cash bonus for eligible employees, including the bp leadership team, to sustainable emissions reductions (SERs). We have exceeded targeted delivery of SERs in both 2019 and 2020, though in 2020, bp decided not to pay an annual bonus due to the prevailing economic and financial environment. In 2020 for senior leaders we increased emphasis on low carbon, moving from 5% to 30% of senior leaders’ equity awards linked to low carbon. And for the bp leadership team, 25% of performance- based pay was linked to delivery of our purpose. The measures for the 2021 annual bonus for the wider workforce are aligned to bp’s strategy and net zero ambition and tied to a balanced scorecard consisting of safety and sustainability, operations and financial measures. In February 2021, we introduced the reinvent bp share award to incentivize our employees in meeting our aims. All employees will receive a one-off grant of either shares or share options that will become available to keep, sell or transfer in the first quarter of 2025. See the Directors’ remuneration report on pages 103-126 for more detail. Five aims to help the world get to net zero Our aim 6 is to more actively advocate for policies that support net zero, including carbon pricing. We have stopped corporate reputation advertising campaigns and this is enabling us to re-direct resources to promote climate policies. In future, any corporate advertising will be to push for well-designed climate policy; communicate our net zero ambition; invite ideas; or build Our aim 8 is to set new expectations for our relationships with trade associations around the globe. We belong to associations that offer opportunities to share good practices and collaborate on issues of importance to our sector. We aim for alignment between our policies and those of trade associations that we are a member of but understand that associations’ positions reflect a compromise of the assorted views of We published our first trade associations review in early 2020, and left three associations where we assessed climate positions as not aligned. Since then, we have made interventions where our views have not aligned – these occurred in the area of carbon pricing with the Canadian Association of Petroleum Producers and the Netherlands Employer Association, VNO-NCV. In 2021 we intend to publish an update on our relationships with trade associations which will focus on our engagement with five partially aligned associations. bp.com/tradeassociations Our aim 9 is to be recognized as an industry leader for the transparency of our reporting. On 12 February 2020, we declared our support for the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD). We intend to work constructively with the TCFD and others – such as the Sustainability Accounting Standards Board – to develop good practices and standards for transparency. See pages 52-55 for our expanded TCFD disclosures. Our aim 10 is to launch a new team to create integrated clean energy and mobility solutions. We launched our regions, cities and solutions team in 2020. It will help countries, cities and corporations around the world decarbonize. We have announced our aim to partner with 10-15 cities globally over the next decade to help them achieve their climate goals. And we will work with three industrial sectors – high tech and consumer products, heavy transport and heavy industries – as they shape their energy transition journeys. In 2020 we’ve formed strategic partnerships with Aberdeen, Houston and Microsoft. We’ve also agreed to provide additional renewable energy to Amazon, helping them toward their ambition to decarbonize. bp.com/RCS bp Annual Report and Form 20-F 2020 51 Sustainability continued Climate change and the environment Recommended disclosure: a. Describe the board’s oversight of climate- related risks and opportunities. The role of the board is to promote bp’s sustainable success for the benefit of its members, generating value for shareholders while having regard to the interests of our other stakeholders, the impact of our operations on the communities where we operate and the environment. In performing this role, the board is responsible for oversight of the overall conduct of the group’s business, which extends to setting our strategy and approach to the energy transition. The board and its associated committees, including the safety and sustainability, audit, people and governance and remuneration committees, where appropriate, have oversight of climate-related matters, which include climate risks and opportunities. They are updated on these matters frequently, a process which is managed by our company secretary’s office, which works closely with teams in bp to develop materials that assist the board or committee to discharge its responsibilities, including those related to climate. In 2020 these processes included formal analysis of bp’s net zero ambition and aims, briefings with subject matter experts, reviews of regulatory correspondence regarding prior year climate disclosures, virtual site visits and the preparation and consideration of corporate reporting documents and AGM materials. During 2020, climate matters were included on the agenda at every board meeting. Agendas are now structured along four distinct pillars: strategy, performance, people and governance. The safety and sustainability committee’s remit was extended from the beginning of 2020 to provide oversight of the effectiveness of the implementation of bp’s sustainability frame. This includes reviewing that appropriate progress is being made against our net zero, people and planet aims. The committee will continue to cover existing sustainability-related activities, including the oversight of operational sustainability risks. The world needs more energy to fuel prosperity and improve standards of living for a growing global population. This energy must be delivered in affordable and reliable ways, but it must also be lower carbon. Climate-related financial disclosures We support the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD), which was established by the Financial Stability Board with the aim of improving the reporting of climate-related risks and opportunities. We announced in 2020 that we intend to work constructively with the TCFD, and others, to develop good practices and standards for transparency. Our latest reporting provides information supporting the TCFD’s recommended disclosures. We responded to the FCA consultation on climate-related financial disclosures and welcome the new listing rule. Governance TCFD recommendation: Disclose the organization’s governance around climate- related issues and opportunities. From 1 January 2021, bp implemented a new, simplified system of sustainability governance encompassing the board, its associated committees and the leadership team. This structure will enhance oversight of bp’s new sustainability frame, which focuses on three areas: net zero, people and planet. The remit of the board and its committees under our new governance framework is set out on page 88. Terms of reference for the board and its committees are available at bp.com/governance. 52 bp Annual Report and Form 20-F 2020 The role of the audit committee is to monitor the effectiveness of bp’s financial reporting, systems of internal control and risk management, and the integrity of bp’s external and internal audit processes. In fulfilling this purpose, the committee has oversight of financial disclosure, including TCFD reporting. The role of the remuneration committee is to recommend to the board the remuneration policy for executive directors and the leadership team. It also reviews workforce remuneration and monitors related policies, satisfying itself that incentives and rewards are aligned to bp’s strategy, culture and long-term sustainable success. This includes climate- related matters. The role of the people and governance committee (formerly the nomination and governance committee) is to oversee a diverse succession pipeline and to review workforce policies and practices, monitoring their consistency with bp’s purpose, strategy and values. This helps ensure that we have the right people to deliver our strategy and net zero ambition. Pursuing a strategy consistent with the Paris goals Strategy has been the core focus of every board meeting since the beginning of 2019. Throughout 2020 the board worked closely with the leadership team in developing our new strategy. In August 2020 the chairman outlined the key judgements the board had applied to their decision making regarding bp’s strategy, financial frame and investor proposition. As a result, the board considers that the strategy allows us to be flexible to adapt to market changes and scenarios to remain consistent with the Paris goals. The role of the board in evaluating material capex consistency with Paris The board assesses the impact of portfolio changes, such as strategic acquisitions and the allocation of capital. It also considers specific investment cases which have been approved by the resource commitment meeting, see page 29. Strategic report Recommended disclosure: b. Describe management’s role in assessing and managing climate-related risks and opportunities. The assessment and management of climate- related matters is embedded across bp at various levels and delegated authority flows down from the board, see page 29. From 1 January 2021, a new executive level governance forum, the group sustainability committee, will provide internal oversight of bp’s progress against the aims and objectives in the sustainability frame, including net zero. This group is chaired by the EVP strategy & sustainability (S&S) and comprises members of the bp leadership team. The group sustainability committee plans to meet on a quarterly basis to review progress within entities against the sustainability frame and decide on critical strategic positions related to sustainability that present risks or opportunities to delivery. The EVP S&S will report to the main board and committees as required. The group operational risk committee will continue to provide oversight of safety and operational risk management performance for the group, where appropriate, which includes sustainability-related risks such as modern slavery and severe weather. Climate-related matters were discussed at each of the leadership team meetings in 2020, including the development of bp’s net zero ambition and aims ahead of discussion with the board. The leadership team is supported by bp’s senior-level leadership and their respective teams, with dedicated business and functional expertise focused on climate-related matters. This includes our health, safety, environment and carbon, strategy and sustainability and group policy and economics teams. Alignment between group, business and functional leaders is fostered through cross- functional bodies. Climate governance: management of climate-related matters As at 1 January 2021 bp board level Board Safety and sustainability committee Audit committee Remuneration committee People and governance committee bp leadership team Group sustainability committee Chair: EVP S&S Oversight of sustainability matters. EVP level Issues and advocacy meeting Chair: EVP S&S, EVP C&A Policy and advocacy issues, including those related to climate matters. SVP level Corporate reporting steering Chair: CFO, EVP C&A, EVP S&S Development and oversight of financial and non-financial reporting, including TCFD. Group operational risk committee Chair: CEO Oversight of the group’s safety and operational risk management performance, safety agenda and priorities. Sustainability forum Chair: SVP sustainability Focused on sustainability plans and progress. Brings together previously separate committees, including carbon steering group, policy and advocacy, and human rights. Production & operations carbon table Chair: SVP HSE & carbon, P&O Focuses on the delivery of lower carbon plans in P&O – particularly in relation to net zero aims 1 and 4. Cross bp meetings and forums Meetings and forums to allow cross-group discussions and integration. bp Annual Report and Form 20-F 2020 53 Strategic implications of climate change In the bp Energy Outlook 2020 we describe the potential implications of climate change and the energy transition on both primary energy demand and the energy system, through three long-term scenarios: Rapid, Net Zero and Business-as-usual. These are summarized on page 11 and further analysis by country and region, energy sector and fuel type can be found in the bp Energy Outlook, available at bp.com/energyoutlook. The transition to a lower carbon economy presents both risks and significant business opportunities for bp. Climate-related physical and transition risks are managed and reported as part of our group-wide risk management process described on pages 64-66. Climate-related risks and opportunities associated with the energy transition were taken into consideration alongside other inputs in developing our new ambition, aims and strategy. For more information about how our new organizational model and financial reporting segments see pages 36-38. For more on our new financial frame see page 22. Risk management TCFD recommendation: Disclose how the organization identifies, assesses and manages climate-related risks. Recommended disclosure: a. Describe the organization’s processes for identifying and assessing climate-related risks. bp’s risk management system, described on page 64, is designed to address all types of risks including our principal risks and uncertainties described in Risk factors on page 67. As part of this system our operating businesses, integrators and enablers (see page 36) are responsible for identifying, assessing, managing, and monitoring risks associated with their business area. Risks are assessed in line with bp’s risk management policy and this includes an impact and likelihood assessment which supports relative prioritization. Climate-related risks are classified in alignment with TCFD’s description of physical and transition risks: Strategic resilience We believe our strategy is resilient to the range of energy transition pathways and scenarios including Paris, see page 11. Physical risks – risks related to the physical impacts of climate change including event- driven risks such as changes in the severity and/or frequency of extreme weather events. For more information on our financial resilience, including our revised long-term price assumptions and impairment testing, see page 28. For information on the resilience of our individual investments, including our governance structure and investment process, see page 29. Our strategy is validated annually by the board to ensure it remains relevant and resilient, as part of our standard governance processes. Elements of the strategy may be refreshed earlier if there are significant changes in external or internal environment. Transition risks – risks related to the transition to a lower carbon economy including policy and legal, technology, markets and reputational risks. The potential material impacts of such climate- related risks are described in Risk factors, see page 67. Recommended disclosure: b. Describe the organization’s processes for managing climate-related risks. c. Describe how processes for identifying, assessing and managing climate-related risks are integrated into the organization’s overall risk management. Risks which may be identified include potential effects on operations at asset level, performance at business level and developments at regional level from extreme weather or the transition to a lower carbon economy. Sustainability continued Strategy TCFD recommendation: Disclose the actual and potential impacts of climate-related risks and opportunities on the organization’s business, strategy and financial planning where such information is material. Recommended disclosure: a. Describe the climate-related risk and opportunities that the organization has identified over the short, medium, and long term. b. The impact of climate-related risks and opportunities on the organization’s businesses, strategy, and financial planning. c. The resilience of the organization’s strategy, taking into consideration different climate- related scenarios, including a 2°C or lower scenario. Our strategy to become an Integrated Energy Company, and our net zero ambition and aims are set out on pages 2-3, 15 and 49. In developing this strategy, the board and leadership team consider a wide range of opportunities and risks across three discrete time horizons: Short term (to 2025): the next five years are defined by detailed business and financial plans, which are performance managed in delivery of our 2025 targets. Medium term (to 2030): looking out 10 years enables us to think beyond the short-term to consider signposts and milestones towards the longer-term scenarios, enabling us to adjust course if required. Long term (to 2050): recognizing the wide range of uncertainties, we use a scenario planning approach to help us explore possible pathways for the energy transition over the next 30 years, as the world moves towards net zero. This includes consideration of changes in policy, societal preferences, economic growth and technological progress. For more detail on our approach and how it informs our strategy, see page 11. 54 bp Annual Report and Form 20-F 2020 Strategic report As part of our annual planning process we review the group’s principal risks and uncertainties. Climate change and the transition to a lower carbon economy has been identified as a principal risk, see page 68. This covers various aspects of how risks associated with the energy transition could manifest. Similarly, physical climate-related risks such as extreme weather are covered in our principal risks related to safety and operations. Our processes for identifying, assessing, managing and monitoring climate-related risks are integrated into bp’s risk management policy and the associated risk management procedures. Examples of how physical and transition climate-related risks are identified, assessed and managed: In the North Sea and Gulf of Mexico, regions more prone to severe weather conditions, our offshore facilities monitor meteorological and oceanographic conditions through collection of measurements at these facilities. These data are collated and periodically compared against the Basis of Design for the facility. If significant differences are observed, then this may trigger an update to the Basis of Design, prompting action to re-assess risks such as structural integrity and station-keeping and if necessary, implement additional risk mitigations. Updates may also occur as a result of other new knowledge, analysis methods and data. Transition risks are typically identified and managed by business, regional or central teams. For example, our strategy & sustainability team has identified risks relating to evolving policies across different regions. They work with bp’s leadership as well as with both central and regional legal teams, communications & advocacy and external advisors to manage and monitor these risks. Metrics and targets TCFD recommendation: Disclose the metrics and targets used to assess and manage relevant climate-related risks and opportunities where such information is material. We present the principal group-wide metrics and targets used to assess and manage climate- related risks and opportunities below. This also addresses the CA100+ resolution requirement to disclose the company’s principal metrics and relevant targets or goals consistent with the Paris goals. We consider this to cover the principal metrics used at group level to help monitor progress on delivery of our strategic consistency with the Paris goals – including our net zero aims. In addition, we report on selected energy group illustrative metrics«. A reference table of these can be found at bp.com/sustainability. Our group-wide principal metrics and relevant targets/goals TCFD recommended disclosures Section of report a. Disclose the metrics used Our strategic focus areas, including low carbon electricity and energy and convenience and mobility Our financial frame: investing at scale in the energy transition Our investor proposition: 2021 guidance Price assumptions Investment criteria Evaluating material new capex for consistency with Paris goals KPIs Sustainability: water and biodiversity metrics Remuneration Directors’ remuneration report Incentivizing our employees to advocate for net zero Sustainability: GHG emissions Sustainability: net zero aims by the organization to assess climate-related risks and opportunities in line with its strategy and risk management process b. Disclose Scope 1, Scope 2, and, if appropriate, Scope 3 greenhouse gas (GHG) emissions, and the related risks. c. Describe the targets used by the organization to manage climate-related risks and opportunities and performance against targets. Where 2025, 2030, 2050 metrics, page 18 (in table). Five aims to get to net zero, page 49 (in table). Sector specific IRR hurdle rates for transition and low carbon investments, page 22. Balanced investment criteria, page 30. Renewable power returns, page 22. Total capital expenditure, page 23. Key investment appraisal assumptions, page 28 (in table). Carbon price (in table). Investment economics, page 30. Quantitative evaluations, page 31. Investment economics: IRR and discounted payback. Environment and sustainability: operational carbon intensity«. Key performance indicators, page 39. Managing our environmental impacts, page 56. Director’s remuneration report, page 103. 2020 annual bonus outcome, page 110. 2021 remuneration policy on a page, page 124. Aim 7, page 51. SECR table, page 50. Ratio of Scope 1 and 2 emissions: gross production, page 50. TCFD: risk management, page 54. Risk factors, page 67. For further GHG metrics see bp.com/ESGdata Aim 1-5 summary of 2020 performance, 2025 targets and 2030 aims, page 49. Aim 1 performance (Scope 1 and 2), page 49. Aim 2 performance (Scope 3), page 49. Aim 3 performance (emissions from the carbon in our upstream oil and gas production), page 50. Aim 4 performance (methane) page 51. bp Annual Report and Form 20-F 2020 55 Sustainability continued Managing our environmental impacts Our health, safety, security and environmental (HSSE) goals are: no accidents, no harm to people and no damage to the environment. We work hard to avoid, mitigate and manage our environmental and social impacts over the life of our operations. The way our businesses around the world are expected to understand and manage their environmental and social impacts is set out in our operating management system« (OMS). This includes requirements on engaging with stakeholders who may be affected by our activities. In planning our projects, we identify potential impacts from our activities in areas such as land rights, water use and protected areas. We use the results of this analysis to identify actions and mitigation measures and look to implement these in project design, construction and operations. Our OMS requires each of bp’s operating businesses and functions to create and maintain its own OMS handbook, describing how it will carry out its local operating activities. Through self-verification, local business processes are reviewed and areas for improvement are prioritized, allowing focus on delivering safe, reliable and compliant operations. Air emissions We monitor our air emissions and put measures in place to reduce the potential impact of our activities on local communities. As part of our aim 19 we plan to evaluate the air emissions from our global operating facilities to better understand how they may be affected while advancing our net zero aims for GHG emissions. For more on air emissions, see the bp Sustainability Report 2020. Caring for our planet Our sustainability frame includes a focus on making a positive difference to the environment in which we operate. The scope of our care for our planet aims covers biodiversity, water management, nature-based solutions including those that reduce or remove carbon, circularity and sustainable purchasing. Water We actively manage our freshwater demands in areas of stress and scarcity. Based on analysis using the World Resources Institute Aqueduct Global Water Risk Atlas, four of our 24 major operating sites were located in regions with high or extremely high water stress in 2020, with another four in areas of medium to high water stress. This number reduces to three in regions with high or extremely high water and three in regions of medium to high water stress, if our bp petrochemicals and other 2020 divestments are excluded. In 2020 we saw a 2% fall in freshwater withdrawals and a 17% fall in freshwater consumption compared to 2019. This was largely due to the divestment of our Alaskan operation in 2020, the formation of the bp Bunge non- operated joint venture from bp operated biofuels and biopower businesses at the end of 2019 and a reduction in freshwater use in our bpx energy operations during 2020. We have set an aim to be water positive by 2035. We aim to replenish more freshwater than we consume in our operations. We will do this by being more efficient in operational freshwater use and effluent management, and by collaborating with others to replenish freshwater in stressed and scarce catchment areas where we operate. Biodiversity We have set an aim to enhance biodiversity, focusing on making a positive impact through our actions to restore, maintain and enhance biodiversity where we work. We expect that from 2022 all new bp projects in scope will have plans in place aiming to achieve net positive impact (NPI), with a target for 90% of actions to be delivered within five years of project approvala. We also aim to enhance biodiversity at our major operating sites and support biodiversity restoration and sustainable use of natural resource projects in the countries where we have current or growing investments. In 2020 we launched our new biodiversity position and focused on sharing it with our stakeholders and putting in place the resources to deliver it. We also started work on defining our NPI methodology with Fauna & Flora International, which we expect to complete at the end of 2021. bp.com/biodiversity Our aims to care for our planet: Aim 16: enhance biodiversity. Aim 17: water positive. Aim 18: championing nature-based solutions. Aim 19: unlock circularity. Aim 20: sustainable purchasing. bp.com/planet a Applicable projects that have the potential for significant direct impacts on biodiversity. Only actions that are intended to be delivered within five years in accordance with the NPI methodology are included. The 30% and 90% targets apply in aggregate across all applicable projects that meet the relevant timeframes from the final project approval (and are not targets for individual projects). 56 bp Annual Report and Form 20-F 2020 Strategic report People and society bp’s success depends on having a talented and diverse workforce that represents the communities we serve. Number of employees at 31 Decembera Upstream Downstream Other businesses and corporate 2020 2019 2018 13,700 16,600 16,900 42,700 41,300 44,300 8,600 9,200 13,400 Total 63,600 70,100 73,000 a Reported to the nearest 100. For more information see Financial statements – Note 35. Our people are the most important element of our success. We need a motivated, engaged, and diverse workforce to deliver our purpose and strategy. We promote a culture that generates the diversity of thought, approach and ideas needed to reimagine energy and move to a low carbon environment. The people and culture committee helps facilitate the CEO’s oversight of people related matters. In 2020 the committee discussed key items, including our remuneration policy, progress in our diversity and inclusion programme, employee engagement, workplace, our talent and learning programmes and long-term people priorities. The committee also spent significant time focusing on the reinvent bp programme and related design and selection activities. Attraction and retention We aim to recruit talented people from diverse backgrounds, and invest in training, development and competitive rewards for all our people. We invest in employee development – with a focus on driving safe, reliable and compliant operations, and on building technical, functional and leadership capability. This includes a range of development opportunities for our people through a mix of on-the-job learning, developmental relationships with mentors, managers and peers, and training delivered face-to-face, virtually and through simulation or e-learning. Reinvent bp selection process As part of our work to reinvent bp we are running selection processes and considering in-scope employees for roles within the new organizational design, with the outcome that around 10,000 employees will leave bp by early 2022. The selection processes focus on office-based non-operational roles. We have put robust steps in place to help ensure that the selection processes are fair and objective and that employees are supported before and after receiving their selection outcome confirmation. We have appointed and coached neutral observers to challenge selection decisions and help mitigate unconscious bias and trained line managers on how to undertake fair and meritocratic selection decisions. Where roles are impacted by the selection processes, bp adheres to local laws. Line managers were given supporting resources for the notification process, including guides, training and scripts on communicating outcomes compassionately. We will continue to provide these resources throughout the remaining selection processes. Employees were provided with supporting resources, including guidance on preparing for change, mental wellbeing, preparing for outcome conversations, and dealing with uncertainty. Employees were encouraged to use the Employee Assistance Programme throughout. We also established our myFuture programme, which provides tools, resources and support to help leavers navigate the next stage in their career or phase of life. See pages 36-37 for more on reinvent bp and our new organizational model. Diversity Our mission is to create an environment in which everyone can bring their best and true selves to work, to reach their potential and support the reinvention of bp. Ethnic diversity In 2020 we published our UK and US frameworks for action to help combat racial injustice in bp. Both frameworks have three key focus areas: transparency, accountability and talent. Those actions will include: publishing a comprehensive global diversity & inclusion (D&I) report in 2021, embedding expectations and metrics on D&I delivery in our operating plans, reporting externally on our UK ethnicity pay gap annually and doubling our spend with US-based diverse suppliers by 2023. A total of 30% of our group leaders came from countries other than the UK and the US in 2020 (2019 25%). Gender equality The gender balance across bp as a whole is improving, with women representing 39% of bp’s total population (2019 38%). 38% of our 120 newly-appointed extended leadership team are women and our goal is to increase this. At the end of 2020 we had five female directors (2019 5) on our board. Our people and governance committee remains mindful of diversity when considering potential candidates. For more information on the composition of our board, see page 74. Workforce by gender As at 31 December 2020 Board directors Leadership team Group leaders Subsidiary directors All employees Male Female Female % 6 8 193 5 4 77 1,351 38,826 284 24,719 45 33 29 17 39 bp.com/ukgenderpaygap Inclusion To promote an inclusive culture we provide leadership training and support employee-run advocacy groups in areas such as gender, ethnicity, sexual orientation and disability. As well as bringing employees together, these groups support our recruitment programmes and provide feedback on the potential impact of policy changes. Each group is sponsored by a senior executive. We aim to provide equal opportunity in recruitment, career development, promotion, training and reward for all employees – regardless of ethnicity, national origin, religion, gender, age, sexual orientation, marital status, disability, or any other characteristic protected by applicable laws. Where existing employees become disabled, our policy is to engage and use reasonable accommodations or adjustments to enable continued employment. Employee engagement Our managers hold team and one-to-one meetings with their team members, complemented by formal processes through works councils in parts of Europe. We regularly communicate with employees on factors that affect bp’s performance, and seek to maintain constructive relationships with labour unions formally representing our employees. bp Annual Report and Form 20-F 2020 57 We incorporate the UN Guiding Principles on Business and Human Rights, which set out how companies should prevent, address and remedy human rights impacts, into our business processes. When working to remediate any impacts on the rights of local communities we are open to co-operating in good faith to agree remedial actions through state-led mechanisms such as the Organisation for Economic Co-operation and Development National Contact Points. We recognize the importance of accessible and effective operational-level grievance mechanisms in addressing our impacts. bp.com/humanrights Our aims to improve people’s lives: Aim 11: more clean energy. Aim 12: just transition. Aim 13: sustainable livelihoods. Aim 14: greater equity. Aim 15: enhance wellbeing. bp.com/people Sustainability continued To understand what our employees think and feel about bp, we run an annual ‘Pulse’ survey as well as ‘Pulse Live’ surveys, which enable us to monitor changes in employee sentiment on a weekly basis. The overall employee engagement positivity score in our 2020 annual survey was 64% (2019 65%). Pride in working for bp was 75% (2019 75%). Employees participating in the 2020 Pulse survey told us they strongly supported the launch of bp’s new purpose and ambition in February and the strategy announcement in August. Initial positivity over the strategy waned in December, with employees expressing anxiety about the reinvent process and economic uncertainty during 2020. Most participants felt confident in bp’s approach to managing the impact of the COVID-19 pandemic. Employees also told us we should focus on addressing workload, supporting health and wellbeing and being transparent about the new structure. Share ownership We continue to encourage employee share ownership and have a number of employee share plans in place. For example, we operate a ShareMatch plan in more than 50 countries, matching bp shares purchased by our employees. We also make annual share awards as part of our total reward package all for senior and mid-level employees globally, and a portion of our more junior professional grade staff. In February 2021, we introduced the reinvent bp share award to incentivize our employees in meeting our aims. All employees will receive a one-off grant of either shares or share options that will become available to keep, sell or transfer in the first quarter of 2025. Wellbeing and mental health Mental health and physical wellbeing are priorities for us and we recognized that the COVID-19 pandemic had direct and indirect consequences for our employees and their families. We offered access to a range of facilities and services, including support through our well-established Employee Assistance Programme and new interventions, including providing access to the Headspace app to both employees and their partners. Our annual global physical wellbeing programme had 5,887 participants from 59 countries, with positive feedback on helping keep teams connected and keeping people physically active. We continue to improve our systematic management of health data points and sources, to identify where we can target preventive interventions and provide training, support and resources to help improve employee wellbeing and performance. We believe wellbeing at work is becoming part of the bp language – a critical part of caring for our people and the communities in which we operate. Value to society Improving people’s lives One of our sustainability frame areas of focus is to improve people’s lives. We have set five people aims focusing on where bp can make the biggest difference. We want people to benefit from our presence in their local communities, wherever we run projects or operate. This includes collaborating with local communities to support sustainable livelihoods and build greater resilience as part of a just transition. Our work on sustainable livelihoods to date supports several of the UN Sustainable Development Goals, in particular on education, health and economic growth as drivers for sustainable livelihoods. Human rights We believe everyone deserves to be treated with fairness, respect and dignity. At bp we strive to conduct our business in a responsible way, respecting the human rights of our workers and everyone we come into contact with. Our human rights policy and our code of conduct help us do that. See page 63 for information on how we updated our business and human rights policy in 2020. We respect internationally recognized human rights as set out in the International Bill of Human Rights and the International Labour Organization’s Declaration on Fundamental Principles and Rights at Work, including the core Conventions. These include the rights of our workforce and those living in communities potentially affected by our activities. 58 bp Annual Report and Form 20-F 2020 Safety Safety is our core value and permeates everything we do. In 2020 it remained our first priority throughout our transformation process and the COVID-19 pandemic. Fundamentally, safety is about caring for our employees and the communities in which we operate. Process safety events Number of incidents 100 84 80 60 40 20 0 61 56 16 18 16 72 26 53 17 2016 2017 2018 2019 2020 Tier 1 Tier 2 Recordable injury frequency Workforce incidents per 200,000 hours worked 0.33 0.21 0.35 0.34 0.30 0.20 0.18 0.19 0.4 0.3 0.2 0.1 0 2016 2017 2018 2019 2020 Workforce 0.211 Employees 0.194 Contractors 0.222 0.218 0.202 0.229 0.198 0.152 0.233 0.166 0.128 0.193 0.132 0.094 0.163 American Petroleum Institute US benchmark* International Association of Oil & Gas Producers benchmark* * API and OGP 2020 data reports not available until May 2021. Strategic report We have taken steps to help our employees operate safely during the COVID-19 pandemic. Tragically, we saw one fatality related to illness, rather than a process safety incident, in our operations in 2020. This occurred in December in our Indonesian operations when an employee died following COVID-19 infection contracted on site. We deeply regret this loss and offer our deepest condolences to the employee’s family. See page 8 for more information. Keeping people safe All our employees and contractors have the responsibility and the authority to stop unsafe work. Our safety rules guide our workers on staying safe while performing tasks with the potential to cause most harm. The rules are aligned with our operating management system (OMS) and focus on areas such as working at heights, lifting operations and driving safety. We monitor and report on key workforce personal safety metrics in line with industry standards. We include both employees and contractors in our data. We have seen improvements in personal safety in 2020 and while this may in part be a consequence of decreased activity during the COVID-19 pandemic, we also believe that other, more intentional factors, are involved – namely the groundwork we have done over the past few years, including our deepening focus on safety leadership, human performance, and the effectiveness of our safety processes such as permit-to-work. Our recordable injury frequency, reduced from 0.166 in 2019 to 0.132 in 2020. There is always more we can do, and we remain focused on further improving our results. Recordable injury frequencya Day away from work case frequencyb Severe vehicle accident rate 2020 2019 2018 0.132 0.166 0.198 0.044 0.047 0.048 0.01 0.05 0.04 a Incidents that result in a fatality or injury per 200,000 hours worked. b Incidents that result in an injury where a person is unable to work for a day (shift) or more per 200,000 hours worked. bp Annual Report and Form 20-F 2020 59 Sustainability continued Managing safety bp-operated businesses are responsible for identifying and managing operating risks and bringing together people with the right skills and competencies to address them. Our safety and operational risk assurance team works alongside bp-operated businesses to provide oversight and technical guidance, while our group audit team visits sites on a risk-prioritized basis to check how they are managing risks. Our operating management system Our OMS is a group-wide framework designed to help us manage risks in our operating activities and drive performance improvements. It brings together bp requirements on health, safety, security, the environment, social responsibility and operational reliability, as well as related issues, such as maintenance, contractor relations and organizational learning, into a common management system. Our OMS also helps us improve the quality of our activities by setting a common framework that our operations must work to. We review and amend these requirements from time to time to reflect our priorities. Any variations in the application of our OMS, in order to meet local regulations or circumstances, are subject to a governance process. Recently acquired operations need to transition to our OMS. Preventing incidents We carefully plan our operations, with the aim of identifying potential hazards and having rigorous operating and maintenance practices applied by capable people to manage risks at every stage. We design our new facilities in line with process safety, good design and engineering principles. We track our safety performance using industry metrics such as the American Petroleum Institute recommended practice 754 and the International Association of Oil & Gas Producers recommended practice 45. Our process safety performance improved from 2019 and was roughly comparable to 2018 and 2017. There were 35% fewer tier 1 process safety events in 2020 compared to 2019, but our performance was broadly in line with the previous three years. We also recorded 26% fewer tier 2 process safety events compared to 2019, lower than the previous 10 years. The combined tier 1 and tier 2 process safety events were down 29% in 2020 compared to 2019. We investigate incidents including near misses. And we use leading indicators, such as inspections and equipment tests, to monitor the strength of controls to prevent incidents. 60 bp Annual Report and Form 20-F 2020 Tier 1 and tier 2 process safety eventsa Oil spills – numberb Oil spills contained Oil spills reaching land and water Oil spilled – volume (thousand litres) Oil unrecovered (thousand litres) 2020 2019 2018 70 98 72 121 152 124 70 46 784 494 90 58 63 57 710 538 300 131 a Tier 1 process safety events are losses of primary containment of greatest consequence – such as causing harm to a member of the workforce, costly damage to equipment or exceeding defined quantities. Tier 2 events are those of lesser consequence. b Number of spills greater than or equal to one barrel (159 litres, 42 US gallons). Emergency preparedness The scale and spread of bp’s operations means we must be prepared to respond to a range of possible disruptions and emergency events, such as the COVID-19 pandemic. We maintain disaster recovery, crisis and business continuity management plans and work to build day-to- day response capabilities to support local management of incidents. Security We monitor for hostile actions that could harm our people or disrupt our operations. These actions might be connected to political or social unrest, terrorism, armed conflict or criminal activity. We take these potential threats seriously and assess them continuously. Our 24-hour response information centre in the UK uses state-of-the-art technology to monitor evolving high-risk situations in real time. It helps us to assess the safety of our people and provide them with practical advice if there is an emergency. Cyber security The severity, sophistication and scale of cyber attacks continues to evolve. The increasing digitalization and reliance on IT systems makes managing cyber risk an even greater priority for many industries, including our own. The risk comes from a variety of cyber-threat actors, including nation states, criminals, terrorists, hacktivists and insiders. As with previous years, we’ve experienced threats to the security of our digital infrastructure, but none of these had a significant impact on our business in 2020. We have a range of measures to manage this risk, including the use of cyber-security policies and procedures, security protection tools, continuous threat monitoring and event detection capabilities, and incident response plans. We also conduct exercises to test our response to and recovery from cyber attacks. To encourage vigilance among our staff, our cyber-security training and awareness programme covers topics such as phishing and the correct classification and handling of our information. We collaborate closely with governments, law enforcement and industry peers to understand and respond to new and emerging threats. Working with contractors Through documents that help bridge between our policies and those of our contractors, we define the way our safety management system co-exists with those of our contractors to manage risk on a site. For our contractors facing the most serious risks, we conduct quality, technical, health, safety and security audits before awarding contracts. Once they start work, we continue to monitor their safety performance. Our OMS includes requirements and practices for working with contractors. Our standard model contracts include health, safety and security requirements. We expect and encourage our contractors and their employees to act in a way that is consistent with our code of conduct and take appropriate action if those expectations, or their contractual obligations, are not met. Our partners in joint arrangements« In joint arrangements where we are the operator, our OMS, code of conduct and other policies apply. We aim to report on aspects of our business where we are the operator – as we directly manage the performance of these operations. We monitor performance and how risk is managed in our joint arrangements, whether we are the operator or not. Where we are not the operator, our OMS is available as a reference point for bp businesses when engaging with operators and co-venturers. We have a group framework to assess and manage bp’s exposure related to safety, operational and bribery and corruption risk from our participation in these types of arrangements. Where appropriate, we may seek to influence how risk is managed in arrangements where we are not the operator. Strategic report Tax transparency We comply with tax laws in a responsible manner, pay and report our taxes on time and have open and constructive conversations with stakeholders, including governments and tax authorities. And we contribute to initiatives that simplify and improve tax regimes to encourage investment and sustainable growth and support the energy transition. We are committed to being transparent about our tax principles and the taxes we pay. We paid $3.3 billion in corporate income and production taxes to governments (2019 $6.9 billion). In 2020 we endorsed the B Team Responsible Tax Principles and we published Our tax report 2019. The report provides more detailed information on how we approach tax matters and the tax payments we make. New disclosures in our tax report include the total tax contribution for our global operations. This covers: all our business activities and details the taxes we pay directly to governments on our own behalf, along with taxes we collect and pay to governments on behalf of others; financial and tax data from our OECD country-by-country report, summary activities of bp subsidiaries by country and details of bp companies located in countries considered to be low tax jurisdictions. bp is a founding member of the Extractive Industries Transparency Initiative (EITI), which supports the disclosure of payments made to and received by governments in relation to oil, gas and mining. Through EITI we work with governments, NGOs and international agencies to improve transparency. bp.com/tax We provide training to employees appropriate to the nature or location of their role. Around 7,700 employees completed anti-bribery and corruption training in 2020 (2019 ~11,000). We assess any exposure to bribery and corruption risk when working with suppliers and business partners. Where appropriate, we put in place a risk mitigation plan or we reject them if we conclude that risks are too high. We also conduct anti-bribery compliance audits on selected suppliers when contracts are in place. Many of our production & operations projects conduct supplier audits to assess their conformance with our anti-bribery and corruption contractual requirements. We take corrective action with suppliers and business partners that fail to meet our expectations, which may include terminating contracts. In 2020 we issued 35 audit reports (2019 25). While our audit process was disrupted in 2020 due to the COVID-19 pandemic, we continued to engage suppliers and communicate our expectations for managing bribery and corruption risk on behalf of bp. For example, our customers & products business delivered a regional annual contractor forum digitally, to provide awareness of bribery and corruption risks. Political donations and activity We prohibit the use of bp funds or resources to support any political candidate or party. We recognize the rights of our employees to participate in the political process and these rights are governed by the applicable laws in the countries where we operate. The way in which we interact with those governments depends on the legal and regulatory framework in each country. Our stance on political activity is defined in our code of conduct. In the US we provide administrative support for the bp employee political action committee (PAC), which is a non-partisan committee that encourages voluntary employee participation in the political process. All bp employee PAC contributions are reviewed for compliance with federal and state law and are publicly reported in accordance with US election laws. The PAC paused all contributions for six months beginning in January 2021. During this time the PAC will re-evaluate its criteria for candidate support. Business ethics and accountability Our values and code of conduct Our values of safety, respect, excellence, courage and one team represent the qualities and actions we wish to see in bp. They inform how we do business and the decisions we make. We use these values as part of our recruitment, promotion and individual performance management processes. Our code of conduct is based on our values and sets clear expectations for how we work at bp. It applies to all bp employees and members of the board. Employees, contractors or other third parties who have a question about our code of conduct or see something that they feel is unethical or unsafe can discuss this with their managers, supporting teams, works councils (where relevant) or through OpenTalk, a confidential and anonymous helpline operated by an independent company. We received more than 1,600 concerns or enquiries through these channels in 2020 (2019 1,800). The most commonly raised concerns were related to the ‘Our people’ section of our code of conduct. The section addresses issues such as harassment, equal opportunity, and diversity and inclusion. We take steps to identify and correct areas of non-conformance and take disciplinary action where appropriate. In 2020 our businesses dismissed approximately 50 bp employees for non-conformance with our code of conduct or unethical behaviour (2019 82a). This excludes dismissals of contractors and vendors, and staff employed at our retail service stations. Anti-bribery and corruption We operate in parts of the world where bribery and corruption present a high risk. We have a responsibility to our employees, our shareholders and the countries and communities in which we do business to be ethical and lawful in all our work. Our code of conduct explicitly prohibits engaging in bribery or corruption in any form. Our group-wide anti-bribery and corruption policy and procedures include measures and guidance to assess risks, understand relevant laws and report concerns. They apply to all bp-operated businesses. a 2019 figure differs from the 2019 figure (74) reported in the bp Annual Report and Form 20-F 2019 to reflect backdated dismissal decisions (concerns where dismissals were not known or recorded until after the 2019 report was published), heliport spot check dismissals and changes to dismissal decisions. bp Annual Report and Form 20-F 2020 61 Sustainability continued TCFD index table Our expanded TCFD disclosures can be found on the following pages. TCFD recommended disclosure Governance Disclose the organization’s governance around climate-related issues and opportunities. Strategy Disclose the actual and potential impacts of climate-related risks and opportunities on the organization’s business, strategy and financial planning where such information is material. Risk management Disclose how the organization identifies, assesses and manages climate-related risks. Metrics and targets Disclose the metrics and targets used to assess and manage relevant climate-related risks and opportunities where such information is material. a. Describe the board’s oversight of climate-related risks and opportunities. Where reported Page 52. b. Describe the management’s role in assessing and managing climate related risks and opportunities. Page 53. a. Describe the climate-related risks and opportunities the organization has identified over the short, medium, and long term. b. Describe the impact of climate-related risks and opportunities on the organization’s businesses, strategy, and financial planning. c. Describe the resilience of the organization’s strategy, taking into consideration different climate-related scenarios, including a 2°C or lower scenario. a. Describe the organization’s processes for identifying and assessing climate-related risks. b. Describe the organization’s processes for managing climate-related risks. c. Describe how processes for identifying, assessing, and managing climate-related risks are integrated into the organization’s overall risk management. a. Disclose the metrics used by the organization to assess climate-related risks and opportunities in line with its strategy and risk management process. b. Disclose Scope 1, Scope 2, and, if appropriate, Scope 3 GHG emissions, and the related risks. c. Describe the targets used by the organization to manage climate-related risks and opportunities and performance against targets. Pursuing a strategy that is consistent with the Paris goals, pages 26-27. Strategy – page 54. Risk factors, pages 67-70. Risk factors, pages 67-70 – description of principal risks. Strategy – page 54. Our strategy, page 15. Pursuing a strategy that is consistent with the Paris goals, pages 26-27. Strategy – page 54. Risk management – pages 54-55. How we manage risk, pages 64-66. Risk factors – page 67. Risk management, pages 54-55. How we manage risk, pages 64-66. Risk management, pages 54-55. How we manage risk, pages 64-66. Risk factors – pages 67-70. Our strategic focus areas and metrics, pages 18 and 19. Our group-wide principal metrics and relevant targets – page 55. GHG emissions data – pages 49-50. Our net zero targets and aims at a glance – pages 49-51. Sustainability at bp More information on our sustainability reporting. More information on our sustainability performance bp.com/sustainability Key environmental, social and governance dataa bp.com/ESGdata For our mapping to key sustainability frameworks and standards, including SASB and GRI, see bp.com/reportingcentre a Selected sustainability information in the ESG datasheet was subject to limited assurance by Deloitte LLP in accordance with the International Standard for Assurance Engagements (“ISAE”) 3000 (Revised). 62 bp Annual Report and Form 20-F 2020 Our stakeholders How we engage with our stakeholders Strategic report Throughout bp we engage with a wide variety of stakeholders on a regular basis. This engagement informs our thinking and decision making. Some examples of our engagement in 2020 are set out below. Section 172 statement In accordance with the requirements of section 172 of the Companies Act 2006 (‘the Act’), the directors consider that, during the financial year ended 31 December 2020, they have acted in a way that they consider, in good faith, would most likely promote the success of the company for the benefit of its members as a whole, having regard to the likely consequences of any decision in the long term and the broader interests of other stakeholders, as required by the Act. See table on pages 82-83 for more information in support of this statement, including a description of the board’s activities during 2020. Employees Monitoring employee sentiment We use our ‘Pulse’ survey and weekly ‘Pulse Live’ surveys to gather feedback from employees, including their perceptions of work demands and leadership support. The employee engagement score is a key performance indicator for bp, see page 41. Responding to feedback When our ‘Pulse Live’ and Employee Assistance platforms showed increased anxiety in employees, our CEO Bernard Looney led a series of live webcasts, including one focused on reducing mental health stigma and encouraging employees to ask for help. We also increased the frequency of mental health awareness training for managers. Keeping connected through webcasts CEO Bernard Looney hosted regular ‘Keeping Connected’ webcasts to discuss important topics with members of the leadership team and subject matter experts such as our partner Equinor’s EVP, New Energy Solutions, and our vice president health and wellbeing, Dr Richard Heron. The sessions included a live Q&A section where employees could ask questions, anonymously if desired, of the CEO and webcast guests. See page 86 for more on how the board and senior management team engaged with stakeholders throughout the year. Investors Developing our new strategy, financial frame and investor proposition Our decision to introduce a new strategy, financial frame and investor proposition, including a new distribution policy, benefited from extensive dialogue with our major shareholders. ESG engagement We engage frequently with our investors on environmental, social and governance (ESG) issues. This includes one-to-one conversations, participation at external events and group meetings, including with Climate Action 100+ representatives. bp week In response to feedback from investors and others, CEO Bernard Looney and his leadership team offered further insight into bp’s new strategy and sustainability frame during bp week – three consecutive virtual capital markets days held in September 2020. Society Our biodiversity position We developed our updated position with input and constructive challenge from international nature and conservation organizations and experts including Conservation International, Fauna & Flora International (FFI), UNESCO and IUCN. The position sets out new measures to help restore, maintain and enhance nature. In September we announced a five-year collaboration with FFI to help support the delivery of our new position, including our aim to achieve a net positive impact. Our human rights policy We updated our business and human rights policy in 2020 to address emerging human rights issues relevant to our industry, clarify our human rights commitments and communicate how bp’s approach to managing human rights impacts has advanced. The update was supported by consultations with a wide range of NGOs, subject matter experts and investors. Examples of engagement with other stakeholder groups Customers Collaboration with original equipment manufacturers such as Ford, Renault, JLR and Volvo on future technologies. Global customer brand tracking. Government and regulators Publication of Our tax report 2019 – see bp.com/tax. Government lobbying – we actively advocated for regional carbon pricing schemes in the US, provided input to the EU methane strategy and supported the UK government’s planned phase out of internal combustion engines. Partners and suppliers Supplier workshops, including sessions focused on net zero, people and planet. University collaborations, including the Carbon Mitigation Initiative (CMI), an independent academic research programme based at Princeton University. bp Annual Report and Form 20-F 2020 63 How we manage risk How we manage risk bp manages, monitors and reports on the principal risks and uncertainties that can impact our ability to deliver our strategy. These risks are described in the Risk factors on page 67. Our management systems, organizational structures, processes, standards, code of conduct and behaviours together form a system of internal control that governs how we conduct the business of bp and manage associated risks. bp’s risk management system bp’s risk management system and policy is designed to be a consistent and clear framework for managing and reporting risks from the group’s operations to management and to the board. The system seeks to avoid incidents and enhance business outcomes by allowing us to: Understand the risk environment, identify the specific risks and assess the potential exposure for bp. Business and strategic risk management – our businesses, integrators and enablers integrate risk management into key business processes such as strategy, planning, performance management, resource and capital allocation, and project appraisal. We do this by using a standard framework for collating risk data, assessing risk management activities, making further improvements and in connection with planning new activities. Oversight and governance – throughout the year management, the leadership team, the board and relevant committees provide oversight of how significant risks to bp are identified, assessed and managed. They help to ensure that risks are governed by relevant policies and are managed appropriately. Such oversight may include reviews of the outcomes of business processes including strategy, planning and resource and capital allocation. bp’s group risk team analyses the group’s risk profile and maintains the group’s risk management system. Our internal audit team provides independent assurance to the chief executive and board as to whether the group’s system of internal control is adequately designed and operating effectively to respond appropriately to the risks that are significant to bp. Determine how best to deal with these risks to manage overall potential exposure. Risk oversight and governance Manage the identified risks in appropriate ways. Monitor and seek assurance of the effectiveness of the management of these risks and intervene for improvement where necessary. Report up the management chain and to the board on a periodic basis on how significant risks are being managed, monitored, assured and the improvements that are being made. Key risk oversight and governance committees include the following: Leadership team and its committees Leadership team meeting – for oversight and for strategic and commercial risks. Group operations risk committee – for health, safety, security, environment and operations integrity risks. Day-to-day risk management Identify, manage and report risks Business and strategic risk management Oversight and governance Group financial risk committee – for finance, treasury, trading and cyber risks. Plan, manage performance and assure Set policy and monitor principal risks Group disclosure committee – for financial reporting risks. Group people and culture committee – for employee risks. Facilities, assets and operations Businesses, integrators and enablers Leadership team and enablers The board Our risk management activities Day-to-day risk management – management and staff at our facilities, assets, and within our businesses, integrators and enablers seek to identify and manage risk, promoting safe, compliant and reliable operations. bp requirements, which take into account applicable laws and regulations, underpin the practical plans developed to help reduce risk and deliver safe, compliant and reliable operations as well as greater efficiency and sustainable financial results. Group ethics and compliance committee – for legal and regulatory compliance and ethics risks. Resource commitment meeting – for investment decision risks. bp quarterly audit meeting – for assurance on the oversight of bp’s principal risks. Board and its committees bp board. Audit committee. Safety and sustainability committee. Remuneration committee. People and governance committee. For bp governance framework see page 88, Board activities see page 80, committee reports see pages 92-102 and 105 and Risk management and internal control see page 127. 64 bp Annual Report and Form 20-F 2020 Strategic report Risk management processes We aim for a consistent basis of measuring risk to: Establish a common understanding of risks on a like-for-like basis, taking into account potential impact and likelihood. Report risks and their management to the appropriate levels of the organization. Inform prioritization of specific risk management activities and resource allocation. Businesses, integrators and enablers review significant risks and associated risk management activities in alignment with key business processes to help enable key decisions to be risk informed. As part of bp’s annual planning process, the leadership team and board review the group’s principal risks and uncertainties and determine risks for particular oversight by the board and its committees. These may be updated during the year in response to changes in internal and external circumstances. Our risk profile The nature of our business operations is long term, resulting in many of our risks being enduring in nature. Nonetheless, risks can develop and evolve over time and their potential impact or likelihood may vary in response to internal and external events. These may include emerging risks which are considered through existing processes, including bp’s risk management system, bp’s Energy Outlook, bp’s Technology Outlook and group strategic reviews. We identify longer-term strategic risks and high priority risks for particular oversight by the board and its various committees in the coming year. There can be no certainty that our risk management activities will mitigate or prevent these, or other risks, from occurring. Further details of the principal risks and uncertainties we face are set out in Risk factors on page 67. Risks for particular oversight by the board and its committees in 2021 Climate-related risks Risks associated with climate change and the transition to a lower carbon economy impact many elements of our strategy and, as such, these risks are considered through key business processes including the strategy, annual plan, capital allocation and investment decisions. The outputs of these key business processes are reviewed in line with the cadence of these activities. Further details are described in Climate change and the environment on page 52. Strategic and commercial risks Financial liquidity External market conditions can impact our financial performance. Supply and demand and the prices achieved for our products can be affected by a wide range of factors including political developments, consumer preferences for low carbon energy, global economic conditions and the influence of OPEC. We seek to manage this risk through bp’s diversified portfolio, our financial framework, liquidity stress testing, maintaining a significant cash buffer, regular reviews of market conditions and our planning and investment processes. See Prices and markets and Liquidity, financial capacity and financial, including credit, exposure on page 67. The impact of COVID-19 The spread of COVID-19 has caused a significant drop in the oil and gas prices and refining margins. bp’s future financial performance will be impacted by the extent and duration of the current market conditions and the effectiveness of the actions that it and others take, including its financial interventions. Our financial frame is designed to be robust to periods of low price, with flexibility to reduce cost and capital expenditure if required. We continue to assess the impact of COVID-19 on our staff and operations and have instigated appropriate mitigation plans. The risks for particular oversight by the board and its committees in 2021 have been reviewed and are listed in this section. These may be updated throughout the year in response to changes in internal and external circumstances. The oversight and management of other risks is undertaken in the normal course of business. In addition to the risks reviewed in 2020, climate-related risks remain a longer-term strategic risk. Cyber security The targeted and indiscriminate threats to the security of our digital infrastructure and those of third parties continue to evolve rapidly and are increasingly prevalent across industries worldwide. In addition, the COVID-19 pandemic changed ways of working and introduced new phishing campaigns. We seek to manage this risk through a range of measures, which include cyber security standards, security protection tools, ongoing detection and monitoring of threats and testing of cyber response and recovery procedures. We collaborate closely with governments, law enforcement agencies and industry peers to understand and respond to new and emerging cyber threats. We build awareness with our staff, share information on incidents with leadership for continuous learning and conduct regular exercises including with the leadership team to test response and recovery procedures. bp Annual Report and Form 20-F 2020 65 How we manage risk continued Geopolitical The diverse locations of our operations around the world expose us to a wide range of political developments and consequent changes to the economic and operating environment. Geopolitical risk is inherent to many regions in which we operate, and heightened political or social tensions or changes in key relationships could adversely affect the group. We seek to manage this risk through development and maintenance of relationships with governments and stakeholders and by becoming trusted partners in each country and region. In addition, we closely monitor events and implement risk mitigation plans where appropriate. The impact of the UK’s exit from the EU We have been assessing the potential impact on bp of Brexit and the UK’s future global relationships and have not identified any significant risk to our business. Safety and operational risks Process safety, personal safety and environmental risks The nature of the group’s operating activities exposes us to a wide range of significant health, safety and environmental risks such as incidents associated with releases of hydrocarbons when drilling wells, operating facilities and transporting hydrocarbons. Our operating management system« helps us manage these risks and drive performance improvements. It sets out the standards and requirements which govern key risk management activities such as inspection, maintenance, testing, business continuity and crisis response planning and competency development. In addition, we conduct our drilling activity through a wells organization in order to promote a consistent approach for designing, constructing and managing wells. Security Hostile acts such as terrorism or piracy could harm our people and disrupt our operations. We monitor for emerging threats and vulnerabilities to manage our physical and information security. Our central security team provides guidance and support to our businesses through a network of regional security advisors who advise and conduct assurance activities with respect to the management of security risks affecting our people and operations. We continue to monitor threats globally and maintain disaster recovery, crisis and business continuity management plans. Compliance and control risks Ethical misconduct and legal or regulatory non-compliance Ethical misconduct or breaches of applicable laws or regulations could damage our reputation, result in litigation, regulatory action and penalties, adversely affect results and shareholder value, and potentially affect our licence to operate. Our code of conduct and our values and behaviours, applicable to all employees, are central to managing this risk. Additionally, we have various group requirements and training covering areas such as anti-bribery and corruption, anti-money laundering, competition/anti-trust law and international trade regulations. We seek to keep abreast of new regulations and legislation and plan our response to them. We offer an independent confidential helpline, OpenTalk, for employees, contractors and other third parties. Trading non-compliance In the normal course of business, we are subject to risks around our trading activities which could arise from shortcomings or failures in our systems, risk management methodology, internal control processes or employee conduct. We have specific operating standards and control processes to manage these risks, including guidelines specific to trading, and seek to monitor compliance through our dedicated compliance teams. We also seek to maintain a positive and collaborative relationship with regulators and the industry at large. The impact of reinventing bp on the organization Last year we announced that we are reinventing bp to help deliver our ambition. This significant reorganization includes a new structure, a new leadership team, new ways of working and a reduction in the size of bp’s office- based workforce. Risks associated with these changes have been identified, assessed and are being managed. As part of our three lines of defence, our businesses, integrators and enablers are working to deliver clear accountabilities and the associated workload reduction. All individuals changing roles or leaving bp are required to complete a comprehensive management of change. Material risk management actions are being assured by internal audit. 66 bp Annual Report and Form 20-F 2020 Strategic report Major project delivery – failure to invest in the best opportunities or deliver major projects successfully could adversely affect our financial performance. We face challenges in developing major projects, particularly in geographically and technically challenging areas. Poor investment choice, efficiency or delivery, or operational challenges at any major project that underpins production or production growth could adversely affect our financial performance. Geopolitical – exposure to a range of political developments and consequent changes to the operating and regulatory environment could cause business disruption. We operate and may seek new opportunities in countries, regions and cities where political, economic and social transition may take place. Political instability, changes to the regulatory environment or taxation, international trade disputes and barriers to free trade, international sanctions, expropriation or nationalization of property, civil strife, strikes, insurrections, acts of terrorism, acts of war and public health situations (including the continued impact of the COVID-19 pandemic or any future epidemic or pandemic) may disrupt or curtail our operations or development activities. These may in turn cause production to decline, limit our ability to pursue new opportunities, affect the recoverability of our assets or cause us to incur additional costs, particularly due to the long-term nature of many of our projects and significant capital expenditure required. Events in or relating to Russia, including trade restrictions and other sanctions, could adversely impact our income and investment in or relating to Russia. Our ability to pursue business objectives and to recognize production and reserves relating to these investments could also be adversely impacted. Liquidity, financial capacity and financial, including credit, exposure – failure to work within our financial framework could impact our ability to operate and result in financial loss. Failure to accurately forecast or work within our financial framework could impact our ability to operate and result in financial loss. Trade and other receivables, including overdue receivables, may not be recovered, divestments may not be successfully completed and a substantial and unexpected cash call or funding request could disrupt our financial framework or overwhelm our ability to meet our obligations. Risk factors The risks discussed below, separately or in combination, could have a material adverse effect on the implementation of our strategy, our business, financial performance, results of operations, cash flows, liquidity, prospects, shareholder value and returns and reputation. Strategic and commercial risks Prices and markets – our financial performance is impacted by fluctuating prices of oil, gas and refined products, technological change, exchange rate fluctuations, and the general macroeconomic outlook. Oil, gas and product prices are subject to international supply and demand and margins can be volatile. Political developments, increased supply from new oil and gas or alternative low carbon energy sources, technological change, global economic conditions, public health situations (including the continued impact of the COVID-19 pandemic or any future epidemic or pandemic) and the influence of OPEC can impact supply and demand and prices for our products. Decreases in oil, gas or product prices could have an adverse effect on revenue, margins, profitability and cash flows. If significant or for a prolonged period, we may have to write down assets and re-assess the viability of certain projects, which may impact future cash flows, profit, capital expenditure, the ability to work within our financial frame and maintain our long-term investment programme. Conversely, an increase in oil, gas and product prices may not improve margin performance as there could be increased fiscal take, cost inflation and more onerous terms for access to resources. The profitability of our refining activities can be volatile, with periodic over-supply or supply tightness in regional markets and fluctuations in demand. Exchange rate fluctuations can create currency exposures and impact underlying costs and revenues. Crude oil prices are generally set in US dollars, while products vary in currency. Many of our major project« development costs are denominated in local currencies, which may be subject to fluctuations against the US dollar. Access, renewal and reserves progression – inability to access, renew and progress upstream resources in a timely manner could adversely affect our long-term replacement of reserves. Focused renewal of our reserve base in line with our strategy depends on our ability to progress upstream resources from our existing portfolio and access new resource in our core areas, generating future opportunities for oil and natural gas production. Competition for access to investment opportunities, heightened political and economic risks where we operate, unsuccessful exploration activity, technical challenges and capital commitments may adversely affect our reserve replacement. This, and our ability to progress upstream resources at a level in line with our strategic outlook for hydrocarbon production, could impact our future production and financial performance. bp Annual Report and Form 20-F 2020 67 Risk factors continued An event such as a significant operational incident, legal proceedings or a geopolitical event in an area where we have significant activities, could reduce our financial liquidity and our credit ratings. Credit rating downgrades could potentially increase financing costs and limit access to financing or engagement in our trading activities on acceptable terms, which could put pressure on the group’s liquidity. bp’s credit rating downgrades could also trigger a requirement for the company to review its funding arrangements with the bp pension trustees and may cause other impacts on financial performance. In the event of extended constraints on our ability to obtain financing, we could be required to reduce capital expenditure or increase asset disposals in order to provide additional liquidity. See Liquidity and capital resources on page 306 and Financial statements – Note 29. Joint arrangements and contractors – varying levels of control over the standards, operations and compliance of our partners, contractors and sub-contractors could result in legal liability and reputational damage. We conduct many of our activities through joint arrangements«, associates«or with contractors and sub-contractors where we may have limited influence and control over the performance of such operations. Our partners and contractors are responsible for the adequacy of the resources and capabilities they bring to a project. If these are found to be lacking, there may be financial, operational or safety exposures for bp. Should an incident occur in an operation that bp participates in, our partners and contractors may be unable or unwilling to fully compensate us against costs we may incur on their behalf or on behalf of the arrangement. Where we do not have operational control of a venture, we may still be pursued by regulators or claimants in the event of an incident. Digital infrastructure and cyber security – breach or failure of our or third parties’ digital infrastructure or cyber security, including loss or misuse of sensitive information could damage our operations, increase costs and damage our reputation. The energy industry is subject to fast-evolving risks from cyber threat actors, including nation states, criminals, terrorists, hacktivists and insiders. A breach or failure of our or third parties’ digital infrastructure – including control systems – due to breaches of our cyber defences, or those of third parties, negligence, intentional misconduct or other reasons, could seriously disrupt our operations. This could result in the loss or misuse of data or sensitive information, injury to people, disruption to our business, harm to the environment or our assets, legal or regulatory breaches and legal liability. Furthermore, the rapid detection of attempts to gain unauthorized access to our digital infrastructure, often through the use of sophisticated and co-ordinated means, is a challenge and any delay or failure to detect could compound these potential harms. These could result in significant costs including fines, cost of remediation or reputational consequences. Climate change and the transition to a lower carbon economy – developments in policy, law, regulation, technology and markets, including societal and investor sentiment, related to the issue of climate change could increase costs, constrain our operations and affect our business plans and financial performance. Laws, regulations, policies, obligations, government actions, social attitudes and customer preferences relating to climate change and the transition to a lower carbon economy, including the pace of change to any of these factors, and also the pace of the transition itself, could have adverse impacts on our business including on our access to and realization of competitive opportunities in any of our strategic focus areas, a decline in demand for, or constraints on our ability to sell certain products, constraints on production and supply and access to new reserves, adverse litigation and regulatory or litigation outcomes, increased costs from compliance and increased provisions for environmental and legal liabilities. Investor preferences and sentiment are influenced by environmental, social and corporate governance (ESG) considerations including climate change and the transition to a lower carbon economy. Changes in those preferences and sentiment could affect our access to capital markets and our attractiveness to potential investors, potentially resulting in reduced access to financing, increased financing costs and impacts upon our business plans and financial performance. Technological improvements or innovations that support the transition to a lower carbon economy, and customer preferences or regulatory incentives that alter fuel or power choices, could impact demand for oil and gas. Depending on the nature and speed of any such changes and our response, these changes could increase costs, reduce our profitability, reduce demand for certain products, limit our access to new opportunities, require us to write down certain assets or curtail or cease certain operations, and affect investor sentiment, our access to capital markets, our competitiveness and financial performance. Policy, legal regulatory, technological and market developments related to climate change could also affect future price assumptions used in the assessment of recoverability of asset carrying values including goodwill, the judgement as to whether there is continued intent to develop exploration and appraisal intangible assets, the timing of decommissioning of assets and the useful economic lives of assets used for the calculation of depreciation and amortization. See Financial statements – Note 1 and Climate change and the environment on page 52. 68 bp Annual Report and Form 20-F 2020 Strategic report Such events or conditions, including a marine incident, or inability to provide safe environments for our workforce and the public while at our facilities, premises or during transportation, could lead to injuries, loss of life or environmental damage. As a result we could face regulatory action and legal liability, including penalties and remediation obligations, increased costs and potentially denial of our licence to operate. Our activities are sometimes conducted in hazardous, remote or environmentally sensitive locations, where the consequences of such events or conditions could be greater than in other locations. Drilling and production – challenging operational environments and other uncertainties could impact drilling and production activities. Our activities require high levels of investment and are sometimes conducted in challenging environments such as those prone to natural disasters and extreme weather, which heightens the risks of technical integrity failure. The physical characteristics of an oil or natural gas field, and cost of drilling, completing or operating wells is often uncertain. We may be required to curtail, delay or cancel drilling operations or stop production because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions and compliance with governmental requirements. Security – hostile acts against our staff and activities could cause harm to people and disrupt our operations. Acts of terrorism, piracy, sabotage and similar activities directed against our operations and facilities, pipelines, transportation or digital infrastructure could cause harm to people and severely disrupt operations. Our activities could also be severely affected by conflict, civil strife or political unrest. Product quality – supplying customers with off-specification products could damage our reputation, lead to regulatory action and legal liability, and impact our financial performance. Failure to meet product quality specifications could cause harm to people and the environment, damage our reputation, result in regulatory action and legal liability, and impact financial performance. bp Annual Report and Form 20-F 2020 69 Competition – inability to remain efficient, maintain a high-quality portfolio of assets, innovate and retain an appropriately skilled workforce could negatively impact delivery of our strategy in a highly competitive market. Our strategic progress and performance could be impeded if we are unable to control our development and operating costs and margins, if we fail to scale our businesses at pace, or to sustain, develop and operate a high- quality portfolio of assets efficiently. Furthermore, as we transition from an International Oil Company to an Integrated Energy Company, we face an expanded and rapidly evolving range of competitors in the sectors in which we operate. We could be adversely affected if competitors offer superior terms for access rights or licences, or if our innovation in areas such as new low carbon technologies, digital, customer offer, exploration, production, refining, manufacturing or renewable energy lags those of our competitors. Our performance could also be negatively impacted if we fail to protect our intellectual property. Our industry faces increasing challenges to recruit and retain diverse, skilled and experienced talent. Successful recruitment, development and retention of specialist staff is essential to our plans. Crisis management and business continuity – failure to address an incident effectively could potentially disrupt our business. Our business activities could be disrupted if we do not respond, or are perceived not to respond, in an appropriate manner to any major crisis or if we are not able to restore or replace critical operational capacity. Insurance – our insurance strategy could expose the group to material uninsured losses. bp generally purchases insurance only in situations where this is legally and contractually required. Some risks are insured with third parties and reinsured by group insurance companies. Uninsured losses could have a material adverse effect on our financial position, particularly if they arise at a time when we are facing material costs as a result of a significant operational event which could put pressure on our liquidity and cash flows. Safety and operational risks Process safety, personal safety, and environmental risks – exposure to a wide range of health, safety, security and environmental risks could cause harm to people, the environment and our assets and result in regulatory action, legal liability, business interruption, increased costs, damage to our reputation and potentially denial of our licence to operate. Technical integrity failure, natural disasters, extreme weather or a change in its frequency or severity, human error and other adverse events or conditions, including breach of digital security, could lead to loss of containment of hydrocarbons or other hazardous materials. This could also lead to constrained availability of resources used in our operating activities, as well as fires, explosions or other personal and process safety incidents, including when drilling wells, operating facilities and those associated with transportation by road, sea or pipeline. There can be no certainty that our operating management systemor other policies and procedures will adequately identify all process safety, personal safety and environmental risks or that all our operating activities, including acquired businesses, will be conducted in conformance with these systems. See Safety on page 59. Risk factors continued Compliance and control risks Ethical misconduct and non-compliance – ethical misconduct or breaches of applicable laws by our businesses or our employees could be damaging to our reputation, and could result in litigation, regulatory action and penalties. Incidents of ethical misconduct or non-compliance with applicable laws and regulations, including anti-bribery and corruption and anti-fraud laws, trade restrictions or other sanctions, could damage our reputation, and result in litigation, regulatory action, penalties and potentially affect our licence to operate. Regulation – changes in the law and regulation could increase costs, constrain our operations and affect our business plans and financial performance. Our businesses and operations are subject to the laws and regulations applicable in each country, state or other regional or local area in which they occur. These laws and regulations result in an often complex, uncertain and changing legal and regulatory environment for our global businesses and operations. Changes in laws or regulations, including how they are interpreted and enforced, can and does impact all aspects of our business. Royalties and taxes, particularly those applied to our hydrocarbon activities, tend to be high compared with those imposed on similar commercial activities. In certain jurisdictions there is also a degree of uncertainty relating to tax law interpretation and changes. Governments may change their fiscal and regulatory frameworks in response to public pressure on finances, resulting in increased amounts payable to them or their agencies. Changes in law or regulation could increase the compliance and litigation risk and costs, reduce our profitability, reduce demand for or constrain our ability to sell certain products, limit our access to new opportunities, require us to divest or write down certain assets or curtail or cease certain operations, or affect the adequacy of our provisions for pensions, tax, decommissioning, environmental and legal liabilities. Changes in laws or regulations could result in the nationalization, expropriation, cancellation, non-renewal or renegotiation of our interests, assets and related rights. Potential changes to pension or financial market regulation could also impact funding requirements of the group. Following the Gulf of Mexico oil spill, we may be subjected to a higher level of fines or penalties imposed in relation to any alleged breaches of laws or regulations, which could result in increased costs. See Regulation of the group’s business on page 321. 70 bp Annual Report and Form 20-F 2020 Treasury and trading activities – ineffective oversight of treasury and trading activities could lead to business disruption, financial loss, regulatory intervention or damage to our reputation. We are subject to operational risk around our treasury and trading activities in financial and commodity markets, some of which are regulated. Failure to process, manage and monitor a large number of complex transactions across many markets and currencies while complying with all regulatory requirements could hinder profitable trading opportunities. There is a risk that a single trader or a group of traders could act outside of our delegations and controls, leading to regulatory intervention and resulting in financial loss, fines and potentially damaging our reputation. See Financial statements – Note 29. Reporting – failure to accurately report our data could lead to regulatory action, legal liability and reputational damage. External reporting of financial and non-financial data, including reserves estimates, relies on the integrity of the control environment, our systems and people operating them. Failure to report data accurately and in compliance with applicable standards could result in regulatory action, legal liability and damage to our reputation. The Strategic report was approved by the board and signed on its behalf by Ben J. S. Mathews, company secretary, on 22 March 2021. Corporate governance Corporate governance Introduction from the chairman Board of directors Leadership team Board activities Decision making by the board How the board has engaged with shareholders, the workforce and other stakeholders Governance framework Learning, development and induction Board evaluation People and governance committee Audit committee Safety and sustainability committee Geopolitical committee Directors’ remuneration report Remuneration committee Directors’ statements 72 74 78 80 82 86 88 90 91 92 94 100 102 103 105 127 Since 2017 when the partnership with bp began, Lightsource bp has more than doubled its global presence, from five to 14 countries. It’s also grown its development pipeline from 1.6 to 17GW. bp Annual Report and Form 20-F 2020 71 Introduction from the chairman New strategy As a board, our responsibilities include determining bp’s purpose and strategy, monitoring its culture and seeking assurance that these are aligned with our values. For bp, 2020 was a year in which we felt this responsibility especially keenly. With the board’s support, bp adopted a new purpose – reimagining energy for people and our planet, which aligns bp’s capabilities and aspirations with the needs of society. 2020 was also the year bp’s new CEO, Bernard Looney, commenced his role. As well as formally launching our new purpose, Bernard set out a net zero ambition, new strategy, financial frame and investor proposition. These actions were taken with the full support of the board following a process of careful debate, and the board is confident that they respect bp’s culture and values. The change that was immediately most consequential for many people within bp was a restructure that will see close to 10,000 colleagues leave bp. It was difficult saying goodbye to people who helped make our organization what it is today – and the board was united with the leadership team in determining that the process should be conducted fairly and respectfully. That process is now largely complete, and I believe, as does the board, that bp is now leaner, flatter and nimbler – better able to fulfil our new purpose, ambition and strategy. COVID impact on working of the board Change on this scale would be challenging in any company at any time. So, I want to pay tribute to my board colleagues for their contribution during such a difficult period. It is to their credit that we very quickly adapted to a new way of working together – with our many meetings since March held entirely virtually. Indeed, the COVID-19 pandemic justified more regular meetings with bp’s leadership – so early in the pandemic we instituted weekly calls to keep abreast of bp’s response to the pandemic and how the team was taking account of the needs and expectations of all our stakeholders. Maintaining bp’s culture Since joining bp, I have always been impressed at the strength of the company’s culture – open, co-operative, collaborative and performance- focused. Rather than weaken that culture, I believe that the pandemic has strengthened it further – and has proved its value. bp would not have achieved all it did in 2020 without such a strong culture. We have been careful that the changes introduced throughout the year are respectful of it, and consistent with bp’s values of safety, respect, excellence, courage and one team. Board composition In 2020 we welcomed Tushar Morzaria, Karen Richardson and Johannes Teyssen to the board. They each have skills, experience and a diverse mindset that is closely aligned to the strategic direction we have set for bp. We also said goodbye to friends who have served bp with distinction over many years – Nils Andersen, Brian Gilvary, Sir Ian Davis, Dame Alison Carnwath and, of course, Bob Dudley. bp has been fortunate to have them, and we will miss them. I was delighted that Paula Reynolds agreed to take over from Sir Ian Davis as senior independent director following the AGM 2020, and that Melody Meyer was able to take over the important role of chairing the safety and sustainability committee after Nils Andersen stepped down from the board. Tushar Morzaria will take over as chair of the audit committee after the AGM in May, following an extensive handover from Brendan Nelson, who will then retire. 2020 tested bp’s governance processes like no other year. Board members, like many colleagues across bp, have achieved and learned a lot together through our new way of working – and there’s much that we will continue. I am grateful for the flexibility, commitment and clear- sightedness of my board colleagues in 2020 – it bodes well for the years ahead. Helge Lund Chairman 72 bp Annual Report and Form 20-F 2020 In the coming year, one of my priorities will be to ensure that the board remains at an appropriate size, with strong composition, and with diversity of both thought and skills in support of the strategic direction we have set. Diversity The process of reinventing bp provided opportunities to enhance bp’s diversity in other ways, too. Though we have more to do in all areas, we have made particular progress on gender diversity at senior levels. In 2020, we increased female board representation from 42% to 45%; increased female executive committee representation from 15% to 31%; and met the Hampton-Alexander and Parker review targets for 2021. New governance framework To complement bp’s new strategic direction, we have introduced a new governance framework, covering bp’s board-level corporate governance and facilitating a stronger board focus on strategy, performance, people and governance, with the committees each playing a critical role in support. The emphasis on strategy and its execution is especially important – I believe it to be where the board can deliver most value at this time, encouraging and working closely with the leadership team as they drive forward our strategic progress, safety, financial and operational performance. The governance framework redefines the committees’ roles. Our newly-titled safety and sustainability committee rightly gains an enhanced focus on sustainability, but with no let-up on our core and overriding priority – safety, while our people and governance committee gains an enhanced focus on our single most important asset – our people. These committees and the insights they provide to the board very much support its effectiveness. Conclusion 2020 tested bp’s governance processes like no other year. Board members, like many colleagues across bp, have achieved and learned a lot together through our new way of working – and there’s much that we will continue. I am grateful for the flexibility, commitment and clear-sightedness of my board colleagues in 2020 – it bodes well for the years ahead. Helge Lund, Chairman 22 March 2021 Corporate governance Compliance with the UK Corporate Governance Code Throughout 2020, bp applied the principles and complied with all the provisions of the 2018 UK Corporate Governance Code. bp Annual Report and Form 20-F 2020 73 Board of directors As at 22 March 2021 P Helge Lund Chairman Appointed Bernard Looney Chief executive officer Appointed Board: 26 July 2018; Chairman: 1 January 2019 5 February 2020 Nationality Norwegian Outside interests Nationality Irish Outside interests Chairman of Novo Nordisk AS; Operating Advisor to Clayton Dubilier & Rice; Member of the Board of Trustees of the International Crisis Group; Member of the European Round Table of Industrialists Fellow of the Royal Academy of Engineering; Fellow of the Energy Institute; Mentor for the FTSE 100 Cross-Company Mentoring Executive Programme; Non-executive director of Rosneft Career summary Career summary Bernard Looney was appointed chief executive officer in February 2020. He previously ran bp’s Upstream business from April 2016 and has been a member of the company’s executive management team since November 2010. As chief executive, Upstream, Bernard was responsible for bp’s oil and gas exploration, development and production activities worldwide. In this role, Bernard oversaw improvements in both process and personal safety performances, and production grew by 20%. He led access into new countries, high-graded the portfolio and created innovative new business models. In earlier Upstream executive roles, he was responsible for all bp-operated oil and gas production worldwide and for all bp’s drilling and major project« activity. Bernard joined bp in 1991 as a drilling engineer and worked in operational roles in the North Sea, Vietnam and the Gulf of Mexico. Skills and experience Bernard has spent his career at bp and has demonstrated dynamic leadership and vision as he has progressed through various roles within bp. During his 10 years as a leader of Upstream, Bernard saw the segment through one of the most difficult periods in bp’s history, helping transform the organization into a safer, stronger and more resilient business. He was instrumental in a number of workforce-based initiatives to promote a diverse and inclusive environment. Bernard set out bp’s new strategy in 2020 and is guiding the company through its transformation. Helge Lund was appointed chairman of the bp board on 1 January 2019. He served as chief executive of BG Group from 2015 to 2016, when it merged with Shell. He joined BG Group from Equinor (formerly Statoil) where he served as its president and chief executive officer for 10 years from 2004. Prior to Equinor, Helge was president and chief executive officer of the industrial conglomerate Aker Kvaerner, and has also held executive positions in the Norwegian industrial holding company, Aker RGI, and the former Norwegian power and industry company, Hafslund Nycomed. He worked as a consultant with McKinsey & Company and served as a political advisor for the parliamentary group of the Conservative party in Norway. Prior to joining bp, he was a non-executive director of the oil service group Schlumberger from 2016 to 2018, and Nokia from 2011 to 2014. He served as a member of the United Nations Secretary-General’s Advisory Group on Sustainable Energy from 2011 to 2014. Skills and experience Helge’s distinguished career as a leader in the oil and gas industry and his open-minded and forward-looking approach is vital as he leads the board in its oversight of delivery of bp’s new strategy. He has deep industry knowledge and global business experience – not only in the oil and gas industry but also in pharmaceuticals, healthcare and construction. His innovative leadership of the board drives cohesion and a strong environment for constructive challenge and oversight as bp works to transform into an Integrated Energy Company. Committee membership key Chairman A Audit committee S Safety and sustainability committee R Remuneration committee P People and governance committee 74 bp Annual Report and Form 20-F 2020 Murray Auchincloss Chief financial officer Appointed 1 July 2020 Nationality Canadian Outside interests Board member of Aker BP ASA; Member of The 100 Group Main Committee Career summary Murray Auchincloss qualified as a chartered financial analyst in the US, leading on to a wide range of tax and financial roles, first for Amoco and then for bp after the two organizations merged in 1998. Murray has worked in both the US and UK, in a range of roles including chief financial officer, Upstream, and chief financial officer, North Sea. He was commercial director for the North American Gas business and, as head of the chief executive’s office for three years, managed all aspects of that office. Skills and experience Murray’s financial expertise, experience and knowledge make him a trusted advisor and bp group leader. His broad experience of working across the group has provided him with deep insight into bp’s assets and businesses. Murray has a degree in commerce from the University of Calgary, Canada, and qualified as a chartered financial analyst at the University of West Virginia, US. His drive to modernize is improving bp’s financial teams, controlling costs and continuing to deliver transparent financial disclosures to investors and markets. Board gender diversity 1. 2. 1. Male 2. Female 7 5 Corporate governance A R S S R Pamela Daley Independent non-executive director Professor Dame Ann Dowling Independent non-executive director Melody Meyer Independent non-executive director Appointed 26 July 2018 Nationality American Outside interests Appointed 3 February 2012 Nationality British Outside interests Director of BlackRock, Inc.; Director of SecureWorks, Inc. Career summary Pamela Daley joined General Electric Company (GE) in 1989 as tax counsel and held a number of senior executive roles in the company, overseeing a wide range of corporate transactions and serving as senior vice president and senior advisor to the chairman in 2013, before retiring from GE. Pamela has served as a director of BlackRock since 2014 and of SecureWorks since 2016. She was a director of BG Group plc from 2014 to 2016 until its acquisition by Shell. She was a director of Patheon N.V. from 2016 to 2017 until its acquisition by Thermo Fisher and, prior to that, she was a partner at Morgan, Lewis & Bockius, a major US law firm, where she specialized in domestic and cross-border tax-oriented financings and commercial transactions. Skills and experience Pamela is a qualified lawyer with significant management insight obtained from previous senior positions held at companies that operate in highly regulated industries. Pamela has a wealth of experience in global business and strategy gained from over 20 years in an executive role at GE. She also has experience in the UK oil and gas industry from her time served on the BG Group plc board. Pamela contributes important insight to the audit committee from her previous executive experience. In 2019, she joined the remuneration committee, where her understanding of employee and investor perspectives brings value. Deputy vice-chancellor and emeritus professor of Mechanical Engineering at the University of Cambridge; Non-executive director of Smiths Group plc Career summary Professor Dame Ann Dowling is a deputy vice-chancellor and emeritus professor of mechanical engineering at the University of Cambridge where her research includes fluid mechanics, acoustics and combustion. She has held visiting posts at MIT and at Caltech. Dame Ann is a fellow of the Royal Society and the Royal Academy of Engineering and a foreign associate of the US National Academy of Engineering, the Chinese Academy of Engineering and the French Academy of Sciences. She was an advisor at Rolls-Royce until 2015. Dame Ann was President of the Royal Academy of Engineering from September 2014 to 2019. In December 2015 she was appointed to the Order of Merit. Skills and experience Professor Dame Ann is an internationally respected leader in engineering research and the practical application of new technology in industry. Her contribution in these fields has been widely recognized by universities around the world. Her academic background provides valuable balance to the board and brings a different perspective to the safety and sustainability committee of which she is a member, particularly as developments in technology continue to accelerate. Her work in this area is supplemented by her chairing the company’s technology advisory council. Non executive directors’ tenure Board nationality 1. 1. 4. 3. 1. <1 year 2. 1–3 years 3. 4–6 years 4. 7+ years 2. 3. 2. 3 3 2 2 1. UK 2. US 3. Non UK/US 4 4 4 Appointed 17 May 2017 Nationality American Outside interests President of Melody Meyer Energy LLC; Director of the National Bureau of Asian Research; Trustee of Trinity University; Non-executive director of AbbVie Inc.; Non-executive director of NOV, Inc. Career summary Melody Meyer started her career in 1979 with Gulf Oil which later merged with Chevron Corporation, where she remained until her retirement in 2016. During her career with Chevron, Melody held several key leadership roles in global exploration and production, working on a number of international projects and operational assignments. Melody was the executive sponsor of the Chevron Women’s Network and continues as a mentor and advocate for the advancement of women in the industry. Melody is a C200 member, and has received several awards and accolades throughout her career including being recognized as a 2009 Trinity Distinguished Alumni, with the BioHouston Women in Science Award by Hart Energy as an Influential Woman in Energy in 2018, by Women Inc as 2018 Most Influential Corporate Board Directors, and Outstanding Director by 2020 Women on Boards. She serves on McKinsey Women in Energy Advisory Board and co-leads Women Corporate Directors in Houston. Skills and experience Melody brings a world-class operational perspective to the board, with a deep understanding of the factors influencing safe, efficient and commercially high-performing projects in a global organization. Her long and illustrious career in the oil and gas industry is predicated on a dedication to excellence, safety and performance improvements. She has expertise in the execution of major capital projects, technology, R&D, creation of businesses in new countries, strategic and business planning, merger integration and safe and reliable operations. bp Annual Report and Form 20-F 2020 75 Board of directors continued As at 22 March 2021 A R A P R Tushar Morzaria Independent non-executive director Brendan Nelson Independent non-executive director Karen Richardson Independent non-executive director Appointed 1 September 2020 Nationality British Outside interests Appointed 8 November 2010 Nationality British Outside interests Group Finance Director of Barclays PLC; Member of The 100 Group Main Committee; Chair of the Sterling Risk Free Reference Rates Working Group Non-executive director of NatWest Markets plc Career summary Career summary Tushar Morzaria is a chartered accountant with over 25 years of strategic financial management, investment banking, operational and regulatory relations experience. He is currently Group Finance Director of Barclays PLC, the British universal banking and financial services company, where he is a member of the Barclays board and executive committee. Tushar joined Barclays from JP Morgan in 2013, where he held various senior roles including the CFO of its Corporate & Investment Bank at the time of the merger of the investment bank and the wholesale treasury/security services business. Skills and experience Tushar’s position as Group Finance Director of Barclays PLC gives him a breadth of knowledge and insight into financial, tax, treasury, investor relations and strategic matters which will benefit bp as Tushar assumes the role of audit committee chair at the conclusion of bp’s annual general meeting on 12 May 2021. He has strong experience in delivering corporate change programmes while maintaining a focus on performance. Brendan Nelson is a qualified chartered accountant. He was made a partner of KPMG in 1984. He served as a member of the UK board of KPMG from 2000 to 2006, subsequently being appointed vice chairman until his retirement in 2010. At KPMG International he held a number of senior positions including global chairman, banking and global chairman, financial services. Brendan has extensive financial experience, having been a non-executive director of The Royal Bank of Scotland Group p.l.c, where he also served as chairman of the group audit committee, until April 2019 and National Westminster Bank p.l.c. until December 2018. Brendan previously served as a member of the Financial Services Practitioner Panel for six years and was chairman of the audit committee of the Institute of Chartered Accountants of Scotland from 2005 to 2008 and later became President of the Institute of Chartered Accountants of Scotland from 2013 to 2014. Skills and experience Brendan has completed a wide variety of audit, regulatory and due-diligence engagements over the course of his career. He played a significant role in the development of the profession’s approach to the audit of banks in the UK, with particular emphasis on establishing auditing standards. His role as a member of the Financial Reporting Review Panel enabled him to further contribute to the profession. This wide experience makes him ideally suited to chair the audit committee and to act as its financial expert. He brings related input from his role as the chair of the audit committee of a major bank. His specialism in the financial services industry allows him to contribute insight into the challenges faced by global businesses by regulatory frameworks. As previously announced, Brendan will retire from the board at the conclusion of bp’s annual general meeting on 12 May 2021. Appointed 1 January 2021 Nationality American Outside interests Director of Artius Acquisition Inc.; Director of Exponent Inc. Career summary Karen Richardson was Vice President of Sales at Netscape Communications Corporation from 1995 to 1998 before embarking on several senior executive roles at E.piphany from 1998 to 2003 and was Chief Executive Officer between 2003 and 2006. In 2011 she became a non-executive director of BT plc where she served for seven years and between 2016 and 2019 Karen was a director of Worldpay Inc. (Worldpay Group plc). Karen is currently a director of Artius Acquisition Inc., a special purpose acquisition company, and, since 2013, Exponent Inc., the engineering and scientific consulting company. Karen has a Bachelor of Science degree in Industrial Engineering from Stanford University and was awarded distinctions from the Stanford Industrial Engineering Department and the American Institute of Industrial Engineers. Skills and experience Karen has over 30 years’ experience in the technology industry. She brings exceptional knowledge of digital, technology, cyber and IT security matters from her career working with innovative companies in Silicon Valley. As bp works to transform into an Integrated Energy Company, Karen has the skills, experience and diversity to further enhance the board’s ability to support and oversee the delivery of bp’s strategy. From the conclusion of the 2021 annual general meeting, Karen will become a member of the audit committee. 76 bp Annual Report and Form 20-F 2020 Corporate governance R A P S P S Paula Rosput Reynolds Senior independent director Sir John Sawers Independent non-executive director Dr Johannes Teyssen Independent non-executive director Appointed Appointed Board: 14 May 2015; Senior independent: 27 May 2020 14 May 2015 Nationality American Outside interests Nationality British Outside interests Appointed 1 January 2021 Nationality German Outside interests Non-executive director and Chair Designate of National Grid plc; Non-executive director of General Electric Company; Chair of the Seattle Cancer Care Alliance Career summary Paula Rosput Reynolds commenced her energy career at Pacific Gas & Electric Corp in 1979 and spent over 25 years in the energy industry. She has held a number of executive positions during her career, including CEO of Duke Energy Power Services, Chairman, President and CEO of AGL Resources as well as Chairman and CEO of Safeco Corporation and Vice Chairman and Chief Restructuring Officer of AIG. Paula was a non-executive director of TransCanada Corporation and CBRE Group, Inc until May 2019, having been appointed in 2011 and 2016 respectively. Between 2011 and 2020 Paula was a non-executive director of BAE Systems PLC. Paula was awarded the National Association of Corporate Directors (US) Lifetime Achievement Award in 2014. Skills and experience Paula has had a long career leading global companies in the energy and financial sectors. Her experience with international and US companies, including several restructuring processes and mergers, gives her insight into strategic and regulatory issues, which is an asset to the board. Her wider business experience and understanding of the views of investors are well suited to her being the chair of bp’s remuneration committee and senior independent director. Visiting Professor at King’s College London; Senior Adviser at Chatham House; Senior Fellow at the Royal United Services Institute; Global Adviser at the Council on Foreign Relations; Governor of the Ditchley Foundation; Director of the Bilderberg Association, UK; Executive Chairman of Newbridge Advisory Limited Career summary Sir John Sawers spent 36 years in public service in the UK, working on foreign policy, international security and intelligence. He was chief of the Secret Intelligence Service, MI6, from 2009 to 2014 and prior to that spent the bulk of his career in the Diplomatic Service, representing the British government around the world and leading negotiations at the UN, in the European Union and in the G8. After he left public service, Sir John was chairman and general partner of Macro Advisory Partners, a firm that advises clients on the intersection of policy, politics and markets from February 2015 to May 2019. He then set up his own firm, Newbridge Advisory, to carry out similar work. Sir John was appointed Knight Grand Cross of the Order of St Michael and St George in the 2015 New Year Honours for services to national security. Skills and experience Sir John’s deep experience of international political and commercial matters is an asset to the board in navigating the geopolitical issues faced by a modern global company. Sir John’s unique skill set made him an ideal chair of bp’s geopolitical committee and he will continue to advise the board on these matters as the chair of the newly established geopolitical advisory council. CEO and Chairman of the management board of E.ON SE (until 31 March 2021); Chairman of the Supervisory Board of Innogy SE.; Member of the Shareholders’ Committee of Nord Stream AG; Member of the Presidential Board of the Federation of German Industries Career summary Johannes began his professional career at VEBA AG in 1989. There he held a number of leadership positions across Legal Affairs and Key Account Sales. In 2000 VEBA became part of E.ON and in 2001 Johannes became a member of the Board of Management of the E.ON Group’s central management company in Munich. In 2004, he was also appointed to the Board of Management of E.ON SE in Düsseldorf and later went on to become Vice Chairman in 2008 and CEO in 2010. He was President of Eurelectric from 2013 to 2015 and the World Energy Council’s Vice Chair responsible for Europe between 2006 to 2012. Johannes was a member of the Supervisory Board of Deutsche Bank AG between 2008 and 2018 and is currently a member of the Presidential Board of the Federation of German Industries and the Shareholders’ Committee of Nord Stream AG. Skills and experience Johannes brings exceptional experience and deep knowledge in the sector and its continuing transformation. His skill set further diversifies and strengthens the overall demographic and attributes of the board as a whole. His experience in the energy sector further enhances the board’s ability to support and oversee the delivery of bp’s new strategy. Johannes has a doctorate in law from the University of Göttingen. Ben J S Mathews Company secretary Appointed 7 May 2019 Ben joined bp as a company secretary in May 2019. He is chairman of the Association of General Counsel and Company Secretaries of the FTSE 100 (GC100) and the co-chair of the Corporate Governance Council of the Conference Board. Ben is also a Fellow of the Institute of Chartered Secretaries and Administrators. Former appointments include Group Company Secretary of HSBC Holdings plc and Rio Tinto plc. bp Annual Report and Form 20-F 2020 77 Leadership team As at 22 March 2021 The leadership team represents the principal executive leadership of the bp group. Its members include bp’s executive directors (Bernard Looney and Murray Auchincloss whose biographies appear on page 74) and the senior management listed on these pages. 78 bp Annual Report and Form 20-F 2020 Emma Delaney EVP, customers & products Leadership team tenure Appointed 1 July 2020 Emma previously served on bp’s executive team starting on 1 April 2020. Nationality Irish Other board memberships None Career Emma has spent 25 years working in bp, both in the Upstream and the Downstream, most recently as interim chief executive officer Downstream from 1 April 2020 and prior to that as regional president for West Africa. She has held a variety of senior roles including Upstream chief financial officer for Asia Pacific and head of business development for gas value chains. In Downstream she held roles in retail and commercial fuels and planning. William Lin EVP, regions, cities & solutions Leadership team tenure Appointed 1 July 2020 Nationality American Other board memberships William is a non-executive director of Pan American Energy Group that operates in Argentina. Career William served as chief operating officer, Upstream regions before joining the leadership team. He has worked in bp for 25 years having spent most of his career working abroad in different countries. Previous senior roles include vice president – gas development and operations for Egypt, regional president for Asia Pacific and head of the group chief executive’s office. William managed the successful start-up of the Tangguh LNG facility during his time in Indonesia. Geoff Morrell EVP, communications & advocacy Leadership team tenure Appointed 1 July 2020 Nationality American Other board memberships None Career Geoff moved to London in 2017 to take over group communications and external affairs. He spent the prior six years leading bp America’s communications and government relations teams and was instrumental in rebuilding bp’s reputation following the Deepwater Horizon incident. Before joining bp, Geoff spent four years at the Pentagon, serving as chief spokesperson for the US Department of Defense under presidents Bush and Obama. He previously worked as a journalist, including as a White House correspondent for ABC News. Corporate governance Dev Sanyal EVP, gas & low carbon energy David Eyton EVP, innovation & engineering Leadership team tenure Appointed 1 July 2020 Leadership team tenure Appointed 1 July 2020 Gordon Birrell EVP, production & operations Leadership team tenure Appointed 1 July 2020 Dev previously served on bp’s executive team starting on 1 January 2012. David previously served on bp’s executive team starting on 1 September 2018. Gordon previously served on bp’s executive team starting on 12 February 2020. Nationality British and Indian Nationality British Nationality British Other board memberships Other board memberships Other board memberships Dev is a non-executive director of Man Group plc, a member of the board of overseers of The Fletcher School of Law and Diplomacy at Tufts University and a member of the energy advisory board of the Government of India. Career Dev has been a member of the executive team since 2011, firstly as executive vice president, strategy and regions, and since 2016, as chief executive alternative energy and executive vice president, regions. Dev joined bp in 1989 and has worked in London, Athens, Istanbul, Vienna and Dubai across various segments. Previous senior roles include CEO of bp Eastern Mediterranean, CEO of Air bp and group treasurer. He played a key role in bp navigating its way through the aftermath of the 2010 Deepwater Horizon incident. None Career None Career David joined the executive team in 2018 as group head of technology. He joined bp in 1982 with a degree in engineering and has held several positions in petroleum engineering, commercial and business management. Previous senior roles include managing Wytch Farm, Trinidad Gas and Gulf of Mexico Deepwater Developments. He was awarded a CBE (Commander of the British Empire) by Queen Elizabeth II for his contributions to UK engineering and energy. David is a Fellow of the UK Royal Academy of Engineering. Before being appointed to his new role, Gordon was chief operating officer for production, transformation and carbon. In his bp career, Gordon has spent time in various leadership, technical, safety and operational risk roles, including four years as bp president Azerbaijan, Georgia and Turkey. Gordon is a Fellow of the UK Royal Academy of Engineering. Carol Howle EVP, trading & shipping Leadership team tenure Appointed 1 July 2020 Nationality British Giulia Chierchia EVP, strategy & sustainability Leadership team tenure Appointed 1 July 2020 Nationality Belgian and Italian Other board memberships Other board memberships None Career None Career Before taking on her current role, Carol ran bp Shipping and was the chief operating officer for IST oil. She has more than 20 years’ experience in the energy industry, many in integrated supply and trading. Previous roles include chief operating officer for natural gas liquids, regional leader of global oil Europe and finance. Carol also served as the head of the group chief executive’s office. Giulia joined bp from McKinsey, where she was a senior partner. She led the global downstream oil and gas practice and was a key member of the chemicals and electricity, power and natural gas practices. She begins this role with more than 10 years’ experience in the energy sector, including helping companies shape their strategies for the energy transition. Kerry Dryburgh EVP, people & culture Leadership team tenure Appointed 1 July 2020 Nationality British Other board memberships Kerry sits as a non-executive director for the United Kingdom Strategic Command Career Kerry was previously head of HR for the Upstream and has held a series of senior HR positions. She was a key driver behind the Upstream people transformation during 2015-2017. Kerry previously ran HR in bp’s Shipping, IST and corporate functions teams. She brings experience from other sectors in Europe and Asia, having worked at both BT and Honeywell before joining bp. Eric Nitcher EVP, legal Leadership team tenure Appointed 1 July 2020 Eric previously served on bp’s executive team starting on 1 January 2017. Nationality American Other board memberships None Career Eric sat on the executive team as group general counsel from 2017. He played a key role in forming the Russian joint venture TNK-BP and settling Deepwater Horizon claims. He began his career as a litigation and regulatory lawyer in Wichita, Kansas. He joined Amoco in 1990 and over the years has held a wide variety of roles, both in the US and elsewhere. bp Annual Report and Form 20-F 2020 79 bp’s success is dependent upon effective and entrepreneurial leadership by the board, establishing its purpose, strategy and values and doing so within a framework of prudent and effective controls, which enable risks to be assessed and managed. The board is responsible to bp’s owners for promoting the long-term sustainable success of the company, generating value for its shareholders, while having regard to its other stakeholders, the impact of its operations on the communities within which it operates, and the environment. Primary tasks of the board in 2020 included Defining and establishing a new purpose and strategy, while assessing and monitoring whether they were consistent with bp’s culture and values. In light of the significant operational challenges presented by the COVID-19 pandemic, establishing a rhythm of board meetings to ensure that the leadership team was supported, providing guidance to the CEO to ensure that shareholder and other stakeholder interests were taken into account, while maintaining safe and reliable operations. Monitoring the activities and performance of bp’s leadership team, obtaining assurance about the delivery of 2025 and 2030 targets and aims and the sustainability frame within which they operate. Designing and establishing the board’s new corporate governance framework, including the delegations of authority under which it operates. Assessing and monitoring the principal risks and emerging risks of bp, having considered feedback from the committees of the board. Ways of working New ways of working were put in place during 2020 alongside the changes to the design of the board’s corporate governance framework. Meeting agendas were structured along four distinct pillars: strategy, performance, people, and governance, with the overarching focus being on the development of bp’s new strategy in support of its transition to an Integrated Energy Company. The board and its committees met regularly during the year, as well as on an ad hoc basis, as required by business needs. Attendance is shown in the table on page 84. Although the board and its committees were able to hold physical meetings in the early part of the year, once COVID-19-related restrictions and controls were introduced, most meetings took place virtually. Throughout the year, the board and its committees continued to engage effectively through the use of technology. Key areas covered during 2020 under each of these pillars are set out on the next page. Corporate governance Board activities Role of the board 80 bp Annual Report and Form 20-F 2020 Strategy During 2020 the board worked closely with the incoming chief executive officer (CEO) and his leadership team, establishing a new purpose and strategy for bp. bp’s purpose is to reimagine energy for people and our planet, with an ambition to become a net zero company by 2050 or sooner, and to help the world get to net zero. This new purpose recognizes: The world is on an unsustainable path – its carbon budget is running out. Energy markets have begun to shift towards low carbon and renewables. Oil and gas produced safely and efficiently will continue to perform a vital role for the world and our business, but over the longer term, demand for both oil and gas will be challenged. bp can contribute to the energy transition the world wants and needs and create value in doing so. The delivery and execution of the strategy that supports this new purpose is made possible through a resilient financial framework, including a new approach to capital allocation. In 2020 the board determined a new distribution policy, which will support us in facing an increasingly uncertain world, allow us to strengthen the balance sheet, invest in our resilient and valuable hydrocarbons business, and invest adequately into the energy transition. A new distribution policy was approved by the board, comprising a reset and resilient dividend and a firm share buyback commitment, see page 22. Associated with the new strategy, the board also agreed a number of tactical divestments, including the disposal of its petrochemicals business. Alongside this, new business opportunities were progressed, for example the formation of a strategic partnership with Equinor, to develop offshore wind energy in the US, see page 21. Against the backdrop of the board’s activities during 2020 described in this section, the table on pages 82 and 83 sets out some examples of board decision making in 2020 and how the directors have performed their duty under Section 172. Performance The board reviewed project, operational and safety performance throughout the year, as well as the latest view on full-year delivery against plan and the implications for the group’s scorecard measures. Equally, in light of the challenging macro-economic environment facing the sector, the company’s financial performance, liquidity, credit position and associated financial risks were closely and regularly monitored by the board. In this way and through the regular interactions that were taking place during the year, the board was able to satisfy itself that bp was performing while transforming. Reports supplementing the role played by the board included: CEO and chief financial officer (CFO) reports. Group financial outlook. The annual effectiveness of investment review. Quarterly and full-year results. Shareholder distributions. The annual plan and associated capital allocation commitments. On risk oversight, the board, assisted by its committees, also regularly reviewed its principal and emerging risks, including the process through which they are identified, evaluated and managed. Linked to this, the high-priority risks were reviewed in 2020, giving the directors the chance to seek assurance as to how those risks were prioritized and being managed. On internal controls, the board also assessed the effectiveness of the group’s system of internal control and risk management as part of the process through which it reviews and, ultimately, approves the bp Annual Report and Form 20-F. No specific areas of significant deterioration were identified in this assessment. The board concluded that the group’s system of internal control continued to be resilient. The board also concluded that the overall design of the group’s system of internal control generally meets external expectations of components to be included in internal control frameworks. In arriving at these conclusions, the board took into account reports from group risk and internal audit, as well as reviews undertaken by the board and its committees during the year. In conducting reviews during the year, the board and its committees considered the impact of remote working on the control environment, among other key factors. For more information on bp’s system of risk management see How we manage risk on page 64. Information about bp’s system of internal control is on page 127. Corporate governance People The board, through the former nomination and governance committee, continued to focus on reviewing its own composition, skills, experience and diversity, as well as that of the bp leadership team. Ultimately, new board appointments were made during the year, most notably with the retirement of the CEO, Bob Dudley, and CFO, Brian Gilvary, succeeded by Bernard Looney and Murray Auchincloss, respectively. Tushar Morzaria was appointed to the board and its audit committee with effect from September 2020. Karen Richardson and Dr Johannes Teyssen were appointed to the board with effect from 1 January 2021. Johannes was also appointed to the safety and sustainability committee with effect from the same date. A new leadership team under the CEO came into being on 1 July 2020. Through the new people and governance committee, the process for executive succession planning, talent management and development is being redesigned. People insights – particularly the reinvention of bp and its impact on the organization – were presented to the board and this committee by the CEO and EVP, people & culture, providing information on matters relating to people strategy, employee engagement, diversity and people processes and policies. To help inform board discussions and decisions, board members also engaged directly with the workforce in structured events, see page 87. Governance The board established a new corporate governance framework, which is more closely aligned with bp’s new purpose and also reinforces the effectiveness of the internal control framework. For more information on the new corporate governance framework see page 88. bp Annual Report and Form 20-F 2020 81 Corporate governance continued Decision making by the board The board delegates authority for the executive management of bp to the chief executive officer, subject to defined limits. Ultimately, the board retains responsibility for – and regularly monitors – the execution of this delegation of authority, taking action to update it as required. As part of the wider board corporate governance redesign, the board reviewed the delegation of authority, in part reflecting the need to ensure that it remained appropriate in light of bp’s new strategy, and the 2025 and 2030 targets and aims. The board’s new ways of working are explained on page 80 including certain matters that under the new corporate governance framework are reserved for the board as set out in its new terms of reference. The execution of company strategy is undertaken by the CEO’s leadership team, under the day-to-day authority for the management of the company delegated to the CEO. Reflecting its governance responsibilities, the board satisfies itself that the CEO and the leadership team’s actions are in keeping with the direction it sets through receipt of management reports at each board meeting. Matters reserved for the board and section 172 Issue faced and decision taken Establishing a new purpose and strategy for bp The board approved a new purpose for bp – reimagining energy for people and our planet – and a strategy to transition to an Integrated Energy Company and to meet the net zero ambition set out alongside bp’s purpose. Section 172(1)a) to (f) matters considered, including stakeholder group(s) affected and feedback received How the board had regard to the feedback in its decision making Workforce In town halls and leadership meetings employees wanted to know how bp could do more to step up to the climate challenge and help society deal with these issues. It became clear that employees were seeking even stronger commitments to the climate change agenda by the company. Community and environment We consulted with communities, NGOs, academics and industry associations – even bringing some of bp’s harshest critics into discussions about the future of the company, about environment, social and governance matters and the issues facing the world, drawing on their external expertise, input and challenge. Investors We talked with investors about their expectations of bp and heard of their desire for bp to continue to deliver operational excellence, to drive higher returns but also to set out a clear medium to long-term vision for a sustainable bp business in light of the energy transition. Fostering business relationships We received feedback from customers via the bp leadership team, conveying the importance of being able to react rapidly to changing demand. All the elements highlighted in Section 172 were central to the discussions as the board evaluated the purpose and strategy options – what are bp’s beliefs and what does bp want to be? The discussions encompassed bp’s role with respect to its shareholders, employees and society. It considered the value creation opportunities and the importance of leaning into the changing needs of customer demand for convenience and society’s demand for renewables and lower carbon energy. The change in purpose and strategy reflects bp’s people’s belief that we can create long-term value by helping solve one of society’s biggest problems – climate change. The decision was made with the long-term future and sustainability of bp in mind with clear 2025 targets, 2030 aims and a 2050 goal. More information on how the board had regard to the Section 172 factors Section 172 factor Key examples The likely consequences of any decision in the long term. Interests of employees. Fostering the company's business relationships with suppliers, customers and others. Reinventing bp: Our strategy How the board has engaged with shareholders, the workforce and other stakeholders Sustainability: People and society How we engage with our stakeholders Sustainability: Business ethics and accountability Impact of operations on the community and the environment. Managing our environmental impacts Sustainability: Safety Maintaining a reputation for high standards of business conduct. Role of the board Sustainability: Business ethics and accountability Acting fairly between members of the company. How the board has engaged with shareholders, the workforce and other stakeholders Page 15 86 57 63 61 57 59-60 80 61 86 Reinvent bp The board approved a reorganization of bp, retiring the existing model and replacing it with one that is more focused, more integrated and faces the energy transition head on. The reorganization will ultimately see around 10,000 employees leave bp. The board considered the importance of skills evaluation to the delivery The board supported the reinvention of bp, with the associated headcount of cost reduction and the wider long-term strategic delivery of bp’s aims. reduction that this implied. They heard feedback from the CEO’s ‘Keeping Connected’ webcasts Given the feedback received, although the board considered it was the with the workforce together with responses to bp’s ‘Pulse’ surveys. right decision to go ahead, they sought assurances from the executive that: Considerations The wider society context following the impact of COVID-19 and the wider oil industry job losses. The importance of putting the safety of employees first. Companies should try to provide job assurance and consider the mental health impact of job insecurity. bp’s reputation for high standards of conduct and the importance of honesty, fairness, and respect in the process. The redundancy process was fair, transparent and objective with an environment of honesty, trust and co-operation that put the care and wellbeing of our people at the heart of the process. The reduction in the workforce was conducted in a manner which protected bp’s safe and reliable operations. Support for the life transition that redundancy brings is offered to the relevant employees. Discretionary enhanced redundancy terms could be offered. Financial frame and distribution policy The board approved a new and resilient financial framework, including a coherent approach to capital allocation and a new distribution policy. In considering the proposed financial frame and distribution policy, the board had regard to: The resilience of bp’s balance sheet for the long term. Delivering sustainable value to shareholders. The need for bp to invest adequately in the energy transition and low carbon, to support the new ambition and strategy. In approving the new distribution policy the directors reflected that there may be some change in bp’s investor base as some investors focus more on the short-term direct return that the dividend provides. After considering all the various factors, the board concluded that a resilient dividend intended to remain fixed at 5.25 cents per ordinary share per quarter (subject to the board’s decision each quarter), with a commitment to return at least 60% of surplus cash« to shareholders through share buybacks (having reached $35 billion net debt« and subject to maintaining a strong investment grade credit rating), was in the best interest of the company, its shareholders as a whole and other stakeholder groups, as it enabled bp to offer sustainable value with increased investment in low carbon and non-oil and gas ventures. 82 bp Annual Report and Form 20-F 2020 Corporate governance Issue faced and decision taken Establishing a new purpose and strategy for bp The board approved a new purpose for bp – reimagining energy for people and our planet – and a strategy to transition to an Integrated Energy Company and to meet the net zero ambition set out alongside bp’s purpose. In the context of the board’s activities during 2020, the table below sets out some examples of board decision making in 2020 and how the directors have performed their duty under Section 172. Section 172(1)a) to (f) matters considered, including stakeholder group(s) affected and feedback received How the board had regard to the feedback in its decision making Workforce In town halls and leadership meetings employees wanted to know how bp could do more to step up to the climate challenge and help society deal with these issues. It became clear that employees were seeking even stronger commitments to the climate change agenda by the company. Community and environment We consulted with communities, NGOs, academics and industry associations – even bringing some of bp’s harshest critics into discussions about the future of the company, about environment, social and governance matters and the issues facing the world, drawing on their external expertise, input and challenge. Investors We talked with investors about their expectations of bp and heard of their desire for bp to continue to deliver operational excellence, to drive higher returns but also to set out a clear medium to long-term vision for a sustainable bp business in light of the energy transition. Fostering business relationships We received feedback from customers via the bp leadership team, conveying the importance of being able to react rapidly to changing demand. All the elements highlighted in Section 172 were central to the discussions as the board evaluated the purpose and strategy options – what are bp’s beliefs and what does bp want to be? The discussions encompassed bp’s role with respect to its shareholders, employees and society. It considered the value creation opportunities and the importance of leaning into the changing needs of customer demand for convenience and society’s demand for renewables and lower carbon energy. The change in purpose and strategy reflects bp’s people’s belief that we can create long-term value by helping solve one of society’s biggest problems – climate change. The decision was made with the long-term future and sustainability of bp in mind with clear 2025 targets, 2030 aims and a 2050 goal. Reinvent bp The board approved a reorganization of bp, retiring the existing model and replacing it with one that is more focused, more integrated and faces the energy transition head on. The reorganization will ultimately see around 10,000 employees leave bp. The board considered the importance of skills evaluation to the delivery of cost reduction and the wider long-term strategic delivery of bp’s aims. The board supported the reinvention of bp, with the associated headcount reduction that this implied. They heard feedback from the CEO’s ‘Keeping Connected’ webcasts with the workforce together with responses to bp’s ‘Pulse’ surveys. Given the feedback received, although the board considered it was the right decision to go ahead, they sought assurances from the executive that: Considerations The wider society context following the impact of COVID-19 and the wider oil industry job losses. The importance of putting the safety of employees first. Companies should try to provide job assurance and consider the mental health impact of job insecurity. bp’s reputation for high standards of conduct and the importance of honesty, fairness, and respect in the process. The redundancy process was fair, transparent and objective with an environment of honesty, trust and co-operation that put the care and wellbeing of our people at the heart of the process. The reduction in the workforce was conducted in a manner which protected bp’s safe and reliable operations. Support for the life transition that redundancy brings is offered to the relevant employees. Discretionary enhanced redundancy terms could be offered. Financial frame and distribution policy The board approved a new and resilient financial framework, including a coherent approach to capital allocation and a new distribution policy. In considering the proposed financial frame and distribution policy, the board had regard to: The resilience of bp’s balance sheet for the long term. Delivering sustainable value to shareholders. The need for bp to invest adequately in the energy transition and low carbon, to support the new ambition and strategy. In approving the new distribution policy the directors reflected that there may be some change in bp’s investor base as some investors focus more on the short-term direct return that the dividend provides. After considering all the various factors, the board concluded that a resilient dividend intended to remain fixed at 5.25 cents per ordinary share per quarter (subject to the board’s decision each quarter), with a commitment to return at least 60% of surplus cash« to shareholders through share buybacks (having reached $35 billion net debt« and subject to maintaining a strong investment grade credit rating), was in the best interest of the company, its shareholders as a whole and other stakeholder groups, as it enabled bp to offer sustainable value with increased investment in low carbon and non-oil and gas ventures. bp Annual Report and Form 20-F 2020 83 Corporate governance continued Independence Non-executive directors (NEDs) are expected to exercise independent judgement and to be free from any business or other relationship that could materially interfere with it. This independence is crucial in bringing constructive challenge to the CEO and the leadership team at board meetings, while providing support and guidance to promote meaningful discussion and, ultimately, informed and effective decision making. The board regularly reviews the independence of its NEDs, as advised by the company secretary, and takes action to identify and manage conflicts of interests, including those that may arise from significant shareholdings. This process helps to ensure that the influence of third parties does not compromise or override independent judgement. Directors are required to provide sufficient information to allow the board to evaluate their independence prior to and following their appointment. As a consequence of regular reviews throughout the year, the board has satisfied itself that there were no matters giving rise to any conflict of interests or which compromised the independence of the NEDs. It has therefore concluded that all bp NEDs are independent. Professor Dame Ann Dowling continues to serve on the board notwithstanding that she has served beyond nine years as a NED. Following careful consideration, the board believes that Ann continues to provide constructive challenge and robust scrutiny of matters that come before the board and the committee on which she serves. She has only served with the current executive directors for a year and the overall average tenure of the board is below the FTSE 100 average. In addition, in 2018 the board undertook significant refreshment of its composition. Accordingly, the board is satisfied that Ann continues to demonstrate the qualities of independence in carrying out her duties. Appointment and time commitment The chairman, senior independent director and other NEDs each have letters of appointment and do not serve, nor are they employed, in any executive capacity. There is no fixed term limit on a director’s service; however, in line with good governance practice, bp proposes all directors for annual re-election by shareholders. Unlike the chairman’s letter of appointment, the NEDs’ letters of appointment do not set a fixed time commitment. NEDs are expected to allocate appropriate time to effectively discharge their duties. The time required of NEDs fluctuates depending on the demands of bp business and other events. The COVID-19 pandemic, as well as the oversight by the board of the energy transition and associated workload, required the NEDs to spend considerably more time fulfilling their responsibilities towards bp during 2020, than in previous years. This included NEDs dedicating additional time through regular calls with the leadership team to remain informed and help guide the executive through unprecedented times. The NEDs’ external time commitments are regularly reviewed, ensuring that, even in the exceptional circumstances of a global pandemic, the NEDs are able to allocate appropriate time to bp. The review process is managed by the company secretary, considering NEDs’ outside appointments and commitments, including relevant factors such as complexity of company and industry, in particular highly regulated sectors, and issues impacting these other companies. The board has concluded that, notwithstanding the NEDs’ other appointments, they are each able to dedicate sufficient time to fulfil their bp duties. Executive directors are normally permitted to take up one board appointment at an external company, subject to the agreement of the chairman and after consultation with the company secretary. Bernard Looney and Murray Auchincloss each hold one non-executive directorship, shown on page 74. Prior to retiring from the board in June 2020, Brian Gilvary undertook a role as NED of Barclays PLC, in addition to his NED role with L’Air Liquide S.A.. Following consideration, it was concluded that Brian’s two external appointments were unlikely to be detrimental to his ability to perform his duties as outgoing CFO. Diversity At a time of significant change across the sector, and with bp transitioning to become an Integrated Energy Company, diversity of thought is as important as ever. Our purpose, to reimagine energy for people and our planet, can only be achieved through collaboration, innovation and constructive challenge that derives from having a diverse and inclusive workplace. The board understands and advocates that better decisions and outcomes are achieved when different people, with differences of opinions, from different backgrounds, come together with a common ambition. We recognize that diversity can take many forms, whether it be gender, social or ethnic backgrounds, personal identities, age, religion, physical abilities and more. All of which promote diversity of thought and reduce the risk of group think. The board has, and continues to have, regard to all these forms of diversity in respect of its processes including both its appointments and succession plans. The board and leadership team believe in leading by example and are pleased to have met the Hampton-Alexander and Parker review targets for 2021. At the end of 2020 the board comprised five female directors, representing 45% of the board (2019 42%, 2018 35%). Karen Richardson and Johannes Teyssen joined the board on 1 January 2021. Dame Alison Carnwath stepped down from the board on 14 January 2021. As previously announced, Brendan Nelson will be stepping down from the board at the conclusion of the 2021 AGM. The board is pleased that Tushar Morzaria, a Ugandan-born British national, joined in September 2020. He will succeed Brendan Nelson as audit committee chair following the 2021 AGM. Our senior management, as defined by the Corporate Governance Code 2018, and their direct reports comprise 43% women (2019 38%) and 25% Black, Asian and minority ethnic (BAME) individuals (2019 18%). While bp continues to benefit from the wide array of perspective and vision in decision-making processes and the company culture continues to strengthen through mitigation of group think, bp will continue to strive for increased diversity across its workforce, leadership team and board. For more information on our workforce diversity and inclusion see page 57. 84 bp Annual Report and Form 20-F 2020 Corporate governance Remuneration committee Geopolitical committee People and Governance committee A 1 3 3 B 1 2 3 A 4 9 9 5 B 4 7 7 5 9 9• 8 9• A 7• 3 7 7 7 7 B 7• 3 7 6 7 7 6 6 3• 3• Safety and sustainability committee A 2 B 2 6 6• 6 6• Attendance Non-executive directors Helge Lund Nils Andersen Dame Alison Carnwath Pamela Daley Sir Ian Davis Professor Dame Ann Dowling Melody Meyer Tushar Morzaria Brendan Nelson Paula Reynolds Sir John Sawers Executive directors Murray Auchincloss Bob Dudley Brian Gilvary Bernard Looney Board Audit committee A B A B 10 10 10 9 3 10• 10 3 10• 10 10• 3 10 10 10 10 10 3 10 10 10 5 2 5 8 10• 2 10 9 9 9 10 3 10 10 10 5 2 5 8 A Possible meetings B Attended meetings • Chair of board/committee bp Annual Report and Form 20-F 2020 85 Corporate governance continued How the board has engaged with shareholders, the workforce and other stakeholders Institutional investors We regularly engage with our institutional shareholders through an active investor relations programme. COVID-19 has meant that this engagement had to move online for the majority of 2020. The pinnacle of this virtual engagement was bp week in September 2020, led by Bernard Looney and members of his leadership team. The team innovatively engaged with shareholders giving detailed insights into bp’s new strategy and the 2025 and 2030 targets and aims. This engagement was also deliberately structured to allow for the increasingly important ESG constituency to be consulted in determining the targets and aims, including the overlay of the new sustainability frame in support of the new strategy. The board receives feedback from shareholders in many ways, particularly through the chairman and leadership team who meet with investors throughout the year. Numerous one-to-one meetings with major institutional investors and proxy advisory groups were hosted by the chairman in 2020. These engagements generated much insightful feedback which was shared with other board members and committees with due regard being given to these views. A similar programme of engagement on matters relating to the 2020 directors’ remuneration policy that was approved by shareholders at the AGM was undertaken during the year, led by the chair of the remuneration committee and senior independent director, Paula Reynolds. More details about this engagement are set out in the 2020 directors’ remuneration report on page 103. Retail investors In May we held our annual event for retail investors in conjunction with the UK Shareholders’ Association (UKSA) and the UK Individual Shareholders Society. For the first time this event was held virtually. The chairman, company secretary and head of investor relations gave presentations on bp’s annual results, strategy and the work of the board. Shareholders’ questions were primarily focused on bp’s response to the COVID-19 pandemic, bp’s sustainability strategy and financial performance. AGM In common with the practice adopted by many UK quoted companies, the 2020 AGM was held as a ‘closed’ meeting, with a minimum quorum present, in line with government rules at the time. Shareholders were invited to submit questions to the board before the meeting, all of which were addressed, and the event was broadcast live via webcast on bp.com. As expected, voting levels saw a slight decrease with the pandemic and stay-at-home orders disrupting shareholder voting. The overall turnout was 62.1% of the total voting rights, including votes cast as withheld, compared to 67.1% in 2019 and 67.3% in 2018. All resolutions passed at the meeting in line with the board’s recommendations. At the date of this report, measures put in place by the UK government in response to the COVID-19 pandemic preclude bp from holding an AGM in person. In these exceptional circumstances, bp’s 2021 AGM is planned to be a hybrid meeting. Shareholders will not be permitted to attend the meeting in person, but will be able to participate via bp’s electronic meeting platform. The board will continue to monitor developments in UK government guidance relating to the COVID-19 situation. If circumstances change materially before the date of the AGM, the board may decide to adapt proposed arrangements. Shareholder engagement cycle 2020 Q1 Q2 Q3 Fourth quarter and full-year 2019 results and strategy update Ambition launch Investor roadshows with the leadership team post the ambition launch bp Annual Report and Form 20-F 2019 bp Sustainability Report 2019 First quarter 2020 results presentation Investor roadshows with executive management following first quarter 2020 results UKSA (retail shareholders’) meeting with the chairman Other institutional shareholder engagement with the chairman 2020 AGM bp Statistical Review of World Energy Second quarter 2020 results and strategy presentation Investor roadshows with executive management follow second quarter 2020 results and strategy Capital markets event – ‘bp week’ bp Energy Outlook presentation Investor roadshows with the bp leadership team – capital markets event Q4 Third quarter 2020 results presentation Investor roadshows with the bp leadership team following third quarter 2020 results 86 bp Annual Report and Form 20-F 2020 Corporate governance A regular programme of engagement has been developed. Some sessions have a specific engagement purpose while others will simply be an open opportunity to hear views, interests, ideas and concerns. It is intended that a number of these sessions will have no line managers to allow for an unconstrained exchange of views. Engagement locations will be varied across our global operations. Alongside this programme, the ‘Pulse’ surveys, bp ‘Keeping Connected’ sessions, site visits (even if virtual) and the chairman’s programme of attendance at selected small team sessions will continue. The board believes the existing approaches and mechanisms described above enable comprehensive two-way engagement opportunities with bp’s workforce, and as such, is satisfied that these are effective alternatives to the proposed workforce engagement methods set out in Provision 5 of the Code. Looking beyond 2021 the board will continue to assess the effectiveness of its engagement with the workforce and how ultimately this informs the decisions that it takes, including the options provided for in the Code, for example appointing a director from the workforce. Workforce 2020 engagement We believe an engaged workforce is critical to us successfully delivering our strategy. When we talk about bp’s workforce, we include a wide range of employees, contractors, agency and remote workers across all of our geographical locations. The board is responsible for overseeing and monitoring bp’s culture and its values. This extends to putting in place mechanisms allowing for workforce views to be reflected in board discussion and decision making, complementing existing mechanisms that are established by the leadership team. Such measures include employees being informed on matters of concern to them through bp’s intranet and local sites, social media channels, town halls, site visits and webinars including topics such as quarterly results, strategy, the low carbon transition and diversity. We also have a number of employee-led forums and business resource groups (BRGs) and aim to build constructive relationships with labour unions formally representing some employees. Employees are consulted on a regular basis through regular team and one-to-one meetings and through our annual ‘Pulse’ survey. The board believes that the approaches and mechanisms described under Site visits, below, enabled effective engagement opportunities with the bp workforce. The board is satisfied that during 2020, these were effective alternatives to the proposed workforce engagement methods set out in Provision 5 of the UK Corporate Governance Code (the Code). Future of workforce engagement As part of its broader review of bp’s corporate governance framework, the board discussed whether its current approach to workforce engagement continues to be the most effective mechanism to inform its discussions and the decisions that it takes. Building on the experience that we have had, and the innovative approaches that were taken to workforce engagement through 2020, the board has sought to create a more rigorous framework so that there is clear channel through which the insights emerging from this engagement process will be consolidated and considered in board discussions and decision making. The board also considered the significant changes to the workforce following reinvent bp and bp’s wide geographic spread and size. Taking all these factors into account, the board concluded that for 2021 workforce engagement is best overseen by the newly constituted people and governance committee. Virtual engagements Virtual site visits During 2020 restrictions associated with COVID-19 disrupted planned opportunities for the board to engage with the bp workforce in person. As a result, most engagements were conducted virtually. The audit committee conducted a virtual visit and tour of bp’s trading floors in London and Houston and a majority of our non-executive directors attended a virtual visit of bpx energy’s Permian assets, led by the safety, environment and security assurance committee. During these visits, directors heard directly from the workforce regarding their perceptions of bp’s new strategy and how these businesses planned to implement it, as well as deepening their understanding of businesses and functions within bp. Business resource groups and focus groups Non-executive directors engaged virtually with employees in BRGs and focus groups throughout the year, including virtual events organized by the Women in Wells, Future Talent and One Young World alumni forums. Through these engagements the directors heard directly from employees on a range of topics, including bp’s new purpose and strategy, employee sentiment – particularly during the reorganization of bp – the impact of COVID-19 on operations and wellbeing, diversity and career progression. CEO ‘Keeping Connected’ webcasts Our CEO Bernard Looney hosted a series of webcasts featuring guests from across the organization to discuss a range of topics throughout the year, including bp’s new purpose, safety, mental health, and reinventing bp. Helge Lund, chairman of the board, joined the CEO as a speaker on two of these webcasts and non-executive directors were also invited to listen in. >12,500 average viewers per webcast bp Annual Report and Form 20-F 2020 87 Corporate governance continued Governance framework We completely redesigned the bp corporate governance framework in 2020, to more closely align with bp’s new purpose – reimagining energy for people and our planet – as well as our new strategy. The framework defines the board’s role, to promote the long-term sustainable success of the company, generating value for its shareholders while having regard to its other stakeholders, the impact of its operations on the communities within which it operates and the environment. The review had three main strands: 1. The role and purpose of the board The bp board believes that in order for governance to be effective it needs to have a regular review process across purpose, strategy, culture and values, while maintaining oversight of performance. Clearly defined terms of reference for the board were established together with a roadmap of activity that reflects those issues the board consider most important. The board terms of reference identify certain matters that are considered to be of such materiality at a group level that they are reserved for approval by the whole board and cannot be delegated. The matters reserved include, among others, certain investments, entry into new countries, changes to the company’s capital structure, distributions and bp’s code of conduct. The full list is available on bp.com/governance. 88 bp Annual Report and Form 20-F 2020 Purpose Considers bp’s purpose, which underpins its decision making. Monitors whether bp’s strategy, values and culture remain in line with that purpose. Values The board monitors bp’s values, ensuring that they are appropriate as the leadership team focuses on the execution of the new strategy. Board governance and performance oversight Culture Reviews the ambition and aims of the people plan and in so doing assesses and monitors any impact on culture so as to satisfy itself that bp’s purpose, strategy and values continue to be aligned with its culture. Strategy Receives regular updates to test that the strategy and strategic direction established by the board continue to be the right approach for the long-term sustainable success of bp in line with its purpose. Through the people and governance committee, reviews work on bp’s ways of working (including integration, agility, wellbeing, workplace, inclusion and digital). Approves the annual plan and regularly monitors that it is aligned with the approved strategy, including reviewing business development, investment effectiveness and capita allocation. Conducts deep dives across each of the business groups and key strategic areas. Receives regular updates on progress towards the aims and objectives in the sustainability frame. Corporate governance 2. Committees A review of the board committees looking at their purpose, scope and authority with a focus on: Fit with the strategic direction of the bp board. Risk and allocation of the review of risk. Alignment with the new leadership structure to give clear oversight. The new committee structure under the board is depicted in the diagram (right) and described below. The nomination and governance committee was renamed the people and governance committee to reflect its wider remit in covering workforce engagement, wellbeing and talent management. The safety, environment and security assurance committee was renamed the safety and sustainability committee. Its remit has been widened to include monitoring the effectiveness of implementation of bp’s sustainability frame, see page 48. This is an important step in light of bp’s new purpose and ambition. The other permanent committees – remuneration and audit – will remain. The results committee (comprising the chairman, CEO and chief financial officer (CFO)) also remains with delegated authority from the board to approve and authorize the release of the periodic financial statements and dividend announcements. The geopolitical committee has been replaced by a geopolitical advisory council rather than a board committee. It is attended by members of the board and the executive together with advisors who give a wider external view. The geopolitical highest priority risk is overseen at the board. Each of the four permanent committees has new terms of reference, adopted from 1 January 2021, to set out their role and responsibilities in a clear mandate, which can be found on bp.com/governance. The board will continue to review its framework annually to satisfy itself that it continues to be best aligned to bp’s purpose and strategy. Board and board committee structure Board People and governance committee Remuneration committee Audit committee Safety and sustainability committee The changes to bp’s purpose and strategy this year and bp’s journey towards becoming an Integrated Energy Company have given rise to the need for greater visibility on the decision- making criteria for capital expenditure and new business transactions. Accordingly, the board spends time examining and discussing the impact of portfolio changes such as strategic acquisitions and the allocation of capital, along with the annual plan, in order to gain a clear understanding of the methodology of capital allocation. The board reviews capital investments that are more than $3 billion for resilient hydrocarbons, more than $1 billion for all transition or low carbon investments and, in addition, any significant inorganic acquisition that is exceptional or unique in nature. Clear information flows have been established between the board and the leadership team. This allows greater time at board meetings to focus on strategic and people topics, enabling a fuller understanding and quality discussion of the challenges to deliver our new strategy. 3. New ways of working The board’s corporate governance review extended to documenting the responsibilities of the chairman, the CEO and the senior independent director so that their respective roles are clear both internally and to our external stakeholders. These are available on bp.com/governance. The board delegates day-to-day management of the business of the company to the CEO. This includes accountability to oversee the implementation of a comprehensive system of internal controls that are designed to, among other things, identify and manage the risks that are material to bp. The board continues to perform its oversight role and monitor bp’s performance. This responsibility extends to monitoring bp’s management and operations and obtaining assurance about the delivery of its strategy, and to oversee bp’s internal control and risk management frameworks. The chairman holds meetings without executive directors present at the start or end of board meetings. The CEO is responsible for maintaining a dialogue with the chairman and the board on important and strategic issues facing bp. Strategic opportunities or issues which may arise, or which are on the CEO’s mind, are discussed at board meetings and the CEO welcomes constructive challenge from non-executive directors in light of their wider experience outside bp. bp Annual Report and Form 20-F 2020 89 Corporate governance continued Learning, development and induction The developmental needs of the board as a whole and for individual directors are regularly reviewed, so as to ensure that the board and individual effectiveness to board discussion and decision making are maximized. A formal and comprehensive induction is provided to all directors following their appointment. This includes meetings with management, technical briefings and site visits. Board induction programme Tushar Morzaria, appointed on 1 September 2020, undertook a tailored and robust induction against the challenging backdrop of COVID-19. Tushar looks forward to continuing his introduction to bp’s operations and learning more about the business and its people. The programme was adapted to accommodate the inability to participate in physical meetings and site visits. Digital solutions were therefore deployed to facilitate Tushar’s induction. The programme included meetings with a wide range of senior management within bp, the external auditor and other key advisors. A selection of these and the areas of focus are outlined below. I am delighted to join the bp board and to contribute my expertise in support of bp’s new strategy. Tushar Morzaria Independent non-executive director Area Board and governance Audit committee Provided by Key topics covered Helge Lund, chairman Ben Mathews, group company secretary Brendan Nelson, chair of the audit committee Jayne Hodgson, SVP, accounting, reporting, control David Jardine, SVP internal audit Doug King, Deloitte (external audit partner) Overview of board and committee matters. Priority areas for the board. Governance framework. Corporate structure. Priority areas for the committee, including committee chair succession. bp’s financial position. Financial reporting framework and quarterly results close cycle. Internal audit reports. External audit and quarterly review reports. bp’s new strategy and sustainability focus. Overview of legal matters, including material litigation. Overview of treasury matters and liquidity risk management. Strategy and sustainability Legal Treasury Giulia Chierchia, EVP strategy & sustainability Eric Nitcher, EVP legal Kate Thomson, SVP treasury 90 bp Annual Report and Form 20-F 2020 Corporate governance Board evaluation Each year bp completes a formal and rigorous annual evaluation of the performance of the board, its committees, the chairman and individual directors. There is also a triennial requirement for this evaluation to be externally facilitated which will next fall due in 2021. The 2019 board evaluation highlighted three specific areas for action in 2020: Focus area Action taken Review the skills, experience and diversity of the board, and the process for executive succession planning and talent management and development. Satisfy itself that every member of the board has a deeper understanding of the board’s role in determining bp’s capital allocation process and in enabling more effective decision making. Redesign bp’s corporate governance framework, reinforcing the effectiveness of this control framework so that it is more closely aligned with bp’s new purpose and strategy. The board skills matrix was used to focus NED recruitment and we have successfully recruited three NEDs with strong experience in areas which will complement and support bp’s new strategy and provide diversity of thought. The board, through the former nomination and governance committee, heard regular updates on the selection process and criteria for the bp leadership team and the next layer of leadership with a focus on building a future succession pipeline and the skills needed to drive the execution of bp’s new strategy. The board and leadership team have developed a process for greater visibility of capital allocation at the board and evaluated the methodology of capital allocation. Capital allocation above agreed thresholds is now a matter reserved for the board. The board governance framework and ways of working were redesigned, details of which can be found on page 88. The 2020 board evaluation was an internal review. The chairman spoke with each director individually. The company secretary facilitated a theme-based review including, among other matters, portfolio management, the impact of the new board agenda, the evolution of bp’s purpose, strategy and values, stakeholder engagement and people matters. The review also looked at the composition and diversity of the board and how effectively the directors work together. In early 2021, the board held a special meeting to discuss the feedback, focusing on strategic and operational oversight, board development and maintaining a dynamic and flexible approach to board and committee agendas. An action plan for areas of focus was agreed. Following this meeting, the senior independent director led a meeting with the non-executive directors without the chairman present to appraise his performance. The directors expressed their strong support for the continued leadership shown by the chairman. bp Annual Report and Form 20-F 2020 91 Corporate governance continued People and governance committee Chair’s introduction I am pleased to present my report as chair of the people and governance committee. During 2020, the committee reviewed the composition of the board and, with the new purpose and strategy in mind, focused on identifying candidates who would enhance the strategic discussion in the boardroom and add to the diversity, skills and experience required as bp transitions to an Integrated Energy Company. We discussed and guided the development of the new board governance framework to satisfy ourselves that bp continues to maintain the highest standards of governance and we reviewed bp’s workforce engagement mechanism options in order to make a clear recommendation to the board. As part of the governance review, the committee was renamed as the people and governance committee with effect from 1 January 2021 to reflect its wider remit in covering workforce engagement, wellbeing and talent management. Looking to 2021, the committee agenda has been restructured to cover four matters: talent and capability, diversity and inclusion, engagement and culture and governance. Under that umbrella, we will oversee workforce engagement, engage an external provider for board effectiveness and continue to look at succession, leadership, talent, diversity and culture matters. Helge Lund Committee chair Committee overview Role of the committee The people and governance committee (previously called the nomination and governance committee, until 31 December 2020) seeks to ensure an orderly succession of candidates for directors, the company secretary and senior executives and oversees corporate governance matters for the group. Key responsibilities Identify, evaluate and recommend candidates for appointment or reappointment as directors. Identify, evaluate and recommend candidates for appointment as company secretary. Review the mix of knowledge, skills, experience and diversity of the board for the orderly succession of directors. Review the outside directorships/commitments of the non-executive directors (NEDs). Review developments in law, regulation and best practice relating to corporate governance and make recommendations to the board on appropriate action, including on environmental, social and governance matters. Meetings and attendance The committee met seven times in 2020. All members attended each meeting with the exception of Brendan Nelson who missed one meeting owing to a prior commitment. Membership Helge Lund Sir Ian Davis Nils Andersen Member since July 2018 and chair since September 2018 Member (resigned December 2020) Member (resigned March 2020) Brendan Nelson Paula Reynolds Sir John Sawers Member Member Member The committee focused on identifying candidates who would enhance the strategic discussion in the boardroom and add to the diversity, skills and experience required as bp transitions to an IEC. Helge Lund Committee chair 92 bp Annual Report and Form 20-F 2020 Corporate governance The committee received regular updates and challenged management on the reinvent bp proposals including the scale of the redundancies, the methodology associated with the selection process and details of the process controls and management of change to satisfy itself that safety would be maintained and a respectful process completed. The committee heard detailed considerations on the workforce engagement mechanism options and discussed the benefits and issues of each option presented in order to make a recommendation to the board for 2021. Activities during the year Reflecting its role in respect of board succession planning, early in 2020, the committee’s priority was to identify new non-executive directors to succeed two of the longer-serving members of the board – Sir Ian Davis and Brendan Nelson. Candidates were sought with the technical and professional skills to take on certain committee responsibilities, including in particular the chairmanship of the audit committee, plus also candidates who would be able to support the chair of the board as the senior independent director. These characteristics were broadened so as to identify candidates who would also enhance the strategic discussion in the boardroom. External headhunters were engaged to support the process and identify candidates. These headhunters had no other connection to the company or its directors during the year. The search process led to the appointment of Tushar Morzaria in September 2020 and, from among the existing board members, Paula Reynolds as the senior independent director. Each of these appointments was considered to fulfil the search criteria, including the succession of the audit committee chairmanship. The committee also agreed new search categories for other NED candidates, broadly covering the areas of digital/technology and energy, reflecting the strategic shift of bp to become an Integrated Energy Company and the dependency on digital as an enabler to transform companies. Karen Richardson and Johannes Teyssen together bring extensive financial, technological, transformation and energy industry experience to the board. Planning for new board members to help ensure a strong focus on strategic execution, safety and sustainability and connectivity to bp’s core businesses and markets continues. Committee meetings in 2020 included updates and discussions on the redesign of bp’s corporate governance framework, more details of which are set out on page 88. Operational excellence and risk management Global business leadership and governance People leadership and organizational transformation Technology, digital and innovation Energy markets Society, politics and geopolitcs Finance, risk, trading Background and experience Skills matrix Non-executive directors Pamela Daley Ann Dowling Helge Lund Melody Meyer Tushar Morzaria Brendan Nelson Paula Reynolds Karen Richardson Sir John Sawers Johannes Teyssen bp Annual Report and Form 20-F 2020 93 Corporate governance continued Audit committee Membership Brendan Nelson Member since November 2010 and chair since April 2011 Dame Alison Carnwath Member (resigned from the board in January 2021) Pamela Daley Paula Reynolds Tushar Morzaria Member Member Member since September 2020 (chair-designate) Brendan Nelson is chair of the audit committee. See page 76 for his biography. The board is satisfied that he is the audit committee member with recent and relevant financial experience as outlined in the UK Corporate Governance Code and competence in accounting and auditing as required by the FCA’s Corporate Governance Rules in DTR7. It considers that the committee as a whole has an appropriate and experienced blend of commercial, financial and audit expertise to assess the issues it is required to address, as well as competence in the oil and gas sector. The board also determined that the audit committee meets the independence criteria provisions of Rule 10A-3 of the US Securities Exchange Act of 1934 and that Brendan may be regarded as an audit committee financial expert as defined in Item 16A of Form 20-F. Committee overview Role of the committee The committee monitors the effectiveness of the group’s financial reporting (including reporting on the financial aspects of climate matters), systems of internal control and risk management and the integrity of the group’s external and internal audit processes. Key responsibilities during 2020 Monitoring and obtaining assurance that the process to identify, manage and mitigate principal and emerging financial risks are appropriately addressed by the CEO and that the system of internal control is designed and implemented effectively in support of the limits imposed by the board (‘executive limitations’). Overseeing the appointment, remuneration, independence and performance of the external auditor and the integrity of the audit process as a whole, including the engagement of the external auditor to supply non-audit services to bp. Reviewing the effectiveness of the internal audit function, bp’s internal financial controls and systems of internal control and risk management. Reviewing financial statements and other financial disclosures and monitoring compliance with relevant legal and listing requirements. Reviewing the systems in place to enable those who work for bp to raise concerns about possible improprieties in financial reporting or other issues and for those matters to be investigated. Meetings and attendance There were 10 committee meetings in 2020. All members attended each meeting with the exception of Pamela Daley who was absent from the March meeting owing to prior commitments. Regular attendees at the meetings include the chief financial officer, SVP accounting reporting control, SVP internal audit, EVP legal and external auditor. The committee was particularly focused on the impacts of bp’s reorganization and the COVID-19 pandemic on financial performance, the financial control environment and resilience. Brendan Nelson Committee chair 94 bp Annual Report and Form 20-F 2020 Corporate governance Chair’s introduction I am pleased to introduce the report on the audit committee’s activities during the year. During the year, the committee has continued to assist the board in fulfilling its oversight responsibilities, by monitoring the integrity of the group’s financial reporting and risk management systems, and also by challenging management and external auditors across a number of key areas of focus, including key accounting judgements and control issues. In addition to the routine committee agenda for the year, the committee was particularly focused on the impacts of bp’s reorganization and the COVID-19 pandemic on financial performance, the financial control environment and resilience. I welcome the addition of Tushar Morzaria to the committee from September 2020. His broad financial experience is immensely beneficial to the committee and bp. Following year end, Dame Alison Carnwath stepped down from the committee and the board. I would like to thank her for her diligent contribution to the committee over the years. This is my last report as chair of the audit committee. I would like to thank my board and committee colleagues, as well as management, for the open, challenging and constructive nature of discussions we have conducted during my tenure. As I hand over the committee chair to Tushar in May 2021, I remain confident that bp is well-positioned for continued resilience and success. Brendan Nelson Committee chair Activities during the year How the committee reviewed financial disclosure The committee reviewed the quarterly, half-year and annual financial statements with management, focusing on the: Integrity of the group’s financial reporting process. Clarity of disclosure. Compliance with relevant legal and financial reporting standards. Application of accounting policies and judgements. As part of its review, the committee received regular updates from management and the external auditor in relation to accounting judgements and estimates, including those relating to recoverability of asset carrying values. The committee keeps under review the frequency of results reporting during the year. In considering the bp Annual Report and Form 20-F, the committee assessed whether the report was fair, balanced and understandable and also whether it provided the information necessary for shareholders to assess the group’s position and performance, business model and strategy. In making this assessment, the committee examined disclosures during the year, discussed the requirement with senior management, confirmed that representations to the external auditors had been evidenced and reviewed reports relating to internal control over financial reporting. The committee made a recommendation to the board, who in turn reviewed the report as a whole, confirmed the assessment and approved the report’s publication. How accounting judgements and estimates were considered and addressed The committee was briefed on a quarterly basis in 2020 on the group’s key accounting judgements and estimates. The primary areas of judgement and estimation which were considered by the committee are set out below. These areas were discussed with management and the external auditor throughout the year and during the preparation of these financial statements. The committee is satisfied that the financial statements appropriately address the key accounting judgements and estimates both in respect of the amounts reported and disclosures made. During the year, the committee also considered and approved a change to bp’s accounting policy relating to physically settled commodity contracts, with effect from 1 January 2021. The committee’s process for considering key accounting judgements and estimates included an assessment of matters at various stages during the year. This primarily included the key accounting judgements and estimates set out on pages 98 and 99. The committee also considered and addressed key accounting estimates and judgements relating to provisions, pensions and other post-retirement benefits, and supplier financing arrangements via briefings and review of the group’s assumptions. See Notes 23, 24 and 29 respectively for further information. bp Annual Report and Form 20-F 2020 95 Corporate governance continued How risks were reviewed The principal risks allocated to the audit committee for monitoring in 2020 included those associated with: Trading activities: including risks arising from shortcomings or failures in systems, risk management methodology, internal control processes or employees. In reviewing this risk, the committee focused on external market developments and how bp’s trading function had responded to a rapidly changing environment, including enhancing its control environment policies to strengthen its compliance and control culture. The committee further considered updates in the trading and shipping function’s risk management programme, including compliance with regulatory developments, activities in response to cyber threats, and efficiencies derived from more collaborative ways of working across group functions and businesses and the use of digital technologies. The committee also considered the impact of COVID-19 on operations and the control environment associated with trading activities, with particular reference to operational considerations associated with increased remote working. Compliance with business and regulations: including ethical misconduct or breaches of applicable laws or regulations that could damage bp’s reputation, adversely affect operational results and/or shareholder value and potentially affect bp’s licence to operate. The committee reviewed the group’s programme on controls and contingencies for managing this risk, including enhanced approaches to monitor the risk in light of business evolution (such as an increase in venturing), as well as other internal and external trends. Cyber security risk: including inappropriate access to or misuse of information and systems and disruption of business activity. The committee reviewed ongoing developments in the cyber security landscape, including events in the oil and gas industry and within bp itself. The review focused on a strengthened approach in order to manage the ever-increasing threat of cyber risk and maintain cyber security, as the focus on a digital transformation across bp continues. Financial liquidity: including the risk associated with external market conditions, supply and demand and prices achieved for bp’s products which could impact financial performance. The committee reviewed the key assumptions and underlying judgements used to manage the group’s liquidity and capital investments (including appraisal, effectiveness and efficiency). How other reviews were undertaken Other reviews undertaken in 2020 by the committee included the following, and in each case where the committee received segment and function reviews, each reported on strategy, performance, capability and risk management as well as on their first, second and third lines of defence policies as appropriate: Information technology and services: including the functions performance, strategy and optimization of core services to enable the digitization and modernization of bp at pace. bp ventures and Launchpad: including the purpose, capabilities, operating model, governance and performance of these entities. Reinvent bp programme: including a review of programme milestones and risks, as well as business continuity and management of change. Tax: including strategy, performance, key drivers of the group’s effective tax rate, the global indirect tax environment, the tax modernization programme and the evolving approach to management of key risks. The committee also reviewed bp’s tax transparency report. Internal audit functional review: including a five-year plan for the function in a reinvented bp. Trading and shipping: including strategy, performance, capability and risk management. Effectiveness of investment: annual review of performance of projects with sanctioned capital over a certain threshold. Internal controls: assessments of management’s plans to remediate the external auditor’s control findings. How internal control and risk management was assessed Internal audit The committee received quarterly reports on the findings of internal audit in 2020, including their assessment of issues raised in previous years, especially those relating to IT access controls. The committee also received a report from internal audit on their annual review of the system of internal control and risk management. The committee met privately with the SVP, internal audit and key members of his leadership team. The committee continued to monitor and review the effectiveness and capabilities of internal audit during the year. During the year, the committee received a report on the findings of an assessment conducted by internal audit of its conformance with the Internal Audit Code of Practice which was published in January 2020. The committee noted that internal audit conforms with the vast majority of recommendations set out in the code. Actions to achieve full conformance with the code were also noted. Training and briefings The committee considered market updates and developments throughout the year. This included technical accounting updates from the SVP accounting reporting control on developments in financial reporting and accounting policy, as well as on accounting and disclosure changes that would be introduced as a result of the reorganization of the group. The committee also received briefings on specific topics, including non-operated joint ventures, and data analytics used by the external auditor. Site visit during the year In October 2020, the committee conducted a virtual visit of the trading & shipping function, including virtual presentations from the trading floor, covering low carbon trading, global power and global crude. Key areas of discussion during this site visit included the impacts of oil price volatility, COVID-19 and the reinvent bp programme on the business and its operations during 2020. 96 bp Annual Report and Form 20-F 2020 FRC thematic review The bp Annual Report and Form 20-F 2019 was included in the FRC’s sample for its limited scope thematic review on reporting on the impact of climate change. bp subsequently received a letter request for information from the FRC’s Corporate Reporting Review team. The audit committee considered the letter and bp’s detailed response thereto, which enabled the FRC to close its enquiries. The committee notes the further enhancements made to disclosures in relation to climate change and the energy transition in this annual report. An FRC review provides no assurance that bp’s Annual Report 2019 was correct in all material respects. The FRC’s role was not to verify the information provided but to consider compliance with reporting requirements. Its letters are written on the basis that the FRC (which includes the FRC’s officers, employees and agents) accepts no liability for reliance on them by bp or any third party, including but not limited to investors and shareholders. External audit How the committee assessed audit risk The external auditor set out its audit plan for 2020, identifying significant audit risks to be addressed during the course of the audit. These included: Impairment of upstream oil and gas property, plant and equipment. Impairment of exploration and appraisal assets. Accounting for structured commodity transactions. Valuation of level 3 instruments in trading and shipping revenue recognition. Management override of controls. The committee received updates during the year on the audit process, including how the auditor had challenged the group’s assumptions on these issues. How the committee assessed audit fees The audit committee reviews the fee structure, resourcing and terms of engagement for the external auditor annually; in addition it reviews the non-audit services that the auditor provides to the group on a quarterly basis. Fees paid to the external auditor for the year were $54 million (2019 $49 million), of which 1.9% was for non-audit and other assurance services (see Financial statements – Note 36). The audit committee is satisfied that this level of fee is appropriate in respect of the audit services provided and that an effective audit can be conducted for this fee. Non-audit or non-audit related assurance fees were $1 million (2019 $1 million). Non-audit or non-audit related services consisted of other assurance services. How the committee assessed audit effectiveness Management undertook a survey which comprised questions across the following: (i) The main criteria to measure the auditor’s performance were: – Robustness of the audit process – Independence and objectivity – Quality of delivery – Quality of people and service (ii) bp’s commitment to the audit; and (iii) Aligned audit approach – which sought to measure progress against the commitments from the audit tender. Year on year, the overall score from the survey increased by +3%. Improvements were seen across audit effectiveness and service quality, including a number areas of focus that had been identified in the previous survey. The committee also held private meetings with the external auditor during the year and the committee chair met separately with the external auditor and group head of audit at least quarterly. The effectiveness of the external auditor is evaluated by the audit committee. The committee assessed the auditor’s approach to providing audit services. On the basis of such assessment, the committee concluded that the audit team was providing the required quality in relation to the provision of the services. The audit team had shown the necessary commitment and ability to provide the services together with a demonstrable depth of knowledge, robustness, independence and objectivity as well as an appreciation of complex issues. The team had posed constructive challenge to management where appropriate. How the auditor reappointment and independence was assessed The committee considers the reappointment of the external auditor each year before making a recommendation to the board. The committee assesses the independence of the external auditor on an ongoing basis and the external auditor is required to rotate the lead audit partner every five years and other senior audit staff every five to seven years. No partners or senior staff associated with the bp audit may transfer to the group. Corporate governance How the committee had oversight of non-audit services The audit committee is responsible for bp’s policy on non-audit services and the approval of non-audit services. Audit objectivity and independence is safeguarded through the prohibition of non-audit tax services and the limitation of audit-related work which falls within defined categories. bp’s policy on non-audit services states that the auditor may not perform non-audit services that are prohibited by the SEC, Public Company Accounting Oversight Board (PCAOB), International Auditing and Assurance Standards Board (IAASB) and the UK Financial Reporting Council (FRC). The audit committee approves the terms of all audit services as well as permitted audit-related and non-audit services in advance. The external auditor is considered for permitted non-audit services only when its expertise and experience of bp is important. Approvals for individual engagements of pre-approved permitted services below certain thresholds are delegated to the SVP accounting reporting control or the chief financial officer. Any proposed service not included in the permitted services categories must be approved in advance either by the audit committee chair or the audit committee before engagement commences. The audit committee, chief financial officer and SVP accounting reporting control monitor overall compliance with bp’s policy on audit-related and non-audit services, including whether the necessary pre-approvals have been obtained. The categories of permitted and pre-approved services are outlined in principal accountant’s fees and services on page 327. bp Annual Report and Form 20-F 2020 97 Corporate governance continued Examples of how accounting judgements and estimates were considered and addressed Key judgements and estimates in financial report Exploration and appraisal intangible assets Audit committee activity Conclusions/outcomes bp uses technical and commercial judgements when accounting for oil and gas exploration, appraisal and development expenditure. Judgement is required to determine whether it is appropriate to continue to carry intangible assets related to exploration costs on the balance sheet. Judgemental aspects of oil and gas accounting are reviewed routinely in bp’s quarterly due diligence process. Received the output of management’s annual intangible asset certification process used to verify that accounting criteria to continue to carry the exploration intangible balance are met. Significant exploration write-offs were recognized during the year (as disclosed in Note 8). Exploration intangibles totalled $4.1 billion at 31 December 2020. Recoverability of asset carrying values Determination as to whether and how much an asset, cash generating unit (CGU) or group of CGUs containing goodwill is impaired involves management judgement and estimates on uncertain matters such as future commodity prices, discount rates, production profiles, reserves and the impact of inflation on operating expenses. Reserves estimates based on management’s assumptions for future commodity prices have a direct impact on the assessment of the recoverability of asset carrying values reported in the financial statements. Impact of climate change and the energy transition Climate change and the transition to a lower carbon economy may have significant impacts on the currently reported amounts of the group’s assets and liabilities and on similar assets and liabilities that may be recognized in the future. Reviewed policy and guidelines for compliance with oil and gas reserves disclosure regulation, including the group’s reserves governance framework and controls. Reviewed the group’s oil and gas price assumptions. Reviewed the group’s discount rates for impairment testing purposes. Upstream impairment charges, reversals and ‘watch-list’ items were reviewed as part of the quarterly due diligence process. The group’s price assumption for Brent« oil and for Henry Hub«gas were revised downward and the period covered extended to 2050 as set out on page 28 and Note 1. Sensitivity analyses estimating the effect of changes in revenue and discount rate assumptions have been disclosed in Note 1. Significant impairments were recorded in the year as a result of the lower price assumptions as disclosed in Note 4. Headroom on goodwill balances was reduced (see Note 14 for further information). Reviewed management’s best estimate of oil and natural gas price assumptions for value-in-use impairment testing. Reviewed management’s assessment of recoverability of exploration intangibles. Received briefings on decommissioning provisions. Management’s revised best estimate of oil and natural gas prices are broadly in line with a range of transition paths consistent with the goals of the Paris climate change agreement. Exploration write-offs were recognized as a result of revised expectations to extract value from certain exploration prospects (see Note 8 for further information). Reasonable changes in the expected timing of decommissioning do not have a significant impact on the associated provisions. 98 bp Annual Report and Form 20-F 2020 Corporate governance Key judgements and estimates in financial report Impact of COVID-19 Audit committee activity Conclusions/outcomes The following areas involving judgement and estimates were identified as most relevant with regard to the impact of the COVID-19 pandemic and current economic environment: going concern, discount rate assumptions, oil and natural gas price assumptions, pensions and other post retirement benefits, impairment of financial assets measured at amortized cost and income taxes. Received briefings on COVID-19 impacts as part of the quarterly due diligence process. Reviewed liquidity forecast assessments. performed to support the going concern assertion. Reviewed discount rates used for impairment testing and provisions. Reviewed management’s best estimate of oil and natural gas price assumptions for value-in-use impairment testing. Investment in Rosneft Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. bp uses the equity method of accounting for its investment in Rosneft and bp’s share of Rosneft’s oil and natural gas reserves is included in the group’s estimated net proved reserves of equity- accounted entities. The equity-accounting treatment of bp’s 19.75% interest in Rosneft continues to be dependent on the judgement that bp has significant influence over Rosneft. Derivatives Reviewed the judgement on whether the group continues to have significant influence over Rosneft. Considered IFRS guidance on evidence of participation in policy-making processes. Received reports from management which assessed the extent of significant influence, including bp’s participation in decision making. bp continues to be resilient despite current economic conditions. The committee is satisfied with management’s assessment that the group will continue to operate as a going concern for at least 12 months from the date of approval of the financial statements. Material impairment charges and exploration write-offs were recognized in the Upstream segment as a consequence of price assumption changes. See Note 1 for further information. bp’s CEO, Bernard Looney, was appointed to the Rosneft board of directors in June 2020. bp has retained significant influence over Rosneft throughout 2020 as defined by IFRS. See Note 1 for further information. For its level 3 derivative financial instruments, bp estimates their fair values using internal models due to the absence of quoted market pricing or other observable, market- corroborated data. Judgement may be required to determine whether contracts to buy or sell commodities meet the definition of a derivative, in particular LNG« contracts. Received regular reports on derivative accounting judgements. Received a briefing on the group’s trading risks and reviewed the system of risk management and controls in place. Reviewed the control process and risks relating to the trading business. bp considers that contracts to buy or sell LNG do not meet the definition of a derivative under IFRS. bp has assets and liabilities of $6.4 and $5.3 billion respectively, recognized on the balance sheet for level 3 derivative financial instruments at 31 December 2020 mainly relating to the activities of the trading and shipping function. bp’s use of internal models to value certain of these contracts has been disclosed in Note 30. bp Annual Report and Form 20-F 2020 99 Corporate governance continued Safety and sustainability committee Chair’s introduction I am pleased to present my second report as chair of the SASC. During 2020, the committee continued to work with the bp leadership team to promote safe and reliable operations within the organization. Operational risk management remained a key area of focus during 2020, against the challenging backdrop of the COVID-19 pandemic with the result that bp maintained a good safety record during the year despite these challenges. The committee (together with other non-executive directors) conducted a virtual visit of bpx energy Permian assets in December 2020. We were very impressed with the safety culture and performance demonstrated by the bpx energy colleagues with whom we interacted during this virtual visit, and we look forward to being able to conduct a physical visit in due course. As part of the review by the board of its governance framework, the committee was renamed as the safety and sustainability committee with effect from 1 January 2021. The committee’s remit has also been expanded to include monitoring the effectiveness of the implementation of bp’s sustainability frame. This is an important step in light of bp’s new purpose and ambition and I look forward to continuing to work with the bp leadership team in furtherance of the new purpose, underpinned by safety and sustainability. Nils Andersen stepped down from the committee and the board in March 2020. I would like to thank him for his valuable contribution and commitment to the committee and I welcome Johannes Teyssen as a new member of the committee from the beginning of 2021. Melody Meyer Committee chair Committee overview Role of the committee The role of the safety and sustainability committee (SASC) (previously called the safety, environment and security assurance committee, until 31 December 2020) is to look at the processes adopted by bp’s executive management to identify and mitigate significant non-financial risk. This includes monitoring the management of personal and process safety risk, security and environment risks and receiving assurance that processes to identify and mitigate such non-financial risks are appropriate in their design and effective in their implementation. Key responsibilities during 2020 The committee receives specific reports from the business segments and functions, which include, but are not limited to, the safety and operational risk function, shipping, internal audit and group security. The SASC can access any other independent advice and counsel it requires on an unrestricted basis. The SASC and audit committee worked together, through their chairs and secretaries, to ensure that agendas did not overlap or omit coverage of any key risks during the year. Meetings and attendance There were six committee meetings in 2020. All directors attended every meeting for which they were eligible. In addition to the committee members, all SASC meetings were attended by the CEO, the SVP for safety and operational risk (S&OR) and the SVP internal audit and/or his delegate. The EVP legal also attended some of the meetings. At the conclusion of each meeting the committee scheduled private sessions for the committee members only, without the presence of executive management, to discuss any issues arising and the quality of the meeting. The CEO receives invitations to join the private meetings on an ad hoc basis and at least once a year the SVP internal audit is invited to a private meeting with the committee. Membership Melody Meyer Nils Andersen Member since May 2017 and chair since November 2019 Member (resigned March 2020) Professor Dame Ann Dowling Member Sir John Sawers Member The committee continued to work with the bp leadership team to promote safe and reliable operations. Melody Meyer Committee chair 100 bp Annual Report and Form 20-F 2020 Activities during the year System of internal control and risk management The review of operational risk and performance forms a large part of the committee’s agenda. Internal audit provided quarterly reports on its assurance work and its annual review of the system of internal control and risk management. The committee also received regular reports from the CEO and SVP S&OR on operational risk, including regular reports prepared on the group’s health, safety, security and environmental performance and operational integrity. These included meeting-by-meeting measures of personal and process safety, environmental and regulatory compliance, security and cyber risk analysis, as well as quarterly reports from internal audit. In addition, the SVP, internal audit regularly met in private with the chair and other members of the committee over the course of the year. During the year the committee received separate reports on bp’s management of risks relating to: The committee reviewed these risks and their management and mitigation in depth with relevant executive management. The committee reviewed the 2020 forward programme for the internal audit function. The committee supported the remuneration committee in relation to remuneration policy. Virtual site visit In December 2020 the members of the committee (together with the non-executive directors of the board) made a virtual visit to the bpx energy Permian site. Discussions during this visit covered a broad range of bpx energy health, safety and environment matters and provided an opportunity for effective virtual engagement with bpx energy staff. Corporate reporting The committee oversaw the bp Sustainability Report 2019. The committee reviewed the content and worked with the external auditor with respect to its limited assurance of selected sustainability KPIs. Marine Wells Pipelines Explosion or release at our facilities Major security incidents Cyber security (process control networks) Corporate governance bp Annual Report and Form 20-F 2020 101 Corporate governance continued Geopolitical committee Committee overview Role of the committee The committee monitors the company’s identification and management of geopolitical risk. Key responsibilities Monitor the company’s identification and management of major and correlated geopolitical risk and consider reputational as well as financial consequences. Review bp’s activities in the context of political and economic developments on a regional basis and advise the board on these elements in its consideration of bp’s strategy and the annual plan. Major geopolitical risks are those brought about by social, economic or political events that occur in countries where bp has material investments. Correlated geopolitical risks are those brought about by social, economic or political events that occur in countries where bp may or may not have a presence but that can lead to global political instability. Meetings and attendance The chairman and CEO regularly attend committee meetings. The chief executive of Alternative Energy and executive vice president, regions and the head of government and political affairs attend meetings as required. The committee met three times during the year. All directors attended each meeting that they were eligible to attend, with the exception of Sir Ian Davis who missed one meeting due to a prior commitment. Membership Sir John Sawers Nils Andersen Sir Ian Davis Member since September 2015 and chair since April 2016 Member (resigned March 2020) Member (resigned December 2020) Melody Meyer Member Chair’s introduction I am pleased to report on the work of the geopolitical committee in 2020. The committee’s agenda developed and evolved during the year, reflecting a year with a significant number of geopolitical developments globally. Following changes to the board governance framework that took effect on 1 January 2021, the committee was replaced by a geopolitical advisory council. Although the council is not a formal committee of the board, its membership includes other directors, certain members of the bp leadership team and three external advisors, with myself as chair. The geopolitical highest priority risk is now overseen by the board as a whole, informed by feedback from the council. Sir John Sawers Committee chair Activities during the year Early in the year, the committee considered the potential impact on bp of policies and plans of the new EU Commission and new UK government elected in December 2019. Later in the year, the committee considered the geopolitics of the COVID-19 pandemic and its impact on businesses and policies. The impacts of different potential outcomes of the November US election were discussed by the committee at its meeting in September 2020. The committee also received periodic geopolitical updates on a number of territories in which bp has significant interests throughout the year. The committee’s agenda developed and evolved during the year, reflecting a year with a significant number of geopolitical developments globally. Sir John Sawers Committee chair 102 bp Annual Report and Form 20-F 2020 Directors’ remuneration report Chair’s letter Contents Alignment with strategy 2020 performance and pay summary 2018-20 performance share plan outcome Executive directors’ pay for 2020 Wider workforce in 2020 Stewardship and executive director interests Non-executive director outcomes and interests Other disclosures Policy implementation for 2021 108 110 111 113 115 118 121 123 124 The committee wishes to place on record our gratitude for all that bp’s people achieved last year, and our acknowledgment of the challenging environment they faced. We look forward to better days ahead. Paula Rosput Reynolds Committee chair Corporate governance Dear shareholder, Last year was enormously challenging – for the world and for bp. Yet the bp team operated safely and reliably, ran the business as well as could possibly be expected, and launched a strategic transformation of the company. That bp achieved so much last year is a credit to everyone in the company – from the leadership to the front lines. Together, they delivered the energy the world needs, and positioned the company for the future. Nevertheless, as COVID-19 took its toll around the globe, there were consequences for bp’s financial outcomes in 2020. The remuneration committee always seeks to align employee reward with shareholder experience. Thus, despite extraordinary efforts on the part of the organization, we decided that there should be no 2020 pay-out for all those who normally participate in our broadly-applicable annual bonus plan. We know that this decision was painful for bp’s people, many of whom count on earning a cash bonus as part of their personal and family financial planning. While words cannot substitute for remuneration not received, the committee wishes to place on record our gratitude for all that bp people achieved amidst the environment they faced. We look forward to better days ahead. Shareholder engagement Throughout this challenging period when we had many decisions to make regarding metrics and reward, the committee has benefited from engagement with our shareholders. The remuneration policy under which we now operate was directly shaped by a meeting we held with bp’s top 25 shareholders and other proxy representatives in 2019. We appreciated shareholders’ overwhelming support (96.58% approval) of the new policy at our AGM last May. Throughout 2020, we have continued to meet (virtually) with our largest shareholders to discuss a range of performance and incentive topics in detail. We are grateful for your counsel and hope you will see your advice reflected in the decisions which we have reached. We ask for your support of this directors’ remuneration report, and the decisions described herein, at the forthcoming annual general meeting. bp Annual Report and Form 20-F 2020 103 Directors’ remuneration report continued In this report, the committee continues its practice of scrutinizing both one- and three-year performance. Even in the absence of paying annual bonuses for 2020, we have included some discussion on results to give a balanced view of what worked well and what disappointed. This report covers our decisions for 2020 and the details regarding our implementation of the 2020 remuneration policy for 2021 and beyond. The highlights are provided immediately below. Key remuneration outcomes for 2020 No pay-out under our 2020 annual bonus plan. There was no pay-out under the annual bonus plan for any of the participating employees Lower vesting for the 2018-2020 equity plan. The vesting outcome for our 2018-20 performance shares cycle is 32.5% of maximum, down from 71.2% in the previous cycle, and from an average of over 66% over the last six cycles. It is worth noting that the committee made no alterations to the performance measures or targets on which these awards were based, nor any discretionary adjustment to the vesting outcome. This vesting outcome applies equally to our former executive directors, and to our new CEO and CFO in respect to their pre- appointment performance share awards. Key remuneration decisions for 2021 and beyond To recognize the efforts of the wider workforce, virtually all employees will receive an above-market pay increase in 2021. Large numbers of our employees received no pay adjustment in 2020 or had their increase deferred for six months. Given the large reduction in headcount and all the responsibility this action places on those who remain, we agreed with management’s plan to increase salaries across-the-board, and ahead of market. Any time salaries rise, the cost of other remuneration that hinges off salary rises as well. At the same time, we are obligated to monitor disparate impacts and overall welfare of the workforce. We will, therefore, continue to monitor and balance the costs of the programme with wider workforce pay issues. We considered the approach to salary for our executive directors apart from the wider workforce. We embrace restraint as a guiding principle, but restraint must be balanced with fair reward for contribution. The board has been gratified by the immediacy of Bernard Looney’s impact in leading the organisation, and in refreshing bp’s purpose, strategy and organisation. We propose to recognize his efforts with an increase of 2.75% salary with effect from the annual general meeting. This increase is significantly lower than the increase that our UK professional workforce will receive on their pay review date in 2021. Murray Auchincloss has likewise made an immediate impact since his appointment. He fully assumed the challenges of the CFO role and has forged a strong partnership alongside Bernard. We set his initial salary in 2020 at a level below comparable rates for finance directors in the FTSE 30, until we could be certain of the contribution he would bring to the role. Shareholders will recall our policy is to keep executive increases within the boundary of wider workforce increases, except in specific circumstances. We find that Murray is already contributing beyond our expectations of even a seasoned CFO. Given his criticality to the execution of our strategy, we conclude that adjusting his below-market salary is such a specific circumstance. We therefore intend to increase his salary by 8% to £750,500, following the annual general meeting, placing him in line with the median rate for FTSE 30 CFOs. It is our intention, subject to the committee’s view of Murray’s continued development and success in role, to bring his salary in line with that of his predecessor and other CFOs in similarly challenging roles. We anticipate that this may require increases somewhat above the wider workforce average in the future. In 2021 we have made an all-employee share award to allow employees to participate in the success that a reinvented bp can deliver. The majority of employees will receive restricted shares vesting in 2025, while more senior employees will receive share options to be exercised from 2025 onward and with a ten-year term. We are bringing our metrics and targets for both the 2021 annual bonus and the 2021-23 performance share into line with bp’s new strategy and the refreshed commitments to financial performance. The changes are described in detail in this report and we hope you will see how closely we have sought to align these targets to the commitments that management have articulated to investors. The 2021-23 awards will be in line with approved policy and the grant size is unchanged from prior years. All share awards will be granted after the annual meeting and pricing will be based on the preceding 90 days. Overview of financial performance, operating achievements, and strategic progress Our 2020 annual bonus plan consisted of measures associated with financial performance and operations. Our long-term share plan consisted of financial measures and strategic progress. Each area of performance is summarized below to provide a sense of how we evaluated overall performance. Financial performance for bonus purposes was measured in terms of underlying replacement cost profit and free cash flow. For performance shares, we measured return on average capital employed (ROACE) and relative total shareholder return (rTSR). In neither the short nor the long-term plan did actual financial performance meet targets. Over the three-year performance period, however, bp ranked third out of the five super- majors for rTSR purposes which accounted for a modest 12.5% vesting of the 2018-20 performance share grant. To offer some perspective, we note that during 2020 the company reduced net debt by $6.5 billion to $39 billion. In announcing the sale of a share of bp’s interest in Oman’s Block 61, we continue making good progress towards the 2025 target of $25 billion of proceeds from divestments. Importantly, too, management initiated the review of bp’s portfolio of assets in 2020 and recommended significant impairments and exploration write- offs. Thus, management took the necessary steps to address the value of our assets given the energy transition, in full knowledge that they would forego near-term benefit because of these actions. We think this reflects well on the system of reward – not paying when performance is below expectations – but also on the integrity of the leadership which is nonetheless doing the right thing to create a sustainable future. 104 bp Annual Report and Form 20-F 2020 Corporate governance Despite the challenges of the pandemic, operations were strong in 2020, with refining availability of 96%, upstream plant reliability of 94%, and delivery of four new major projects. Safety trends were also positive, with process safety events, recordable injury frequency, and other key safety and environmental metrics significantly lower than in 2019. While workforce hours were down, bp people safely managed increased COVID-19-related risks and travel restrictions, and increased quarantine periods associated with cross-border crew rotations, while ensuring safety critical staffing and emergency response preparedness. bp teams also delivered above-target sustainable emissions reductions in 2020. Strategic progress is the other area we assessed; in the 2018-20 performance share plan it carried a 20% weight. As we consulted with shareholders, we can appreciate that the inclusion of ‘strategic progress’ in a scorecard can be a double-edged sword. On the one side, measuring strategic progress more specifically aligns our strategy and the reward we will confer. On the other side, strategic progress does not always carry with it straightforward metrics that are more typically used in remuneration designs. Thus the committee must use its judgement and explain its rationale. We do so here on page 111. We hope you will agree that we’ve been thoughtful in evaluating the organization’s strategic performance over the 2018-20 period. Other decisions and forward-looking activity In our approved 2020 remuneration policy, we retained flexibility to adjust performance measures and weightings in both our annual bonus and performance share plans. Given the shift in the business mix and the exigencies of our financial frame, for the 2021 annual bonus, we are introducing two new financial measures: cumulative cash cost reductions (weighted at 25%); and an operational measure to reflect margin share from convenience retail and electrification (weighted at 10%). These changes represent the committee’s best judgment for fine-tuning measures to the new strategy. While we are adding two new measures, we will continue to measure annual performance of our operations, of cash generation, of sustainable emissions reductions and of safety. For the 2021-23 performance share awards, we will introduce an earnings per share growth (EBIDA CAGR) measure alongside the existing ROACE measure (each weighted at 20%), and will reduce the weighting on rTSR (from 40% to 20%). Many of you will recall that the relevance of rTSR and the selection of an appropriate peer group were widely, but inconclusively discussed, during our September 2019 stakeholder engagement session. Against that backdrop, our judgment is that if the bp team can achieve the multi-year financial results to which it committed in July 2020, then the team should be rewarded, with only a modest calibration to what other energy companies accomplish over these three years. Remuneration committee Role of the committee The role of the committee is to determine and recommend to the board the remuneration policy and to set chair, executive director and leadership team remuneration. It reviews workforce remuneration and monitors related policies, satisfying itself that incentives and rewards are aligned with bp’s culture. In determining the policy, the committee takes into account various factors, including workforce remuneration, and structures the policy to promote the long-term success of the company and linking reward to performance. Key responsibilities Recommend to the board the remuneration principles and policies for the executive directors while considering remuneration and related policies for employees below the board and the executive team. Set and approve the terms of engagement, remuneration, benefits and termination of employment for the executive directors, leadership team and the company secretary in accordance with the policy. Prepare the annual remuneration report to shareholders to show how the policy has been implemented. Approve the principles of any equity plan that requires shareholder approval. Ensure termination terms and payments to executive directors and leadership team are fair. Receive and consider regular updates on workforce views and engagement initiatives related to remuneration, insight from data sources on pay ratio, gender pay gap and other workforce remuneration outcomes as appropriate. Maintain appropriate dialogue with shareholders on remuneration matters. Membership Paula Rosput Reynolds Member since Nils Andersen Pamela Daley Sir Ian Davis Melody Meyer September 2017 and chair since May 2018 Member (resigned March 2020) Member Member (resigned 30 December 2020) Member since March 2020 Brendan Nelson Member Meetings and attendance The chairman and the CEO attend meetings of the committee except for matters relating to their own remuneration. The CEO is consulted on the remuneration of the CFO, the leadership team and more broadly on remuneration across the wider employee population. Both the CEO and CFO are consulted on matters relating to the group’s performance. bp’s EVP people and culture, SVP reward and wellbeing and advisors attend meetings and other executives may attend where necessary. The committee consults other board committees on the group’s performance and on issues relating to the exercise of judgement or discretion as necessary. The committee met nine times during the year. All directors attended each meeting that they were eligible to attend, except Sir Ian Davis who was not able to attend two meetings, and Pamela Daley and Brendan Nelson who each missed one committee meeting. bp Annual Report and Form 20-F 2020 105 In this directors’ remuneration report RC profit (loss), underlying RC profit, return on average capital employed, operating cash flow excluding Gulf of Mexico oil spill payments, margin share for convenience and electrification, net debt and cumulative cash cost reductions are non-GAAP measures. These measures, together with upstream plant reliability and refining availability, are defined in the Glossary on page 341. Directors’ remuneration report continued Also noteworthy for the 2021-23 performance share awards, we are recasting the strategic progress measures to three well-defined areas: (1) delivering value through a resilient and focused hydrocarbon business; (2) building scale and value through investments in lower carbon electricity and energy sources; and (3) accelerating growth in convenience and mobility. Strategic progress metrics will be weighted at 40%. Several shareholders have asked us to be more specific about which measures from the September 2020 presentations we intend to use in evaluating strategic progress, and I say more on this at page 109 in the alignment to strategy section. The leadership team has been bold in seeking to transform bp and has shown exemplary cooperation in developing these challenging performance measures. Wider workforce and activities through the pandemic Much of the committee’s time this year was dominated by the pandemic, which had a serious impact on workforce and remuneration matters. With our plans to reinvent bp already proceeding when the pandemic hit, bp’s leadership committed that no redundancies would take place for a minimum of three months to allay immediate concerns about job security. Also, bp sought no pandemic relief in the form of grants or furlough funding from any governments anywhere in the world. Despite the limited ability to meet in person, the committee and the board engaged with employees virtually throughout the year. Despite the fact that 2020 was a year with many discouraging moments, we find that the employees are highly engaged – and willing to speak their minds – which bodes well for the future. From the outset of the pandemic’s impact, mental health as well as physical well-being were of concern. Both Bernard and our chair Helge Lund donated 20% of their salaries to charities dealing with mental health issues from April 2020. In addition, Bernard directed the company to make a substantial donation to the UK mental health charity, Mind. This generosity is consistent with the leadership’s support for mental health within the company, and given the duration and far-reaching effects of the pandemic, was exceptionally far-sighted. Closing thanks Following their retirement from the board, I thank Nils Andersen and Sir Ian Davis for their many contributions to this committee, while welcoming Melody Meyer and, most recently, Tushar Morzaria. At the annual general meeting, Brendan Nelson plans to stand down and his particular brand of sober judgement will be greatly missed by the committee. The technology we have all deployed in the last year has only served to enhance our consultation with shareholders and their advisors. These virtual face-to-face contacts from our respective homes have allowed for frequent conversations. We thank you for fitting us into your long days, and as you review the details provided in this report, we welcome your comments. Paula Rosput Reynolds Chair of the remuneration committee 22 March 2021 106 bp Annual Report and Form 20-F 2020 Remuneration at a glance Salary and benefits Retirement benefits Annual bonus Performance shares Corporate governance Purpose and key features Outcomes for 2020 Implementation in 2021 Fixed remuneration reflecting the scale and complexity of our business, enabling us to attract and keep the highest calibre global talent. Reviewed annually and, if appropriate, increased following the AGM. Benchmarked to market at inception with increases limited to those of our wider workforce, except in specific circumstances. To recognize competitive practice in home country. Bernard is a deferred member of a UK final salary pension plan, but now receives a cash allowance in lieu of retirement benefits. Murray is a deferred member of a US final salary pension plan, but now receives a cash allowance in lieu of retirement benefits. Bob was a member of both a US final salary pension plan and a US retirement savings plan. Brian was a member of a UK final salary pension plan and received a cash allowance in lieu of further service accrual. To incentivize delivery of our annual and strategic goals. 112.5% of salary at target, and 225% at maximum. To reinforce the long-term nature of our business and the importance of sustainability, 50% of the bonus is paid in cash and 50% is mandatorily deferred and held in bp shares for three years. To align reward to our strategy and long-term performance. Vesting outcomes vary relative to our financial returns and strategic priorities. Annual grant of performance shares, representing the maximum outcome. 500% of salary for the chief executive officer and 450% of salary for chief financial officer. Bernard Looney’s salary set at £1,300,000 on appointment. Murray Auchincloss’s salary set at £695,000 on appointment. Bob Dudley’s salary unchanged at $1,854,000 until cessation. Brian Gilvary’s salary unchanged at £790,500 until cessation. Benefits were unchanged. Bernard has no further service accrual for his deferred pension, and the pension calculation will be based on his pre-appointment salary. His cash allowance is fixed at 15% of salary. Murray has no further service accrual for his deferred pension arrangement, and the pension calculation will be based on his pre-appointment salary. His cash allowance is fixed at 15% of salary. Bob’s defined benefit pension did not increase in 2020. bp actual and notional retirement savings plan contributions of $32,445 were more than offset by investment losses within his plans, hence he received no net benefit in 2020. Brian’s defined benefit pension increase was below inflation. His cash allowance was 30% of salary to 30 May, and 25% of salary from 1 June 2020. No bonus for 2020. Awards granted in 2018 (under our 2017 policy) were assessed against our balanced scorecard of financial (80%) and strategic progress (20%) measures. Our 2018-20 performance share outcome is 32.5% of maximum vesting. Bernard’s salary to increase by 2.75% to £1,335,750 from the AGM. Murray’s salary to increase by 8% to £750,500 from the AGM. Benefits to remain unchanged. Bernard’s cash allowance will be unchanged at 15% of salary, and he accrues no further value under his deferred pension. Murray’s cash allowance will be unchanged at 15% of salary, and he accrues no further value under his US deferred pension. For our 2021 bonus, our scorecard will be reweighted to safety (15%), environment (15%), operational (20%) and financial (50%), as described on page 125. Awards granted in 2019 (under our 2017 policy) will vest in proportion to success against the measures of our 2019-21 scorecard. For the 2021-23 cycle (under our 2020 policy), grant levels will remain unchanged at 500% for Bernard and 450% for Murray, with weightings of 20% each for rTSR, ROACE and EBIDA CAGR, and 40% for strategic measures, as shown on page 125. The minimum shareholding requirements remain unchanged. Shareholding requirement To ensure sustained alignment between shareholder and executive director interests. The chief executive officer and other executive directors are required to maintain shareholdings equivalent to 500% and 450% of salary respectively, including for two years post employment (2020 policy). Both former executive directors materially exceed their post- employment share ownership requirements of two and a half times salary (pre-dating the 2020 policy). Bernard and Murray have not yet achieved their minimum shareholding requirement (they must do so within five years of appointment). bp Annual Report and Form 20-F 2020 107 Directors’ remuneration report continued Alignment with strategy The frame for our remuneration policy and practice Last year we refreshed our remuneration policy following wide consultation, individually and collectively, with shareholders. Through that consultation we decided to retain the strongly performance-oriented reward model that served us well in the previous decade. Thus, we retained and built upon the established policy structure, with the advantage this brings of being well- understood and accepted by our executives and wider workforce alike. bp’s purpose, ambition and strategy bp’s purpose, to reimagine energy for people and our planet, is complemented with a clear and unambiguous ambition – to be a net zero company by 2050 or sooner and to help the world get to net zero. Our strategy is transformational, to pivot from International Oil Company to Integrated Energy Company, from a focus on developing resources, to a focus on delivering solutions for customers. As seen below, this strategy is grounded in three focus areas and three sources of differentiation, set within a sustainability frame linking our strategy to our purpose. By design, this refreshed policy allows for ongoing alignment to the nearer-term needs of our strategy, with measures intended to evolve in line with the pace and form of the energy transition. This design reflected the four broad themes that emerged from our engagement with shareholders: A clear end-to-end alignment from strategy, through measurable performance indicators and reward outcomes, to shareholder experience. To balance our contribution to the energy transition with delivering shareholder returns, with encouragement to use appropriate discretion given the complexity of the environment in the energy transition. To ensure strategic measures align to long-term sustainability, relative to a wide peer group. To use meaningful and transparent performance indicators reflecting our progress in the energy transition and reductions to our carbon impact. Connecting remuneration to strategy Alignment with strategy is evident in: Clearly measurable safety, sustainability, strategic and financial measures for each cycle of annual bonus and/or performance shares. The judgements we make to assess qualitative progress against strategic objectives. Our ‘underpin’ assessment to take safety outcomes into account prior to determining the final performance shares vesting percentage. Our overarching discretionary decisions to ensure share plan outcomes reflect shareholder experience, environmental, societal, and other inputs. Achieving balance between safety, sustainability, strategic and financial measures is an essential consideration for the committee in applying policy. Considering the three ‘focus areas’ of bp’s strategy, generating cash from our resilient and focused hydrocarbons business is the critical element to support bp’s transition into the two growth areas – low carbon electricity and energy, and convenience and mobility. We expect bp to be directing 40% or more of its investment into these areas by 2030, but that reallocation of spend will be a gradual and non-linear matter, requiring flexibility and judgement from leadership. Our commitment is to oversee this transition with care, applying remuneration policy to incentivize results in the most critical areas. In our most recent consideration we have therefore aligned the strategic performance measures of our 2021-23 performance share awards entirely to the three ‘focus areas’ of bp strategy: low carbon electricity and energy; convenience and mobility; and resilient and focused hydrocarbons. This means that, for now, we are consciously not introducing measures related to the three ‘sources of differentiation’, in the belief that we need to limit the total number of measures and highlight those which are the most pressing. This has also led us to review our decision- making from last September when we set strategic measures for the 2020-22 performance share awards. At that time, we had chosen four strategic elements – two of the focus areas, and two of the sources of differentiation. With the hindsight of our more recent discussions and a deeper understanding of how the strategy is likely to yield most value, we realise those earlier decisions were not the best. Therefore, we are taking the unusual step of amending our 2020-22 strategic progress measures mid-cycle, to align them instead with the measures of our 2021-23 cycle. Thus we bring focus to the most critical areas, align the measures for the first two cycles of share award under our 2020 policy, and can develop a common set of performance metrics that will allow us to transparently report progress across all three cycles of award under the 2020 policy (ie. those starting in 2020, 2021 and 2022). The table on page 109 summarizes the alignment between performance measures and strategy, showing the weightings associated with each. Low carbon electricity and energy Convenience and mobility Resilient and focused hydrocarbons Integrating energy systems Partnering with countries, cities and industries Driving digital and innovation A sustainability frame linking our purpose and 108 bp Annual Report and Form 20-F 2020 Corporate governance Aligning performance measures and strategy Safety, our core value Low carbon Convenience and mobility Resilient hydrocarbons Integrating energy Partnering Digital Sustainability Financial frame 2020 annual bonus 2021 annual bonus 2020-22 performance shares 2021-23 performance shares 20% – – 10% – – – 20% 15% – 10% 10% – – 15% Underpin Underpin 30%{ { 40% – – – – – – – – 25% cash flow 25% profit 25% cash flow 25% cumulative cash cost reduction 40% rTSR 30% ROACE 20% rTSR 20% ROACE 20% EBIDA CAGR Looking forward, strategic progress for the 2020-22 and 2021-23 performance shares will be a largely qualitative assessment by the committee, supported by key performance indicators that will enable us to add a quantitative overlay in our assessments and to allow reporting on progress through the concurrent cycles of each award. These indicators are as follows: Resilient and focused hydrocarbons Production costs per barrel: track improvement in unit production cost per barrel to help deliver margin efficiency. Plant reliability: measure the reliability of upstream production assets as an indicator of operational efficiency. Refining availability: measure the availability of downstream refining assets, also as an indicator of operational efficiency. Demonstrate track record, scale and value in low carbon electricity and energy Gigawatts of developed renewables energy: confirm the growth and value added from new renewable energy projects. Clear decisions on other energy platforms: demonstrate strategic progress in the selection of energy platforms for future growth. Renewables pipeline: build a renewable pipeline in alignment with 2025 and 2030 goals while consistent with targeted returns. Accelerate growth in convenience and mobility Castrol performance: demonstrate growth momentum in Castrol. Strategic convenience sites: confirm the number of strategic convenience sites. Margin share from convenience and electrification: demonstrate the capture of growth from the energy transition through the retail network via measuring the ratio of convenience and electrification gross margin to total consumer energy (retail fuels and electrification) and convenience gross margin. bp Annual Report and Form 20-F 2020 109 Directors’ remuneration report continued 2020 performance and pay outcomes Business performance An exceptional year of challenge and internal reinvention Key strategic highlights Completed the Southern Gas Corridor pipeline system, with the Trans Adriatic pipeline beginning gas deliveries. Agreed to sell our petrochemicals business to INEOS. Added ~300 strategic convenience sites across our retail network, bringing the total to 1,900. 3rd Among peers for total shareholder return 2018-20 $13.8bn Operating cash flow excluding Gulf of Mexico oil spill payments $6.4bn Total dividends paid to shareholders Performance outcomes Robust safety and operating outcomes, but plan unaffordable. Strong strategic progress, weak financials. 2020 annual bonus No bonus Formulaic outcome (% of maximum) n/a Committee judgement 2018-20 performance shares n/a Final outcome (% of maximum) 32.5% Formulaic outcome (% of maximum) 0% Committee judgement, no adjustment 32.5% Final outcome (% of maximum) KPI Performance dimensions (% weighting) Performance dimensions (% weighting) This legend denotes remuneration measures that directly relate to bp’s key performance indicators. See page 39. Safety (20%) Environment (20%) Operational (10%) Financial (50%) No bonus for 2020 Financial (80%) Strategic progress (20%) KPI KPI 12.5/80 20/20 Annual bonus outcome (% of maximum) Performance shares outcome (32.5% of maximum) Bernard Looney Nil Murray Auchincloss Nil Nil Bob Dudley Nil Brian Gilvary Bernard Looney Murray Auchincloss Bob Dudley Brian Gilvary £0.35m £0.22m $1.57m £0.62m Total remuneration 2020 See page 113 for detail. Bernard Looney CEO from 5 February 2020 Murray Auchincloss CFO from 1 July 2020 Bob Dudley CEO to 4 February 2020 Brian Gilvary CFO to 30 June 2020 1. 1. 1. 1. 4. 2. £1.74m 2019: n/a 4. £0.62m 2019: n/a 2. $0.19m 2019: $13.3m 2. £0.55m 2019: £6.6m 1. Salary and benefits 2. Retirement benefits 3. Annual bonus 4. Performance shares Share ownership Shareholding is a key means by which the interests of executive directors are aligned with those of shareholders. The CEO and CFO shareholdings are shown below, as at 2 March 2021. Both these new executive directors are building towards the policy requirement, which is mandatory within five years of appointment. Bernard Looney, CEO Murray Auchincloss, CFO Policy requirements Actual 1.24 times salary, 543,939 shares 0.60 times salary, 141,535 shares 110 bp Annual Report and Form 20-F 2020 Corporate governance 2018-20 performance share plan outcome Vesting under our performance share plans is assessed using the group performance scorecard shown on page 112, and subject to any discretionary adjustment by the committee. Bernard and Murray were granted 2018-20 performance share awards under the Group Share Value Plan (GSVP) for bp group leaders, rather than under the Executive Director Incentive Plan (EDIP). The GSVP and EDIP both use the same scorecard, therefore the comments in this section apply equally to our former and new executive directors, as well as our group leaders, even though they relate to performance shares awarded under different plans. The financial outcomes for the three-year period were disappointing. Return on average capital employed averaged 2.6% over 2019 and 2020 (the ROACE measurement period for this cycle), below our threshold level for vesting on this measure. Total shareholder returns turned negative for bp, alongside all our constituent peer companies. bp placed third among our competitor group, however, which yielded formulaic vesting of 12.5% (of a potential 50%). To counter the impact of share price volatility in TSR measures, bp has continued its standard practice of averaging US market prices over the fourth quarter immediately before, and at the end of, the three-year performance cycle. Peers in our competitor group may use different pricing methods, leading them to report different ranking outcomes from bp. As reported last year, we introduced four strategic progress measures in our 2017 policy, and this is now the second cycle for which we have made an assessment on strategic progress. These were the measures that then positioned bp for the future, and the committee found that in all four strategic areas the business has delivered fully against intended outcomes. Thus vesting on this element of the scorecard is determined to be 20%. The key factors that formed our scoring decision were: Growing gas and advantaged oil in the upstream. Gas production grew from 1.11mmboed in 2017 to 1.15mmboed by 2020, with eight major gas projects started up in the period. In the same period bp started up seven major oil projects and have a further eight major oil projects under construction. We purchased BHP tight oil assets, accessing some of the best basins onshore in the US. Market-led growth in the downstream. We have continued strategic progress with our convenience partnership model now in around 1,900 sites across the network, with 800 opened since 2017. The growth has been driven by the roll-out of REWE to Go in Germany, our Thorntons business in North America, and new partnerships launched in South Africa, Australia, New Zealand and Portugal. Retail store gross margin has grown 6% per annum since 2017 to over $1bn and is showing resilience despite COVID-19. In growth markets, we doubled our retail sites to 2,700 in 2020, expanded our network to over 500 bp-branded retail sites« in Mexico, and opened over 1,400 sites in India with our Reliance joint venture. In our sustainable aviation fuel business, we added 13 new locations to Air bp’s supply network and have struck an innovative collaboration with Neste for supply of sustainable aviation fuel. We have made a further $40 million investment in Fulcrum since 2017. Venturing and low carbon across multiple fronts. Lightsource bp now has a presence in 14 countries, up from five in 2018. We have created a differentiated strategy in electric vehicle charging through bp pulse and Storedot, which has demonstrated five-minute charging capability. Our focus on reducing emissions has progressed well, with a reduction from 48.8Mte in 2018 to 41.7Mte in 2020, aligning with our net zero ambition. Our 2020 methane intensity is estimated at 0.12%, well below our target of 0.2% Gas power and renewables trading and marketing growth. We remain the largest US gas and power marketing company. In 2018 and 2019 we added six advanced liquified natural gas (LNG) tankers to the bp-operated fleet; our Tangguh LNG expansion started drilling in 2019; and Train 2 of our Freeport LNG began commercial operations in 2020, with first gas deliveries from bp under our 20-year tolling agreement. Along with the combination of financial and strategic measures, the committee considers an ‘underpin’ decision before deciding on the final result, taking a broader view to ensure that the reward outcome aligns with absolute shareholder returns, safety and environmental factors, and low carbon and climate change considerations. The committee has been mindful of the need to take an even broader perspective, and thus consider executive outcomes in relation to societal matters in general and our wider workforce in particular. While absolute returns disappoint, we find that all aspects of the underpin support at least 32.5% vesting, which from a participant’s perspective reflects a poor return for the efforts expended. Therefore, our overall judgement is to leave the vesting outcome unadjusted. As mentioned above, this scorecard outcome applies to all participants in both the EDIP (for executive directors) and the GSVP (for group leaders). With time pro-ration for Bob and Brian to reflect their periods of service during the three-year performance period, this vesting delivers the outcomes detailed below. For Bernard and Murray these values are included in the single figure table on page 113, whereas for Bob and Brian they are reported in the payments for past directors section at page 122. 2018-20 performance share plan outcomes (audited) Shares awarded 158,690b 77,958b 1,395,600 696,705 Shares vesting including dividends Value of vested shares, Feb/ Mar 2021 Impact of share price changea 126,134 62,124 £350,652 $275,934 410,922 $1,566,298 £618,357 227,337 -£228,991 -$111,497 -$962,923 -£430,217 Bernard Looney Murray Auchinclossc Bob Dudleyc Brian Gilvary a These values reflect the impact of the reduction in share price since grant related to the number of shares that vest, excluding dividend equivalents. b Share grants under the GSVP are made at 50% of maximum, not at 100% of maximum as for the EDIP. c Bob Dudley and Murray Auchincloss’s awards were granted in respect of American depositary shares (ADSs). The numbers in this table reflect calculated equivalents in ordinary shares. One ADS equates to six ordinary shares. The value of vested shares reflects the share price changes all shareholders have experienced over the three-year period. For this 2018-20 award cycle, the original grant was calculated based on ordinary share and American depositary share (ADS) prices of £5.00 and $39.85 respectively, while the values at vesting were £2.78/£2.72 (on 16 and 19 February respectively), and $22.87/$26.65 (on 19 February and 10 March respectively). Consequently, the share price fall has reduced the initial face value of these awards by approximately 45% for ordinary shares, by 33% for Murray Auchincloss’s ADSs, and by 43% for Bob Dudley’s ADSs. The committee has made no discretionary adjustment to vesting outcomes related to these share price changes. bp Annual Report and Form 20-F 2020 111  See page 39 for more on our key performance indicators. Formulaic vesting 32.5% Outcome Third Directors’ remuneration report continued 2018-20 performance shares scorecard (audited) These measures were set under the terms of our 2017 policy Relative total shareholder return 12.5% + Return on average capital employed 0% + Strategic process 20.0% = Measures Financial Strategic progress Formulaic Formulaic vesting 32.5% Relative total shareholder return Return on average capital employed Growing gas and advantaged oil in the upstream Market-led growth in the downstream Venturing and low carbon across multiple fronts Gas power and renewables trading and marketing growth Weighting at maximum Threshold performance Maximum performance 50% Third First 30% 7.375% 11.5% 2.6% Outcome 12.5% 5% 5% 5% 5% Qualitative and quantitative assessment by the committee. No numeric scale for vesting outcome. See page 111 Outcome 20.0% 12.5% 0% 5.0% 5.0% 5.0% 5.0% 32.5% Underpin: Committee review of absolute returns, long-term safety and environmental performance, low carbon and climate change considerations: No adjustment Final vesting after committee judgement 32.5% 112 bp Annual Report and Form 20-F 2020 Corporate governance Executive directors’ pay for 2020 Single figure table – executive directors (audited) Salary Benefits Retirement benefits Cash in lieu of retirement benefits Annual bonus, cash Annual bonus, deferred (as detailed on page 107) Performance shares (as detailed on page 107) Discontinued plans Total remunerationb Total fixed remuneration Total variable remuneration Bernard Looney CEO since 5 Feb 2020 (thousand) Murray Auchincloss CFO since 1 July 2020 (thousand) 2020 £1,181 £26 – £177 – – £351 – £1,735 £1,384 £351 2020 £348 £8 – £52 – – £215 – £623 £408 £215 Bob Dudley CEO to 4 Feb (thousand) Brian Gilvary CFO to 30 June (thousand) 2020 $170 $18 $0 – – – – – 2019 $1,854 $84 $544 – $1,408 $1,408 $8,039a – $188 $188 $13,336 $2,481 $0 $10,855 2020 £395 £41 £0 £115 – – – – £552 £552 £0 2019 £785 £59 £0 £252 £600 £600 £2,787a £1,529a £6,612 £1,095 £5,517 Please refer to the overview section below for additional detail, except where noted otherwise. a The amounts reported for 2019 have been adjusted to include the vesting of additional dividends on 5 November 2020 at the market price of £2.03 for ordinary shares and $15.83 for ADSs. See the performance shares table on page 111, and the deferred shares table on page 120, for further details on these awards. b Due to rounding, the totals do not agree exactly with the sum of their component parts. Overview of single figure outcomes (audited) Bernard Looney and Murray Auchincloss started in their roles as CEO and CFO on 5 February and 1 July 2020 respectively. Accordingly, the values shown in the single figure table represent remuneration outcomes from the time of their appointment to the board only. Similarly, because Bob Dudley and Brian Gilvary stepped down on 4 February and 30 June respectively, their 2020 remuneration values relate only to their part-years of service as executive directors. Payments received after they stepped down from their position are included in the payments to past directors section on page 122. Salary and benefits Bernard Looney’s salary was £1,300,000 from appointment. The amount reported above is before his 20% mental health charitable contribution. Murray Auchincloss’s salary was £695,000 from appointment. Bob Dudley’s salary remained at $1,854,000 until his exit on 31 March 2020. Brian Gilvary’s salary was unchanged at £790,500 until his exit on 30 June 2020. All executive directors received car-related benefits, assistance with tax return preparation, security assistance, insurance and medical benefits. 2020 annual bonus The committee concluded that there should be no bonus for 2020 as the plan was unaffordable. There were no other contributing factors leading us to this decision. 2018-20 performance shares Please refer to page 112 for details of the performance measures, targets and outcomes for these performance shares. Retirement benefits From their appointment as executive directors, Bernard Looney and Murray Auchincloss ceased to receive any retirement benefits for their service, but receive a cash allowance fixed at 15% of salary in line with the majority of similarly situated employees. They may choose to direct these allowances into retirement plans at their sole discretion, and the amounts are therefore identified as cash in lieu of retirement benefits on the single figure table. Bob Dudley was provided with pension benefits and retirement savings through a combination of tax-qualified and non-qualified benefit plans. His normal retirement age is 60. The BP Supplemental Executive Retirement Benefit Plan (SERB) is a non-qualified defined benefit pension plan which provides a proportion of earnings for each year of service. In 2020 his accrued defined benefit pension did not increase, and the amount included in the single figure table is therefore zero. The BP Employee Savings Plan (ESP) is a US tax-qualified defined contribution plan to which both Bob and bp contributed. The BP Excess Compensation (Savings) Plan (ECSP) is a non-qualified, unfunded, retirement savings plan to which bp notionally contributed 7% of base salary above the annual IRS limit. In 2020 Bob made contributions to the ESP totalling $28,500 and bp made matching contributions to the ESP, and notional contributions to the ECSP, totalling $32,445. However, investment losses in his unfunded ECSP account (aggregating the unfunded arrangements relating to his overall service with bp and TNK-BP) exceeded these contributions, hence the amount included in the single figure table is zero. bp Annual Report and Form 20-F 2020 113 History of chief executive officer remuneration Year Chief executive officer Total remuneration thousanda Annual bonus % of maximum Performance shares % of maximum Bob Dudley 2011 2012 Bob Dudley 2013 Bob Dudley 2014 Bob Dudley Bob Dudley 2015 2016 Bob Dudley 2017 Bob Dudley 2018 Bob Dudley 2019 Bob Dudley 2020b Bob Dudley Bernard Looney $8,439 $9,609 $15,086 $16,390 $19,376 $11,904 $15,108 $15,253 $13,336 $188 £1,735 66.7 64.9 88.0 73.3 100.0 61.0 71.5 40.5 67.5 0 0 16.7 0 45.5 63.8 74.3 40.0 70.0 80.0 71.2 32.5 32.5 a Total remuneration figures include share vesting outcomes. b 2020 figures show remuneration for the periods of qualifying service as CEO during 2020, as per the single figure values on page 113. Directors’ remuneration report continued Brian Gilvary was provided with retirement benefits through a combination of tax-qualified and non-qualified plans for service to 31 March 2011, but linked to his final salary. In line with terms offered to UK employees employed prior to 2010 (or before 2014 in the North Sea) Brian was a member of the BP Pension Scheme (bpPS), a UK final salary defined benefit pension plan. Pension benefits accrued in excess of the individual lifetime tax allowance set by legislation were provided to Brian via a non-qualified, unfunded pension arrangement designed to mirror the design of the approved bpPS. His normal retirement age is 60, although due to his long service, benefits accrued before 1 December 2006 may be paid unreduced from age 55 with bp’s consent. Brian received no salary increase in 2020, hence his interests in these retirement benefits did not increase and the amount included in the single figure table is therefore zero. For service after 31 March 2011 Brian received a cash allowance in lieu of further accrual. This was set at 30% of salary to 30 May, then 25% of salary to 30 June 2020, and the amount has been separately identified in the single figure table. Discontinued plans In accordance with 2014 policy, Brian Gilvary compulsorily deferred one third of his 2015 annual bonus and received a matching award of bp shares. Both the deferred and matching awards were subject to a three-year performance period which ended on 31 December 2018, however Brian voluntarily requested that the committee delay the performance assessment and vesting of the 2015 matching award for two years, to 31 December 2020. The committee considered operational and financial performance and reviewed safety and environmental sustainability performance over the 2016-20 period, seeking input from the strategy and sustainability committee on safety and sustainability measures. The committee concluded that safety performance continues to show improvement, with safety embedded in the culture of the organization and supporting strong operational and financial performance. The committee concluded that this award should vest in full. Because this award vested post-employment, the value is included in the payments to past directors statement on page 122, with further details available in the deferred shares table on page 120. Bob Dudley has previously requested that the committee delay the performance assessment and vesting of all his deferred and matching awards under the 2014 policy. Following the committee’s conclusion that the original safety and environmental sustainability conditions have been met, these awards will vest one year after his retirement, and the value will be reported in the payments to past directors statement in our 2021 report. 114 bp Annual Report and Form 20-F 2020 Corporate governance Over half of our global workforce participates in an annual cash bonus plan and for 2020 the plan was intended to pay an incentive based equally on individual performance and bp performance. However, as reported in my opening letter, the committee and CEO both concluded that there should be no bonus for 2020 as the plan was unaffordable, and this outcome applies equally to our executive directors, leadership team, and those of our wider workforce who participate in the annual bonus plan. These decisions reflect our principle of consistency for all those rewarded under our common template. Note, however, that a limited number of employees, such as those with specific contractual rights or who work in parts of the business with different remuneration models, have received bonus payments for 2020. Looking forward, we have reviewed the role of share plans offered to employees with a view to understanding the extent to which these plans align our wider workforce with bp’s purpose, particularly whether employees are personally invested in the new ambition and able to share in success. This review has led to our support for a ‘one off’ equity grant to every bp employee in 2021, vesting in 2025, reflecting our belief in sharing success broadly while aligning employees’ longer-term interests with all shareholders. We have also devoted time to examine the support provided for employee health and wellbeing, to gain a better understanding of how these aspects of policy support the organization’s culture and encourage appropriate behaviours. This is an ongoing study and we will have more to report next year. Turning to non-discrimination matters, we understand the sharp interest that exists in disclosures of gender and ethnicity pay gaps. Having reviewed the gender pay gap reports of the last several years we are satisfied that reward processes and decisions are designed and managed to effectively avoid bias, and that reported pay gaps relate in the main to differences in gender representation across the pay hierarchy. We therefore conclude that the narrative accompanying our pay gap reporting is better reflected within bp’s diversity and inclusion reporting, rather than remuneration reporting. With this in mind, and because bp has committed to annual diversity and inclusion reporting, we will leave additional commentary to that publication, which is expected to be available on the company’s website bp.com next month. Wider workforce in 2020 Workforce experience During 2020 the committee has continued to receive and review information on pay outcomes and processes for our wider workforce in order to take account of wider workforce pay and conditions when setting executive remuneration, and to consider alignment between pay structures. As part of this review we carried out a programme of engagement with a diverse range of employees from different parts of the workforce from the front line to corporate office and covering new joiners, employees with long tenure in the organization, and employees of different gender and nationality. The topics discussed addressed bp’s new purpose and ambition, and how this aligns with the organization’s reward programmes. Our enquiries ranged from success in attracting and retaining talent, employee preferences in how pay is delivered, the make-up of the reward package, and programmes to support international mobility. A recurring theme was the desire for flexibility, with employees wanting to be empowered to make their own choices about how they work and how they are remunerated for their work. Overall we continue to observe well-balanced and structured approaches to reward. Although these approaches vary by business area and location, the core offering for the majority of our workforce is summarized in the table on page 116. We also find that financial reward is complemented with strong emphasis on maintaining a supportive and inclusive working environment. For instance, our commitment to family-friendly leave policies; recognition as a top global employer in Stonewall’s list of the best multinational employers for LGBT+ staff; and scoring 100% for a fourth consecutive year in the Human Rights Campaign’s 2021 Corporate Equality Index, which measures adoption of non-discrimination policies, equitable benefits for LGBT+ employees and families, and supporting an inclusive culture and corporate social responsibility. We are also pleased to confirm that bp is now accredited by the Living Wage Foundation as a real living wage employer in the UK. This ensures all colleagues in our UK businesses and at company-owned sites are paid at least the real living wage and we are now reviewing the position across other bp countries. We apply the insights we gain from engaging with the workforce to challenge leadership generally and to make sure we think about remuneration holistically, not just with regard to those leaders whose pay is within our remit. This has been more relevant than ever through a year in which the COVID-19 pandemic has had such a significant impact on our people and business. Wider workforce salary increases were postponed at the normal salary review date 1 April 2020; from 1 October 2020 staff below our senior leadership level did receive increases. Salaries remained frozen for senior leaders (other than promotions) throughout 2020. bp Annual Report and Form 20-F 2020 115 Directors’ remuneration report continued Summary of remuneration structure for employees below the board Element Salary Pensions and benefits Annual bonus Performance shares Policy features for the wider workforce Comparison with executive director remuneration Our salary is the basis for a competitive total reward package for all employees, and we conduct an annual salary review for all non-unionized employees. As we determine salaries in this review, we take account of comparable pay rates at other relevant employers, the skills, knowledge and experience of each individual, relativity to peers within bp, individual performance, and the overall budget we set for each country. In setting the budget each year, we assess how employee pay is currently positioned relative to market rates, forecasts of any further market increases, and business context related to such things as growth plans, workforce turnover and affordability. We offer market-aligned benefits packages reflecting normal practice in each country in which we operate. Where appropriate, and subject to scale, we offer significant elements of personal benefit choice to our employees. Over half of our global workforce participate in an annual cash bonus plan that multiplies a target bonus amount by a performance factor in the range 0 to 2. For 2021, the performance factor will reflect bp performance alone, placing emphasis on aligning individual efforts to the shared goals of the company at this critical stage of our transition. We operate different bonus plans for those distinct parts of our business where remuneration models in the market are markedly different, such as our trading and marketing businesses. We operate a performance share plan with three-year vesting for employees from our professional entry level and above. Operation varies based on seniority in three broad tiers: group leaders (approximately 300); senior leaders (approximately 4,000); and all other professional employees (approximately 32,000 potential participants, of whom 20% will participate). Vesting is subject to group performance outcomes for the group leader population only. The salaries of our executive directors and executive leadership form the basis of their total remuneration, and we review these salaries annually. The primary purpose of the review is to stay aligned with relevant market comparators. We intend to keep increases within the salary review budgets set for our wider workforce, except in specific circumstances. Other than the addition of security-related benefits, our executive director benefit packages are broadly aligned with other employees who joined bp in the same country at the same time. Under our 2020 remuneration policy pension benefits have been sharply reduced for our new executive directors, who receive a cash-in-lieu of pension allowance set at 15% of salary. Their previously accrued defined benefit calculations are capped on pre-appointment salary service. Annual bonus for executive directors is directly related to the same group performance measures and outcomes as the wider workforce. Performance shares for our executive directors are assessed using the same group performance scorecard used for the group leader performance shares. 116 bp Annual Report and Form 20-F 2020 Corporate governance Chief executive officer to employee pay ratio This is our second year reporting the CEO pay ratio following the requirements introduced in 2018. As last year, we have selected option A as our reporting basis, being the most accurate approach available. The employees included in these calculations were employed by the group on 31 December 2020 and pay and benefits values were determined with reference to the financial year ending 31 December 2020. We confirm that no broadly applicable components of pay have been omitted and, where necessary, full-time equivalent pay has been calculated by simple engrossment of part year values. Our analysis this year covers more than 14,000 UK employees, 45% of whom work in our retail sites. Employee values reflect the zero bonus outcome for the majority of employees, and the delayed salary review date, from 1 April to 1 October. Given the succession of CEO in 2020, these employee values are compared against the sum of total pay values, per the single figure table on page 113, for Bernard Looney and Bob Dudley. Percentage change comparisons: Directors’ remuneration versus employees In the table below, values in column ‘a’ represent the percentage change in salary and fees; values in column ‘b’ represent the percentage change in taxable benefits; and values in column ‘c’ represent the percentage change in bonus outcomes for performance periods in respect of each financial year. The employee percentages shown represent the change in median employee pay. This compares the median BP p.l.c. employee on 31 December of the relevant financial year, with the median BP p.l.c. employee on 31 December of the preceding financial year, in each case ranked based on the total of salary, benefits and bonus. For the chair and non-executive directors, the decline in the value of taxable benefits largely relates to the sharp drop in business travel arising from pandemic-related travel restrictions. Year Method 2019 Option A 2020 Option A 25th percentile: pay ratio, total pay and benefits, (salary) 543:1 £19,108 (£18,845) 99:1 £18,984 (£18,984) 50th percentile: pay ratio, total pay and benefits, (salary) 75th percentile: pay ratio, total pay and benefits, (salary) 188:1 £55,071 (£38,800) 82:1 £126,085 (£74,200) 40:1 £46,933 (£29,040) 19:1 £98,546 (£80,475) Bob Dudley’s pay has been converted from US dollars at 0.77907 for 2020. The 2019 ratio is as originally reported. The sharp reduction in 50th percentile ratio from 188:1 to 40:1 reflects the fact that CEO remuneration is more heavily weighted to variable pay which reduces in years of weaker performance such as 2020. This is a natural reason for volatility in pay ratio reporting from year to year, and illustrates one of the challenges in commenting on whether any given year’s pay ratio is appropriate. Our considered view as to appropriateness is that the policies for our CEO, and for the wider workforce, are both fit for purpose and that they deliver pay outcomes appropriate to the circumstance of the year. Thus differentials reflect both the relative contributions made at different levels in our hierarchy, and the nature of the year in question. Taken in the round with all of the insights we have gained into pay policies and practices, we remain satisfied that pay outcomes, and the ratios derived from them, are as they should be. In particular we note that as well as being paid at least the real living wage, our UK employees also benefit from the significant intangible value of working in an inclusive and caring enterprise that is not reflected in pay ratio analyses. Employees Bernard Looney Murray Auchincloss Bob Dudley Brian Gilvary Nils Andersen Dame Alison Carnwath Pamela Daley Sir Ian Davis Professor Dame Ann Dowling Helge Lund (Chair) Melody Meyer Tushar Morzaria Brendan Nelson Paula Rosput Reynolds Sir John Sawers 2020 v 2019 b 0% – – -5% 13% -46% -94% -92% -81% -96% -74% -77% – -71% -92% -83% a 0% – – 0% 1% -7% -4% -15% -14% -4% 0% 9% – -7% 2% -3% c -100% – – -100% -100% n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a Bob Dudley, Brian Gilvary and Nils Andersen resigned during 2020, therefore, other than for one-time items, their 2020 pay has been annualised for comparison. Bernard Looney, Murray Auchincloss and Tushar Morzaria were appointed on the board in 2020 and therefore no comparison to 2019 is available. Relative importance of spend on pay ($ million) Distributions to shareholders Remuneration paid to all employees Capital investment 9,844 9,872 9,878 6,340 15,238 12,034 2019 2020 2019 2020 2019 2020 bp Annual Report and Form 20-F 2020 117 Directors’ remuneration report continued Stewardship and executive director interests We believe that our executive directors should have a material interest in the company, both during their tenure and after they leave bp. Our 2020 remuneration policy therefore requires the CEO and other executive directors to build personal shareholdings of five times salary and four and half times salary, respectively, within five years of their appointment. They are expected to maintain those shareholding levels for two years post employment. Directors’ shareholdings (audited) The table below details the personal shareholdings of each current and former executive director. Both Bob Dudley and Brian Gilvary significantly exceed their post-employment shareholding commitment. Bernard Looney and Murray Auchincloss are building towards the policy requirement that applies five years from their dates of appointment, 5 February and 1 July 2020 respectively. These figures include all beneficial and non-beneficial ownership of shares of bp (or calculated equivalents) that have been disclosed to the company. Director Bernard Looney Murray Auchincloss Bob Dudleyb Brian Gilvaryb Ordinary shares or equivalents at 1 Jan 2020 – – 4,592,208 2,593,708 Ordinary shares or equivalents at 31 Dec 2020 Changes from 31 Dec 2020 to 2 Mar 2021 Ordinary shares or equivalents at 2 Mar 2021 Appointment date Value of current shareholding Multiple of salary achieved 331,711 139,525 – – 212,228 2,010 – – 543,939 5 February 2020 £1,615,499a £420,359a 1 July 2020 141,535 – October 2010 – – January 2012 – 1.24x 0.60x – – a Based on ordinary share price at 2 March 2021 of £2.97. b Bob Dudley and Brian Gilvary resigned on 4 February and 30 June 2020 respectively. These current and former executive directors have additional interests in restricted and performance shares, and Bob and Brian have various interests in deferred bonus shares. These additional share interests are shown in aggregate, and by plan, in the tables below. For performance shares, the figures reflect maximum possible vesting levels (excluding the addition of reinvested dividends) even though the actual number of shares that vest will depend on the extent to which performance conditions are satisfied. Aggregated interests, all plans (audited) Directora Bernard Looney Murray Auchincloss Bob Dudley Brian Gilvary Unvested ordinary shares or equivalents at 1 Jan 2020 – – 6,639,882 2,905,764 Unvested ordinary shares or equivalents at 31 Dec 2020 3,193,599 1,581,899 5,296,740 2,060,135 Changes from 31 Dec 2020 to 2 Mar 2021 -530,370 -2,755 – – Unvested ordinary shares or equivalents at 2 Mar 2021 2,663,229 1,579,144 – – a Bernard Looney was appointed as CEO on 5 February and Murray Auchincloss was appointed as CFO on 1 July 2020, Bob Dudley and Brian Gilvary resigned on 4 February and 30 June 2020 respectively. 118 bp Annual Report and Form 20-F 2020 Corporate governance Performance shares (audited) Share element interests Interests vested in 2020 and 2021 Performance period Date of award of performance shares At 1 Jan 2020 Awarded 2020 At 31 Dec 2020 Potential maximum performance sharesa Bernard Looney Murray Auchincloss Bob Dudleye Brian Gilvary 2018-20b 2019-21b 2020-22d 2018-20be 2019-21be 2020-22d 2017-19f 2018-20g 2019-21 2017-19f 2018-20g 2019-21 20 Mar 2018 25 Mar 2019 11 Aug 2020 20 Mar 2018 25 Mar 2019 11 Aug 2020 19 May 2017 22 May 2018 19 Feb 2019 19 May 2017 22 May 2018 19 Feb 2019 317,380 335,920 – 155,916 156,468 – 1,571,628 1,395,600 1,340,766 722,093 696,705 654,315 Number of ordinary shares vested 126,134 – – 62,124 – – – – 2,076,677 317,380 335,920 2,076,677 – – 999,201 155,916 156,468 999,201 – – – – – – – 1,395,600 1,340,766 1,358,334 410,922 – – 696,705 654,315 623,242 227,337 – Vesting date 16 Feb 2021 – – 10 Mar 2021 – – 18 Feb 2020 19 Feb 2021 – 18 Feb 2020 19 Feb 2021 – Face value of awardc, £ 1,840,842 6,396,165 857,445 3,077,539 – – 7,199,913 – – 3,513,672 a For awards under the 2017-19 plan, performance conditions are measured 50% on TSR relative to Chevron, ExxonMobil, Shell and Total (‘comparator companies’) over three years, 30% on ROACE based on performance in 2019, and 20% on strategic progress assessed over the performance period. For awards under the 2018-2020 plans, performance conditions are measured on the same basis as the 2017-2019 plan, except ROACE which will be based on performance in the last two years of the performance period (i.e. 2019 and 2020). For awards under the 2019-2021 plans, performance conditions are measured 50% on TSR relative to the comparator companies over three years, 20% ROACE averaged over the full performance period, and 30% on strategic progress assessed over the performance period. Each performance period ends on 31 December of the third year. b Awards granted under the Group Share Value Plan (GSVP) prior to appointment as executive directors (disclosed share interests reflect maximum vesting, though under this plan awards are granted at 50% of maximum). Represents vesting of shares at the end of the performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares vested. Bernard Looney’s 2018-20 award vested on 16 February 2021, when the market price was £2.78 for each share, and Murray Auchincloss’s award vested on 10 March 2021 when the market price for each ADS was $26.65. The amounts reported as 2020 income on the single figure table are therefore £351k for Bernard Looney and $275k (£215k) for Murray Auchincloss. c Face values have been calculated using market prices of ordinary shares at closing on the dates of award, as follows; £5.37 on 19 February 2019; £5.48 on 25 March 2019; and £3.08 on 11 August 2020. d Minimum vesting under these awards (below threshold performance) is 0%. At the lowest performance outcome that would yield an above-zero score on each measure, vesting would be 10% of maximum. e These awards were received in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares. f Represents vesting of shares at the end of the performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares vested. This 2017-2019 award vested on 18 February 2020, when the market price was £4.54 for each ordinary share, and $36.09 for each ADS. Reinvested dividends were delivered on 5 November 2020, when the market price was £2.03 for each ordinary share, and $15.83 for each ADS. The adjusted amounts reported as 2019 income on the single figure table are therefore $8.039 million for Bob Dudley, and £2.787 million for Brian Gilvary. g Represents vestings of shares at the end of the performance period based on performance achieved under rules of the plan, pro-rated for time served, and includes reinvested dividends on the shares vested. This 2018-2020 award vested on 19 February 2021, when the market price was £2.72 for each share, and $22.87 for each ADS. As they were received post-employment, the value of these vested shares are included in the payments to past directors section on page 122. Restricted shares (audited) Bernard Looney Murray Auchincloss Share element interests Number of restricted shares Restricted period Date of award of restricted shares At 1 Jan 2020 Awarded 2020 At 31 Dec 2020 Face value of awardc, £ 2016-20a 2018-20a 2018-20b 2019-21b 2018-20a 2018-22a 2018-20b 2018-20d 2019-21d 2019-21b 2020-22d 15 Mar 2016 20 Mar 2018 20 Mar 2018 25 Mar 2019 20 Mar 2018 20 Mar 2018 20 Mar 2018 20 Mar 2018 25 Mar 2019 25 Mar 2019 28 Aug 2020 75,000 104,577 137,990 146,055 43,170 43,170 86,616 2,755 2,835 86,928 – – – – – – – – – – – 4,840 75,000 104,577 137,990 146,055 43,170 43,170 86,616 2,755 2,835 86,928 4,840 256,500 485,237 640,274 800,381 200,308 200,308 401,898 12,783 15,536 476,365 12,778 a Awards made under the Restricted Share Plan II prior to appointment as a director. b Awards made under the Individual Share Value Plan prior to appointment as a director. Awards under this plan were granted at 100% of salary. c Face values have been calculated using market prices of ordinary shares at closing on the dates of award, as follows; £3.42 on 15 March 2016; £4.64 on 20 March 2018; £5.48 on 25 March 2019; £2.64 on 28 August 2020. d Interests of person closely associated with Murray Auchincloss. bp Annual Report and Form 20-F 2020 119 Directors’ remuneration report continued Deferred sharesa (audited) Bonus year Bob Dudleybc 2014 Brian Gilvary 2015 2016 2017 2018 2019 2014 2015 2016 2017 2018 2019 Deferred share element interests Potential maximum deferred shares Interests vested in 2020 and 2021 Type Comp Vol Mat Comp Vol Mat Comp Mat Comp Comp Comp Mat Mat Comp Matg Comp Comp Comp Performance period Date of award of deferred shares At 1 Jan 2020 Awarded 2020 At 31 Dec 2020 2015-17 2015-17 2015-17 2016-18 2016-18 2016-18 2017-19 2017-19 2018-20 2019-21 2020-22 2015-17 2016-18 2017-19 2017-19 2018-20 2019-21 2020-22 11 Feb 2015 11 Feb 2015 11 Feb 2015 4 Mar 2016 4 Mar 2016 4 Mar 2016 19 May 2017 19 May 2017 22 May 2018 19 Feb 2019 18 Feb 2020 11 Feb 2015 4 Mar 2016 19 May 2017 19 May 2017 22 May 2018 19 Feb 2019 18 Feb 2020 147,054 147,054 294,108 275,892 275,892 551,784 147,642 147,642 226,236 118,584 – 176,576 318,042 73,070 73,070 127,457 64,436 – – – – – – – – – – – 228,486 – – – – – – 126,110 147,054 147,054 294,108 275,892 275,892 551,784 147,642 147,642 226,236 118,584 228,486 – 318,042 – 73,070 127,457 64,436 126,110 Number of ordinary shares vested Vesting date – – – – – – – – – – – – – – – – – – – – – – 253,223e 18 Feb 20 402,227f 19 Feb 21 88,577e 18 Feb 20 – 153,562h 19 Feb 21 – – – – – Face value of the awardd, £ 655,861 655,861 1,311,722 1,015,283 1,015,283 2,030,565 696,870 696,870 1,330,268 636,796 1,046,466 – – – 344,890 – 346,021 577,584 a Since 2010, vesting of the deferred shares has been subject to a safety and environmental sustainability hurdle. If the committee assesses that there has been a material deterioration in safety and environmental performance, or there have been major incidents, either of which reveal underlying weaknesses in safety and environmental management, then it may conclude that shares should vest only in part, or not at all. In reaching its conclusion, the committee obtains advice from the SAS committee. There is no identified minimum vesting threshold level. ‘Comp’ denotes compulsory deferral, ‘Vol’ denotes voluntary deferral, and ‘Mat’ denotes matching awards. b Bob Dudley received awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares. c Bob Dudley has voluntarily agreed to defer vesting of these awards until one year post employment. d Face values have been calculated using market prices of ordinary shares on the dates of award, as follows; £4.46 on 11 February 2015; £3.68 on 4 March 2016; £4.72 on 19 May 2017; £5.88 on 22 May 2018; £5.37 on 19 February 2019; £4.58 on 18 February 2020. e Represents vestings of shares at the end of the deferral period and includes reinvested dividends on the shares vested. The market price of each share used to determine the total value at vesting on 18 February 2020 was £4.54. The additional reinvested dividend shares were delivered on 5 November 2020, at a market price of £2.03. The adjusted amount reported as 2019 income on the single figure table is therefore £1.529 million. f Represents vesting of shares made at the end of the deferral period, prorated for 54 months’ service out of 60 months’ vesting period, and includes reinvested dividends thereon. The market price of each share used to determine the total value at vesting on 19 February 2021 was £2.72. As they were received post-employment, the values of these vested shares are included in the payments to past directors section on page 122. g Brian Gilvary has voluntarily agreed to defer vesting of this 2016 matching award to at least one year post employment. h In line with the 2017 policy, these compulsory deferrals of Bob and Brian’s 2017 bonus were included in the single figure of total remuneration reported for 2017 and therefore the values of these shares are not included as payments to past directors. In common with many of our UK employees, Bernard Looney holds options under the bp group save as you earn (SAYE) scheme as shown below. These options are not subject to performance conditions. Share interests in share option plans (audited) Director Option type Bernard Looney Murray Auchincloss Brian Gilvary Brian Gilvary SAYE SAYEb BP 2011c SAYEd At 1 Jan 2020 6,024 – 400,000 2,064 Granted Exercised 2020a Option price At 31 Dec Market price at date of exercise – 3,614 – – – – – – 6,024 3,614 400,000 – £2.54 £2.54 £3.72 £4.36 – – – – Date from which first exercisable 01 Sep 2025 01 Sep 2023 07 Sep 2014 01 Sep 2022 Expiry date 28 Feb 2026 28 Feb 2024 07 Sep 2021 28 Feb 2023 a The closing market price of an ordinary share on 31 December 2020 was £2.55. During 2020 the highest market price was £5.04, and the lowest market price was £1.93. b Interest of person closely associated with Murray Auchincloss. c The BP 2011 plan – these options were granted to Brian Gilvary prior to his appointment as a director and are not subject to performance conditions. d Brian Gilvary closed his save as you earn contract, and therefore these options lapsed, on 18 June 2020. Bernard Looney, Murray Auchincloss, Bob Dudley and Brian Gilvary have no interests in bp preference shares, debentures or option plans (other than as listed above), and none have interests in shares or loan stock of any subsidiary company. No directors or other leadership team members own more than 1% of the ordinary shares in issue. At 2 March 2021, our directors and leadership team members collectively held interests of 5,294,828 ordinary shares or their calculated equivalents, 10,204,082 restricted share units (with or without conditions) or their calculated equivalents, 3,075,878 performance shares or their calculated equivalents and 1,580,380 options over ordinary shares or their calculated equivalents, under bp group share option schemes. 120 bp Annual Report and Form 20-F 2020 Corporate governance Post employment share ownership interests Bob Dudley and Brian Gilvary have, and will continue to retain, significant interests in bp post employment. Under our 2017 policy, they gave their personal commitment as executive directors to maintain actual holdings equivalent to two and a half times salary for two years post employment. Their ongoing interests in share awards under group plans which remain subject to vesting and/or holding periods materially exceed the two and a half times salary threshold, and thus guarantee that they will continue to meet their minimum shareholding commitment. Although we instituted a formal post employment share ownership requirement as part of our 2020 policy, given the foregoing, we have not modified the requirements for these former executives. Chair and non-executive director outcomes and interests The remuneration policy for the chair and non-executive directors (NEDs) was approved at the 2020 AGM and implemented during 2020. Fee structure The table below shows the fee structure for the chair and NEDs, per our 2020 policy. The chair is not eligible for committee chairmanship and membership fees or intercontinental travel allowance. Chair Senior independent directora Board member Audit, geopolitical, remuneration and SAS committees chairmanship feesb Committee membership feec Intercontinental travel allowance Fees £ thousand 785 120 90 30 20 5 a The senior independent director is eligible for committee chairmanship fees and intercontinental travel allowance plus any committee membership fees. b Committee chairs do not receive an additional membership fee for the committee they chair. c For members of the audit, geopolitical, SAS and remuneration committees. As disclosed in our 2019 report, in early 2020 a revised fee structure was adopted for implementation with effect from 1 June 2020. The implementation of that revised fee structure was postponed on account of the COVID-19 pandemic and actions taken by bp in response. With effect from 1 January 2021, a fee for membership of the people and governance committee has been introduced given the increased time commitment associated with the expanded responsibilities of this committee. The fee is in line with other committee membership fees. The senior independent director has waived her entitlement to this committee membership fee. The geopolitical advisory council was constituted with effect from 1 January 2021. Fees of £10,000 and £15,000 are payable for membership of and chairing the council, respectively. The fee structure for 2021 remains otherwise unchanged and the board will review the situation again during the year. The table below shows the fees paid and applicable benefits for the year ended 31 December 2020. Benefits include travel and other expenses relating to the attendance at board and other meetings. As chair throughout 2020, Helge Lund had the use of a fully maintained office for company business, a car and driver, and security advice in London. Benefits values have been grossed up using a tax rate of 45%, where relevant, as an estimation of tax due. 2020 remuneration (audited) £ thousand Nils Andersenb Dame Alison Carnwathb Pamela Daley Sir Ian Davisb Professor Dame Ann Dowlingc Helge Lund (Chair) Melody Meyer Tushar Morzariab Brendan Nelson Paula Rosput Reynolds Sir John Sawers Fees Benefits Totala 2020 2019 2020 2019 2020 2019 38 110 140 143 135 785 166 37 140 174 140 161 115 164 165 140 785 152 – 150 170 145 1 2 3 1 0 25 4 0 3 3 0 11 33 37 5 3 95 16 – 11 36 1 39 112 143 143 135 810 170 37 143 177 140 172 148 201 170 143 880 168 – 161 206 146 a Due to rounding, the totals may not agree exactly with the sum of the component parts. b Nils Andersen resigned on 18 March 2020. Sir Ian Davis resigned on 30 December 2020. Tushar Morzaria was appointed on 1 September 2020. Dame Alison Carnwath resigned on 14 January 2021. c Fee includes £25,000 for chairing and being a member of the bp technology advisory council. bp Annual Report and Form 20-F 2020 121 Directors’ remuneration report continued Chair and non-executive directors’ interests (audited) The figures below include all the beneficial and non-beneficial interests of the chair and each non-executive director of the company in shares of bp (or calculated equivalents) that have been disclosed according to the disclosure guidance and transparency rules in the Financial Conduct Authority handbook (‘the DTRs’) as at the applicable dates. Our policy, shown on page 126, includes a shareholding guideline encouraging non-executive directors to establish a holding in bp shares of the equivalent value of one year’s base fee. Nils Andersenb Dame Alison Carnwathb Pamela Daley Sir Ian Davisb Professor Dame Ann Dowling Helge Lund (Chair) Melody Meyer Tushar Morzariab Brendan Nelsond Paula Rosput Reynolds Karen Richardsonb Sir John Sawers Dr Johannes Teyssenb Ordinary shares or equivalents at 1 Jan 2020 Ordinary shares or equivalents at 31 Dec 2020 Changes from 31 Dec 2020 to 2 Mar 2021 Ordinary shares or equivalents at 2 Mar 2021 Value of current shareholdinga % of policy achieved 125,000 17,700 17,592c 52,671 22,320 600,000 20,646c – 21,626 73,200c – 15,506 – – 17,700 40,332c – 22,320 600,000 20,646c 36,276 21,626 73,200c – 23,116 – – – 0 – 0 0 0 0 0 0 – 0 – – – 40,332c – 22,320 600,000 20,646c 36,276 21,626 73,200c 10,746c 23,116 20,000 – – $166,504 – £66,290 £1,782,000 $85,234 £107,740 £64,229 $302,194 $44,363 £68,655 £59,400 – – 144% – 74% 227% 74% 120% 71% 262% 38% 76% 66% a Based on share and ADS prices at 2 March 2021 of £2.97 and $24.77. b Nils Andersen and Sir Ian Davis resigned on 18 March and 30 December 2020 respectively. Tushar Morzaria appointed on 1 September 2020. Karen Richardson and Dr Johannes Teyssen appointed on 1 January 2021. Dame Alison Carnwath resigned on 14 January 2021. c Held as ADSs. d Brendan Nelson’s 31 December 2019 shareholding was incorrectly shown as 11,040 shares, rather than 21,626 shares, in our 2019 report. Payments for loss of office (audited) Brian Gilvary received a payment in lieu of notice of £447,950 relating to the part of his 12-month notice period that followed his retirement on 30 June 2020. As detailed on page 120, Bob Dudley deferred the vesting of various deferred and matching share awards, related to annual bonus outcomes from 2014 to 2019, until at least one year post retirement. Of these, awards under the 2014 policy (for bonus years 2014, 2015 and 2016) were not included in the single figures of total remuneration, therefore the values of these awards will be disclosed in the payments to past directors section of the relevant annual report following vesting. Similarly, Brian Gilvary deferred the vesting of his 2016 matching share award until at least one year post retirement. The value of this award will be disclosed in the payments to past directors section of the relevant annual report following vesting. Payments to past directors (audited) Since leaving employment, Bob Dudley and Brian Gilvary have received shares upon vesting of the awards listed below: (1) Bob Dudley received 410,922 shares on vesting of his 2018-20 performance share award on 19 February 2021. Based on a share price of $22.78 this vesting was valued at $1,566,298. This award reflects the 32.5% vesting outcome, and has been pro-rated for 27 months’ service through the three-year performance period. (2) Brian Gilvary received 227,337 shares on vesting of his 2018-20 performance share award on 19 February 2021. Based on a share price of £2.72 this vesting was valued at £618,357. This award reflects the 32.5% vesting outcome, and has been pro-rated for 30 months’ service through the three-year performance period. (3) Brian Gilvary received 402,227 shares on vesting of his 2015 matching award on 19 February 2021. Based on a share price of £2.72 this vesting was valued at £1,094,057. This award has been pro-rated for 54 months’ service through the five-year vesting period. Bob Dudley was also provided with post-employment medical benefits amounting to $14,359, ongoing car and driver benefits in the UK, amounting to $44,429, and relocation benefits to assist his repatriation to the US, amounting to $47,186. We made no other payments within the scope of the disclosure requirements to any past director of bp during 2020 (we have no de minimis threshold for such disclosures). 122 bp Annual Report and Form 20-F 2020 Other disclosures Historical TSR performance £250 £200 £150 £100 £50 £0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 BP FTSE 100 This graph shows the growth in value of hypothetical £100 investments in BP p.l.c. ordinary shares, and in the FTSE 100 Index (of which bp is a constituent), over 10 years from 31 December 2010 to 31 December 2020. Independence and advice The board considers all committee members to be independent with no personal financial interest, other than as shareholders, in the committee’s decisions. Further detail on the activities of the committee, advice received, and shareholder engagement is set out in the remuneration committee report on page 105. During 2020 Ben Mathews, who was employed by the company and reported to the chair of the board, acted as secretary to the remuneration committee. The committee also received advice on various matters relating to the remuneration of executive directors and senior management from Helmut Schuster, former EVP, group human resources, Kerry Dryburgh, EVP, people and culture (from 1 July 2020) and Ashok Pillai, SVP, reward and wellbeing. PricewaterhouseCoopers LLP (‘PwC’) continued to provide independent advice to the committee in 2020, following its appointment as independent advisor to the committee in September 2017, following a competitive tender process. None of PwC’s consultants advising the committee have any connection with the company’s directors. PwC advice included, for example, support with remuneration benchmarking and updates on market practice. PwC is a member of the Remuneration Consulting Group and, as such, operates under the code of conduct in relation to executive remuneration consulting in the UK. The committee is satisfied that the advice received is objective and independent. Freshfields Bruckhaus Deringer LLP (‘Freshfields’) provided legal advice on specific compliance matters to the committee. PwC and Freshfields provide other advice in their respective areas to the group. During the year, PwC provided bp with services including: subsidiary company secretarial support; digital and IT services; low carbon strategy consulting; internal audit subject matter expertise and trading transformation. Total fees or other charges (based on an hourly rate) for the provision of remuneration advice to the committee in 2020 (save in respect of legal advice) were £110,262 to PwC. Corporate governance Considerations related to the Corporate Governance Code When setting the 2020 policy, the committee concluded that the scorecard- based approach to setting targets and measuring outcomes provides great clarity in our ability to engage transparently with shareholders and the wider workforce on remuneration. Thus, bp continues to operate a simple structure of market-aligned salary with annual and three-year performance- based incentives. Risks are managed through careful setting of performance measures and targets, and broad options to apply committee discretion in assessing outcomes, such as the decision to pay no annual bonus for 2020. These are complemented with robust malus and clawback measures. Remuneration outcomes are predictable, as shown in the scenario charts of the 2020 policy, and proportional by virtue of the challenging performance levels required to achieve target pay outcomes. Through material weighting in measures related to safety, sustainability and strategy, as shown on page 109, remuneration aligns closely with bp’s culture, as expressed through our purpose and ambition. Shareholder engagement Throughout 2020 we continued to discuss remuneration policy and approach with many of our largest shareholders, as well as investor representative bodies. We plan to continue this dialogue in 2021, as we consider issues and make decisions related to the implementation of our remuneration policy for 2021 and beyond. The table below shows the votes on the report for the last three years. AGM directors’ remuneration report vote results Year 2020 2019 2018 % vote ‘for’ % vote ‘against’ Votes withheld 96.05% 95.93% 96.42% 3.95% 67,623,825 4.07% 337,586,814 42,741,541 3.58% The remuneration policy was approved by shareholders at the 2020 AGM last May. The votes on the policy are shown below. 2020 AGM directors’ remuneration policy vote results Year 2020 % vote ‘for’ % vote ‘against’ Votes withheld 96.58% 3.42% 65,652,222 External appointments The board supports executive directors taking up appointments outside the company to broaden their knowledge and experience. Each executive director is permitted to retain any fee from their external appointments. Such external appointments are subject to agreement by the chair and reported to the board. Any external appointment must not conflict with a director’s duties and commitments to bp. Details of appointments as non-executive directors of publicly listed companies during 2020 are shown below. Director Appointee company Additional position held at appointee company Bernard Looney Murray Auchincloss Bob Dudley Brian Gilvary Rosnefta Aker BP ASAa Rosnefta Air Liquide SA Brian Gilvary Barclays plc Director Director Director Non-executive director Non-executive director Total fees 0 0 0 Eur 38,375 £47,500 a Held as a result of the company’s shareholdings in Rosneft and Aker BP ASA. bp Annual Report and Form 20-F 2020 123 Directors’ remuneration report continued Policy implementation for 2021 The table below shows how the remuneration policy approved by shareholders at the 2020 AGM will be implemented in 2021, alongside a summary of key features. For the full remuneration policy, please go to bp.com/remuneration Salary and benefits Retirement benefits Annual bonus Performance shares To provide fixed remuneration to reflect the scale and complexity of both the business and the role, and to be competitive with the external market. When setting salaries, the committee considers practice in other oil and gas majors as well as European and US companies of a similar size, geographic spread and business dynamic to bp. Percentage increases for executive directors will not exceed increases for the broader employee population, other than in specific circumstances identified by the committee (e.g. in response to a substantial change in responsibilities). Executive directors normally participate in the company retirement plans that operate in their home country. New appointees from within the bp group retain previously accrued benefits. For their service as a director, retirement benefits will be no more than the median provision offered to the wider workforce in the UK. For future appointments, the committee will carefully review any retirement benefits to be granted to a new director, taking account of retirement policies across the wider group and any arrangements currently in place. Bonus is measured against an annual scorecard. The committee holds discretion to choose the specific measures and the relative weightings adopted in the annual scorecard, to reflect the annual plan as agreed with the board. Numeric scales are set for each measure, to score outcomes relative to targets. A scorecard outcome of 1.0 reflects the target outcome, and half of the maximum outcome. Target bonus is 112.5% of salary, and maximum bonus is 225% of salary. Half of the bonus for each year is paid in cash, and half is delivered as a deferred share award vesting in three years. Performance shares are granted with a three-year performance period, measured against scorecard. The committee holds discretion to choose the specific measures and the relative weightings adopted in the scorecard, to ensure they are focused on the near-term priorities for delivering the bp strategy in the interests of shareholders. Annual grants are 500% of salary for the CEO, and 450% of salary for any other executive director. Awards will vest in proportion to the outcomes measured through the performance scorecard, subject to any adjustment by the committee. Bernard Looney’s salary will increase by 2.75% to £1,335,750 following the 2021 AGM. Murray Auchincloss’s salary will increase by 8% to £750,500 following the 2021 AGM. This compares to an increase in excess of 4% to our UK salaried staff effective from 1 April, our annual salary review date. Benefits will remain unchanged for 2021 and include car-related provisions (or cash in lieu), security assistance, insurance and medical cover. Bernard and Murray are deferred members of final salary pension plans related to their service prior to appointment as executive directors, but now receive a cash allowance in lieu of retirement benefits. Bernard’s cash allowance will be unchanged at 15%, and he accrues no further value under his deferred pension. Murray’s cash allowance will be unchanged at 15%, and he accrues no further value under his US deferred pension. For our 2021 bonus, our scorecard will be reweighted to safety (15%), environment (15%), operational (20%) and financial (50%). Please see scorecard measures on page 125 for detail. Awards are subject to malus and clawback provisions described on page 125. For our 2021-23 cycle, 20% each for rTSR, ROACE, and EBIDA CAGR, and 40% for strategic progress. Please see scorecard measures on page 125 for detail. The 2021-23 awards will be granted in June 2021, based on the average closing share price over the 90 days preceding our 2021 AGM. Awards are subject to malus and clawback provisions described on page 125. 124 bp Annual Report and Form 20-F 2020 Corporate governance Bernard and Murray have not yet reached five years since appointment, and are therefore building the share interests towards the level required by policy. The committee has committed to an ongoing review of the outcomes of 2020-22 performance shares to ensure there is no windfall gain related to share price appreciation following market turmoil around the time the awards were granted. Shareholding requirement Malus and clawback Committee flexibility CEO to build a shareholding of at least five times salary, and other executive directors four and a half times salary, within five years of appointment. Executive directors are required to maintain at least that minimum level for at least two years post employment. Malus provisions may apply where there is: a material safety or environmental failure; an incorrect award outcome due to miscalculation or incorrect information; a restatement due to financial reporting failure or misstatement of audited results; material misconduct; or other exceptional circumstances that the committee considers similar in nature. Clawback provisions may apply where there is: an incorrect outcome due to miscalculation or incorrect information; a restatement due to financial reporting failure or misstatement of audited results; or material misconduct. The committee holds discretion to adjust performance measures and weightings, and to revise the peer group for the rTSR measure. This discretion allows appropriate re-alignment, throughout the policy term, for changes in the annual plan and for the anticipated evolution of the low carbon business environment. The committee also holds discretion in determining the outcomes for annual bonus and performance shares, allowing them to take broad views on alignment with shareholder experience, environmental, societal and other relevant considerations. Performance measures for incentive plans commencing in 2021 Annual bonus (weighting as % of maximum) Safety 15% Tier 1/2 process safety Environment 15% Sustainable emissions reductions Operational performance 20% bp-operated plant reliability and refining availability (10%) Margin share from convenience and electrification (10%) Financial performance 50% Free cash flow (25%) Cumulative cash cost reductions (25%) Performance shares (weighting as % of maximum) Relative TSR 20% ROACE 20% Growth (EBIDA CAGR) 20% Underpin: To take into account safety outcomes prior to determining final vesting percentage Discretion: To reflect shareholder experience, environment, societal and other inputs Robust malus and clawback Strategic progress 40% Deliver value through a resilient and focused hydrocarbon business Demonstrate a track record, scale and value in low carbon electricity and energy Accelerate growth in convenience and mobility bp Annual Report and Form 20-F 2020 125 Directors’ remuneration report continued Policy table – non-executive directors Non-executive chair Fees Approach Remuneration is in the form of cash fees, payable monthly. The level and structure of the chair’s remuneration will primarily be compared against UK best practice. Operation and opportunity The quantum and structure of the non-executive chair’s remuneration is reviewed annually by the remuneration committee, which makes a recommendation to the board. Benefits and expenses Approach The chair is provided with support and reasonable travelling expenses. Operation and opportunity The chair is provided with an office and full-time secretarial and administrative support in London and a contribution to an office and secretarial support in his home country as appropriate. A car and the use of a driver is provided in London, together with security assistance. All reasonable travelling and other expenses (including any relevant tax) incurred in carrying out his duties are reimbursed. Non-executive directors Fees Approach Operation and opportunity Intercontinental allowance Approach Remuneration is in the form of cash fees, payable monthly. Remuneration practice is consistent with recognized best practice standards for non-executive directors’ remuneration and, as a UK-listed company, the level and structure of non-executive directors’ remuneration will primarily be compared against UK best practice. Additional fees may be payable to reflect additional board responsibilities, for example, committee chairmanship and membership and for the role of senior independent director. The level and structure of non-executive directors’ remuneration is reviewed by the chair, the CEO and the company secretary who make a recommendation to the board. Non-executive directors do not vote on their own remuneration. Remuneration for non-executive directors is reviewed annually. Non-executive directors receive an allowance to reflect the global nature of the company’s business. The intercontinental travel allowance is payable for the purpose of attending board or committee meetings or site visits. Operation and opportunity The allowance is paid in cash following each event of intercontinental travel. Benefits and expenses Approach Operation and opportunity Shareholding guidelines Approach Non-executive directors are provided with administrative support and reasonable travelling expenses. Professional fees are reimbursed in the form of cash, payable following the provision of advice and assistance. Non-executive directors are reimbursed for all reasonable travelling and subsistence expenses (including any relevant tax) incurred in carrying out their duties. The reimbursement of professional fees incurred by non-executive directors based outside the UK in connection with advice and assistance on UK tax compliance matters. Non-executive directors are encouraged to establish a holding in bp shares of the equivalent value of one year’s base fee. This directors’ remuneration report was approved by the board and signed on its behalf by Ben J. S. Mathews, company secretary, on 22 March 2021. 126 bp Annual Report and Form 20-F 2020 Corporate governance UK Corporate Governance Code compliance Throughout 2020, bp applied the principles and complied with all the provisions of the 2018 UK Corporate Governance Code. Risk management and internal control Under the UK Corporate Governance Code 2018 (Code), the board is responsible for the company’s risk management and internal control systems. In discharging this responsibility the board, through its governance principles, requires the chief executive officer to operate the company with a comprehensive system of controls and internal audit to identify and manage the risks including emerging risks that are material to bp. In turn, the board, through its monitoring processes, satisfies itself that these material risks are identified and understood by management and that systems of risk management and internal control are in place to mitigate them. These systems are reviewed periodically by the board, have been in place for the year under review and up to the date of this report and are consistent with the requirements of Principle O of the Code. The board has processes in place to: Assess the principal and emerging risks facing the company. Monitor the company’s system of internal control (which includes the ongoing process for identifying, evaluating and managing the principal and emerging risks). Review the effectiveness of that system annually. Directors’ statements Statement of directors’ responsibilities The directors are responsible for preparing the annual report and the financial statements in accordance with applicable law and regulations. The directors are required by the UK Companies Act 2006 to prepare financial statements for each financial year that give a true and fair view of the financial position of the group and the parent company and the financial performance and cash flows of the group and parent company for that period. Under that law they are required to prepare the consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) adopted pursuant to Regulation (EC) No 1606/2002 as it applies in the European Union (EU) and applicable law and have elected to prepare the parent company financial statements in accordance with applicable United Kingdom law and United Kingdom accounting standards (United Kingdom generally accepted accounting practice), including FRS 101 ‘Reduced Disclosure Framework’. In preparing the consolidated financial statements the directors have also elected to comply with IFRS as issued by the International Accounting Standards Board (IASB). In preparing those financial statements, the directors are required to: Select suitable accounting policies and then apply them consistently. Make judgements and estimates that are reasonable and prudent. Present information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information. Provide additional disclosure when compliance with the specific requirements of IFRS is insufficient to enable users to understand the impact of particular transactions, other events and conditions on the group’s financial position and financial performance. State that applicable accounting standards have been followed, subject to any material departures disclosed and explained in the parent company financial statements. Prepare the financial statements on the going concern basis unless it is inappropriate to presume that the company will continue in business. The directors are responsible for keeping adequate accounting records that disclose with reasonable accuracy at any time the financial position of the group and company and enable them to ensure that the consolidated financial statements comply with the Companies Act 2006 and the parent company financial statements comply with the Companies Act 2006. They are also responsible for safeguarding the assets of the group and company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities. Having made the requisite enquiries, so far as the directors are aware, there is no relevant audit information (as defined by Section 418(3) of the Companies Act 2006) of which the company’s auditors are unaware, and the directors have taken all the steps they ought to have taken to make themselves aware of any relevant audit information and to establish that the company’s auditors are aware of that information. The directors confirm that to the best of their knowledge: The consolidated financial statements, prepared on the basis of IFRS as issued by the IASB, IFRS adopted pursuant to Regulation (EC) No 1606/2002 as it applies in the EU and in accordance with the provisions of the Companies Act 2006 as applicable to companies reporting under international accounting standards, give a true and fair view of the assets, liabilities, financial position and profit or loss of the group. The parent company financial statements, prepared in accordance with United Kingdom generally accepted accounting practice, give a true and fair view of the assets, liabilities, financial position, performance and cash flows of the company. The management report, which is incorporated in the strategic report and directors’ report, includes a fair review of the development and performance of the business and the position of the group, together with a description of the principal risks and uncertainties that they face. Helge Lund Chairman 22 March 2021 This page does not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 127 Directors’ statements continued Non-operated joint ventures« and associates« have not been dealt with as part of this board process. A description of the principal and emerging risks facing the company, including those that could potentially threaten its business model, future performance, solvency or liquidity, is set out in Risk factors on page 67. During the year, the board undertook a robust assessment of the principal and emerging risks facing the company. The principal means by which these risks are managed or mitigated are set out on page 65. In assessing the risks faced by the company and monitoring the system of internal control, the board and the audit, safety, environment and security assurance and geopolitical committees requested, received and reviewed reports from executive management, including management of the business segments, corporate activities and functions, at their regular meetings. A report by each of these committees, including its activities during the year, is set out on pages 92-102 and 105. During the year, the committees, as relevant, also met with management, the group head of audit and other monitoring and assurance functions (including group ethics and compliance, safety and operational risk, group control, group legal and group risk) and the external auditor. Responses by management to incidents that occurred were considered by the appropriate committee or the board. At a meeting in January 2021, the audit committee considered reports from the group risk function on the system of internal control and the function’s categorisation of significant failings and weaknesses. The audit committee also considered a report from internal audit on their assessment of bp’s systems of internal control and risk management, based on audit work conducted during 2020. In considering these reports and assessments, the audit committee noted that bp’s system of internal control and risk management is designed to manage, rather than eliminate, the risk of failure to achieve business objectives and can only provide reasonable, and not absolute, assurance against material misstatement or loss. At its meeting in March 2020, the board considered the review undertaken by the audit committee and the proposed disclosures outlining the company’s risk management and internal control systems prior to publication of the annual report and accounts. The scenarios that have been modelled are based on the most severe but plausible outcomes and associated costs are based on actual experience where possible. The scenarios have been considered individually and as a cluster of events. They include: A statement regarding the company’s internal controls over financial reporting is set out on page 327. a significant process safety incident when operating facilities, drilling wells or transporting hydrocarbons. Longer-term viability In accordance with provision 31 of the Code, the directors have assessed the prospects of the company over a period significantly longer than 12 months. The directors believe that, notwithstanding bp’s new strategy and the associated 2025 and 2030 net zero carbon targets and aims that it set out in 2020, a viability assessment period of three years remains appropriate. This assessment is based on management’s reasonable expectations of the position and performance of the company over this period and the targets and aims that it has set out. Our risk management system, described in how we manage risk on page 64, outlines our risk identification, assessment and management approach for all risks, including our principal risks, described on page 67. Taking into account the company’s current position and its principal risks, the directors have a reasonable expectation that the company will be able to continue in operation and meet its liabilities as they fall due over the next three years. The directors’ assessment included a review of the potential financial impact of, and the financial headroom that could be available in the event of, the most severe but plausible scenarios that could threaten the viability of the company. The assessment took into consideration the robust financial position of the group and the potential mitigations that management reasonably believes would be available to the company over this period. Mitigations considered include use of cash, access to debt facilities and credit lines, raising of capital, reductions in capital expenditure, divestments and dividend reductions. a sustained significant decline in oil prices over three years. a significant cyber-security incident. a loss of a significant market or producing asset for six months. The directors also considered the impact on viability from an extended pandemic scenario, as well as the potential risks associated with the energy transition. They consider that the most likely impacts of these risks are broadly captured and modelled through the sustained low oil price and loss of a producing asset scenarios. In assessing the prospects of the company, the directors noted that such assessment is subject to a degree of uncertainty that can be expected to increase looking out over time and, accordingly, that future outcomes cannot be guaranteed or predicted with certainty. Going concern In accordance with provision 30 of the Code, the directors consider it appropriate to adopt the going concern basis of accounting in preparing the financial statements. The impact of COVID-19 and the current economic environment was considered as part of the going concern assessment. Forecast liquidity has been assessed under a number of stressed scenarios, including a significant decline in oil prices over the 12-month period. Reverse stress tests performed indicated that the group will continue to operate as a going concern for at least 12 months from the date of approval of the financial statements even if the Brent price fell to zero. Fair, balance and understandable The board considers the annual report and financial statements, taken as a whole, is fair, balanced and understandable and provides the information necessary for shareholders to assess the company’s position and performance, business model and strategy. This page does not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 128 bp Annual Report and Form 20-F 2020 Financial statements The Thunder Horse platform is located in the US Gulf of Mexico, around 150 miles southeast of New Orleans, in over 6,000 feet of water. Consolidated financial statements of the bp group Independent auditor’s reports Group income statement 19. Inventories 20. Trade and other receivables 21. Valuation and qualifying accounts 22. Trade and other payables 130 155 Group statement of comprehensive income 156 23. Provisions 24. Pensions and other post-retirement benefits 25. Cash and cash equivalents 26. Finance debt 27. Capital disclosures and net debt 28. Leases 29. Financial instruments and financial risk factors 30. Derivative financial instruments 31. Called-up share capital 32. Capital and reserves 33. Contingent liabilities and legal proceedings 34. Remuneration of senior management and non-executive directors 35. Employee costs and numbers 36. Auditor’s remuneration 37. Subsidiaries, joint arrangements and associates 38. Condensed consolidating information on certain US subsidiaries Group statement of changes in equity Group balance sheet Group cash flow statement Notes on financial statements 1. Significant accounting policies 2. Non-current assets held for sale 3. Business combinations and other significant transactions 4. Disposals and impairment 5. Segmental analysis 6. Revenue from contracts with customers 7. Income statement analysis 8. Exploration expenditure 9. Taxation 10. Dividends 11. Earnings per share 12. Property, plant and equipment 13. Capital commitments 14. Goodwill 15. Intangible assets 16. Investments in joint ventures 17. Investments in associates 18. Other investments 157 158 159 160 177 177 178 180 183 183 184 184 186 187 189 190 190 191 192 192 195 195 195 196 196 197 197 204 204 205 206 206 211 219 220 225 228 229 229 230 230 Supplementary information on oil and natural gas (unaudited) Oil and natural gas exploration and production activities Movements in estimated net proved reserves Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves Operational and statistical information Parent company financial statements of BP p.l.c. Company balance sheet Company statement of changes in equity Notes on financial statements 1. Significant accounting policies 2. Investments 3. Receivables 4. Pensions 5. Payables 6. Taxation 7. Called-up share capital 8. Capital and reserves 9. Financial guarantees 10. Share-based payments 11. Auditor’s remuneration 12. Directors’ remuneration 13. Employee costs and numbers 14. Related undertakings 232 238 253 256 259 260 261 261 265 266 267 270 271 271 272 272 273 273 273 273 274 bp Annual Report and Form 20-F 2020 129 Consolidated financial statements of the bp group Independent auditor’s report to the members of BP p.l.c. Report on the audit of the financial statements 1. Opinion In our opinion: • The financial statements of BP p.l.c. (the ‘parent company’) and its subsidiaries (the ‘group’) give a true and fair view of the state of the group’s and of the parent company’s affairs as at 31 December 2020 and of the group’s loss for the year then ended. • The group financial statements have been properly prepared in accordance with international accounting standards in conformity with the requirements of the Companies Act 2006, International Financial Reporting Standards (IFRSs) as adopted by the European Union and IFRS as issued by the International Accounting Standards Board (IASB). • The parent company financial statements have been properly prepared in accordance with United Kingdom accounting standards (United Kingdom generally accepted accounting practice), including Financial Reporting Standard (FRS) 101 ‘Reduced Disclosure Framework'. • The financial statements have been prepared in accordance with the requirements of the Companies Act 2006 and, as regards the group financial statements, Article 4 of the IAS Regulation. We have audited the financial statements of BP p.l.c. which comprise the: • Group income statement; • Group statement of comprehensive income; • Group and parent company statements of changes in equity; • Group and parent company balance sheets; • Group cash flow statement; • Group related Notes 1 to 38 to the financial statements, including a summary of significant accounting policies; and • Parent company related Notes 1 to 14 to the financial statements, including a summary of significant accounting policies. The financial reporting framework that has been applied in the preparation of the group financial statements is applicable law and IFRSs as adopted by the European Union and as issued by the IASB. As regards the parent company financial statements, the financial reporting framework that has been applied in their preparation is applicable law and United Kingdom accounting standards (United Kingdom generally accepted accounting practice), including FRS 101 'Reduced Disclosure Framework'. 2. Basis for opinion We conducted our audit in accordance with International Standards on Auditing (UK) (ISAs (UK)) and applicable law. Our responsibilities under those standards are further described in the auditor’s responsibilities for the audit of the financial statements section of our report. We are independent of the group and the parent company in accordance with the ethical requirements that are relevant to our audit of the financial statements in the UK, including the Financial Reporting Council’s (the ‘FRC’s’) Ethical Standard as applied to listed public interest entities, and we have fulfilled our other ethical responsibilities in accordance with these requirements. The non-audit services provided to the group and parent company for the year are disclosed in Note 36 to the financial statements. We confirm that the non-audit services prohibited by the FRC’s Ethical Standard were not provided to the group or the parent company. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. 3. Summary of our audit approach Key audit matters The key audit matters that we identified in the current year were: • COVID-19 and the resulting significant changes to the business environment; • Potential impact of climate change and the energy transition; • Impairment of upstream oil and gas property, plant and equipment (PP&E) assets; • Write-off of exploration and appraisal (E&A) assets; • Accounting for structured commodity transactions (SCTs) within the trading and shipping (T&S) function, and the valuation of other level 3 financial instruments, where fraud risks may arise in revenue recognition; • IT controls relating to financial systems; and • Management override of controls. This year we identified COVID-19 and the related significant changes to the business environment as a key audit matter, given the consequential impact on the financial statements and the focus on this issue by management and by external stakeholders. All other key audit matters are consistent with those we identified in the prior year. Materiality The materiality that we used for the group financial statements was $600 million (2019 $850 million) which was determined based on net assets. We adopted a different basis to determine the materiality used to audit the group financial statements this year. In the prior year we used profit-based metrics but this year we used net assets due to the significant losses incurred as a consequence, inter alia, of the COVID-19 pandemic and in particular the decrease in oil and gas prices. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. 130 bp Annual Report and Form 20-F 2020 Financial statements Scoping Our scope covered 277 consolidation units (cons units). Of these, 173 were full-scope audits and the remaining 104 were subject to specific procedures on certain account balances by component audit teams or the group audit team. These covered 82% of group revenue and 75% of PP&E. The remaining 642 cons unit were subject to other procedures, including conducting analytical reviews, making inquiries, and evaluating and testing management's group-wide controls. 4. Conclusions relating to going concern In auditing the financial statements, we have concluded that the directors’ use of the going concern basis of accounting in the preparation of the financial statements is appropriate. Our evaluation of the directors’ assessment of the group’s and parent company’s ability to continue to adopt the going concern basis of accounting included: • an assessment of whether material uncertainties existed that could cast significant doubt on the entity’s ability to continue as a going concern for at least 12 months after the date of approval of the financial statements; • an assessment of the financing facilities including nature of facilities, repayment terms and covenants; • testing of clerical accuracy and appropriateness of the model used to prepare the forecasts; • an assessment of the assumptions used in the forecasts; • an assessment of management’s identified potential mitigating actions and the appropriateness of the inclusion of these in the going concern assessment; • an assessment of the historical accuracy of forecasts prepared by management; • reperformance of management’s sensitivity analysis; and • an assessment of the disclosures made within the financial statements Based on our assessment, we concluded that the assumptions used by management were in the acceptable range and the disclosures made within the financial statements were appropriate. Based on the work we have performed, we have not identified any material uncertainties relating to events or conditions that, individually or collectively, may cast significant doubt on the group's and parent company’s ability to continue as a going concern for a period of at least twelve months from when the financial statements are authorised for issue. In relation to the reporting on how the group has applied the UK Corporate Governance Code, we have nothing material to add or draw attention to in relation to the directors’ statement in the financial statements about whether the directors considered it appropriate to adopt the going concern basis of accounting. Our responsibilities and the responsibilities of the directors with respect to going concern are described in the relevant sections of this report. 5. Key audit matters Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial statements of the current period and include the most significant assessed risks of material misstatement (whether or not due to fraud) that we identified. These matters included those which had the greatest effect on: the overall audit strategy, the allocation of resources in the audit; and directing the efforts of the engagement team. Throughout the course of our audit, we identify risks of material misstatement (‘risks’). We consider both the likelihood of a risk and the potential magnitude of a misstatement in making the assessment. Certain risks are classified as ‘significant’ or ‘higher’ depending on their severity. The category of the risk determines the level of evidence we seek in providing assurance that the associated financial statement item is not materially misstated. These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 131 5.1 Impact of COVID-19 and the resulting significant changes to the business environment Key audit matter description The COVID-19 pandemic has significantly impacted the oil and gas industry. The principal area in which this has impacted bp is the demand destruction which led to low oil and gas prices in the year and an expectation that there will be an enduring impact going forward reducing forecast oil and gas prices. Accordingly this has impacted certain key estimates and judgements reliant on oil and gas prices. The lower oil and gas prices resulted in a loss for the year and the lower oil and gas price forecasts have resulted in significant PP&E impairments and reduced the attractiveness of developing certain E&A assets, leading to significant write-offs. The related principal risks that we have identified for our audit are as follows: • The forecast assumptions used in assessing the value of assets within bp’s balance sheet for impairment testing, particularly oil and gas price assumptions relevant to upstream oil and gas PP&E assets, may not appropriately reflect changes in supply and demand due to COVID-19 (see 'Impairment of upstream oil and gas PP&E assets' below); • The E&A asset write-offs are not aligned with management’s intentions. In addition there is a risk around the commercial viability of E&A assets that remain on the balance sheet (see 'write-off of E&A assets' below); and • The unobservable inputs including long term commodity prices and the associated liquidity in the market, volatility and correlations, which are critical in determining the valuation of level 3 financial instruments may not reflect how market participants would reflect the effect, if any, of COVID-19 (see 'valuation of other level 3 financial instruments' below). Management also assessed the following potential risks that could arise from the impact of COVID-19 and the resulting significant changes to the business environment, which we determined also to be audit risks: • The liquidity of the business and future cash flow projections associated with the going concern assumption may not reflect fully the impact of COVID-19. As a consequence, inter alia, of the COVID-19 pandemic and its implications, management significantly increased liquidity, including securing a new $10 billion revolving credit facility in March 2020, issuing $6.8 billion of bonds in April 2020 and issuing $11.9 billion of hybrid bonds in June 2020. In addition management performed a reverse stress test as set out in Note 1; • The carrying value of the downstream PP&E refining assets may no longer be recoverable, due to changes in supply and demand which have resulted from COVID-19. Furthermore, the useful economic lives of these assets could be reduced (see 'Potential impact of climate change' below); • Decommissioning obligations transferred to third parties as part of bp’s historical disposal transactions could potentially return to bp under relevant laws and regulations in the event the buyer is unable to complete decommissioning works due to the possibility of COVID-19 impacting their liquidity and financial stability; • The increased risk of credit losses following increased counterparty credit risk due to commodity price volatility, unprecedented demand destruction and bankruptcies of trading organisations. As described in Note 21, management recognises that credit risk has increased since 31 December 2019 but as there has also been a significant reduction in the group’s trade and other receivables balance, the total allowance for expected credit losses has not increased significantly in the year; • The shift to key business processes being performed virtually and the associated impact on the control environment. In particular, in an environment of volatile commodity prices, there is an increased risk of non-compliance with policies and procedures by traders within the T&S function, resulting in the risk of breaches in trader limits, as the monitoring and surveillance of front office activities becomes more challenging; and • During the year, a number of oil trading entities in Singapore have declared bankruptcies. After the bankruptcies, allegations have been made that certain of the funding arrangements of these oil trading entities involved finance schemes whereby funds were raised backed by assets that did not exist or were supported by fraudulent sales. These finance schemes typically involved back-to-back intra-group arrangements transacted with an independent third party. There is a risk that bp, as a significant participant in the oil trading sector in Singapore, may have been a counterparty to such transactions, resulting in exposure to claims by the financiers to these oil trading entities. The above considerations were a significant focus of management during the period which led to this being a matter that we communicated to the Audit Committee, and which had a significant effect on the overall audit strategy. We therefore identified this as a key audit matter. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. 132 bp Annual Report and Form 20-F 2020 How the scope of our audit responded to the key audit matter Financial statements Overall response We held discussions with management, Deloitte fraud specialists and within the Group engagement team to identify the areas where we felt COVID-19 could have had a potential impact on the financial statements. Audit procedures in respect of the three principal audit risks identified Our audit response related to the three principal audit risks identified is set out under the key audit matters for impairment of upstream oil and gas PP&E assets on page 136, the write-off of E&A assets on page 139 and the valuation of other Level 3 instruments on page 140. Other audit procedures performed We performed further audit procedures, in addition to those discussed in section 4, to obtain sufficient appropriate audit evidence regarding the appropriateness of management’s use of the going concern basis of accounting in the preparation of the financial statements. These procedures included an assessment and reperformance of bp's reverse stress test and a detailed analysis of the new financing agreements. We challenged management’s analysis of potential exposures related to bp’s decommissioning obligations transferred to third parties as part of disposal transactions, including comparing management’s assessment of each counterparty’s liquidity and creditworthiness to third party support where available and holding discussions with bp's internal legal counsel. We assessed the credit risk of the portfolio and the associated valuation methodology to check the expected credit loss allowance appropriately reflects the level of risk. In performing this assessment, we considered the impact of demand destruction and price volatility on counterparties in specific market sectors such as Aviation, Independent refiners, Retail Energy Providers, West African oil producers and regional commodity trading organisations. We understood changes made to the control environment following the shift to remote working. Where there was a change in the control, we challenged the appropriateness of these changes and assessed the operating effectiveness of the control in light of these changes. We specifically obtained an understanding of the output of management’s review of traders’ compliance with policies and procedures in light of remote working, including gain / loss alerts, operational risk incidents reports and internal audit findings. To respond to the oil trading entities’ bankruptcies, we altered the nature and extent of our procedures across seaborne trading activity for the year ended 31 December 2020. Using data analytics, we have profiled the related transactions to identify activity that exhibited certain characteristics, such as sale and purchase transactions at the same location with similar settlement dates to determine the validity of such transactions. Our procedures to challenge the validity of the transactions in this population included obtaining an understanding of the commercial rationale for a sample of the contracts, obtaining independent confirmation or sighting third party evidence of bills of lading or other relevant documentation that evidenced the sale of inventory. We read the related disclosures in the Annual Report. Key observations Key observations in relation to oil and gas price assumptions used in upstream oil and gas PP&E assets impairment tests, E&A asset write-offs and the valuation of other Level 3 instruments are set out in the relevant key audit matter sections below. We are satisfied with the results of the further audit procedures we performed in respect of going concern and consider that management’s conclusion on the going concern assumption remains appropriate as set out in section 4 above. Management’s reverse stress test as set out in Note 1 on page 161 indicates that the group will continue to operate as a going concern for at least 12 months from the balance sheet date even if the Brent price fell to zero. In respect of the decommissioning liabilities that transferred to third parties, we agree with management's conclusion that no provision is required based on our assessment of the credit risk. We are satisfied with the disclosure set out in Note 33. We are satisfied with the results of our audit procedures in respect of credit risk and consider that management’s expected credit loss valuation methodology and the input assumptions appropriately reflects the level of risk in the current environment. We found that the controls we tested generally operated effectively in the remote working environment and we identified no issues of non-compliance with policies and procedures in the T&S function. Our additional procedures to assess if the Group is exposed to any risk of exposure from finance schemes similar to those that were used by the oil trading entities that declared bankruptcy did not highlight any additional issues. We consider that management’s other disclosures in the Annual Report relating to COVID-19 are consistent with the financial statements and our understanding of the business. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 133 5.2 Potential Impact of climate change and the energy transition (impacting PP&E, goodwill, intangible assets and provisions) Key audit matter description Climate change impacts bp’s business in a number of ways as set out in the strategic report on pages 2-70 of the Annual Report and Note 1 on page 160 of the financial statements. It represents a strategic challenge with its implications becoming increasingly significant towards 2050 and beyond. In February 2020 bp announced a new strategic intent which incorporates the ambition to become a ‘net zero’ company by 2050 or sooner. Further details were announced in August 2020 and September 2020. This led to revised intentions in respect of E&A assets and a significant internal restructuring. In addition, as a consequence of the COVID-19 pandemic, bp revised its oil and gas price forecasts significantly downwards. Whilst many of bp’s oil and gas properties, and refining assets, are long term in nature, none are being amortised over a period that extends beyond 2050. At current rates of depreciation, depletion and amortisation (DD&A), the average remaining depreciable life of the upstream PP&E is seven years and the downstream PP&E is twelve years. Accordingly, the related principal risks that we have identified for our audit are as follows: • Forecast assumptions used in assessing the value of upstream assets within bp’s balance sheet for impairment testing, particularly oil and gas price assumptions relevant to upstream oil and gas PP&E assets, may not appropriately reflect changes in supply and demand due to climate change and the energy transition (see 'impairment of upstream PP&E' below); and • Recoverability of E&A assets included within bp’s balance sheet where the investment required in order to develop particular projects into producing oil and gas PP&E assets might not be sanctioned by the board in future due to climate change considerations or a potential development may not be considered to be economic due to the impact of climate change and the energy transition on oil and gas prices (see 'write-off of exploration and appraisal (E&A) assets' below). Management also assessed the following potential risks that could arise from climate change considerations: • The carrying value of goodwill may no longer be recoverable and therefore may need to be impaired. The material upstream goodwill balance is recorded and tested at the segment level. The most significant assumption in the goodwill impairment test affected by climate change relates to future oil and gas prices (see 'impairment of upstream PP&E' below). Given the significant headroom in the goodwill impairment test, management identified no other assumption that could lead to a material misstatement of goodwill due to the energy transition and other climate change factors. Disclosures in relation to sensitivities for goodwill are included within Note 14 on pages 190-191. The total goodwill balance as at 31 December 2020 is $12.5 billion, of which $7.8 billion relates to the upstream segment. The downstream segment has a goodwill balance of $4.7 billion, of which the most significant element is $2.9 billion relating to the Lubricants business. Notwithstanding the expected global transition to electric vehicles which may reduce demand for Lubricants, management has assessed due to the substantial headroom in the most recent impairment test (as described in Note 14), the likelihood that the recoverable amount of goodwill is less than its carrying value is remote. • Provisions for decommissioning and asset retirement obligations of upstream PP&E may need to be brought forward with a resulting increase in the present value of the associated liabilities. As described in Note 1, the impact of a two- year change to the timing of expected future decommissioning expenditures would not have a material impact on the decommissioning provision reported in the current period; • The carrying value of the downstream PP&E refining assets may no longer be recoverable, due to changes in supply and demand which arise as a consequence of COVID-19, climate change and the energy transition, for example the adoption of electric vehicles in markets where bp has significant fuel refining activity. Management identified impairment indicators at certain of the most material downstream refining assets, as a result of a combination of factors including the onset of COVID-19 and the resulting reduced demand for fuels. Accordingly, impairment tests were performed to assess the recoverability of the refinery asset carrying values. The most significant assumptions in the impairment tests are the assumed future refining margins, and demand profiles for fuel in the markets served by individual refineries. As disclosed in Note 1 to the accounts on page 160, management concluded that no material impairments were required on its downstream assets. • The useful economic lives of the group’s downstream refining assets may be shortened as society moves towards 'net zero' emissions targets and bp seeks to achieve its net-zero ambition, such that the depreciation charge is materially understated. As disclosed in Note 1 to the accounts on page 160, management concluded that demand for refined products is expected to remain strong over the useful life of its existing assets and hence no changes to the useful economic lives of its refinery assets was required. • Provisions for decommissioning downstream refining assets, previously not generally recognised on the basis that the potential obligations cannot be measured given their indeterminate settlement dates, might need to be recognised if reductions in demand due to climate change and exacerbated by COVID-19 curtail their operational lives. As disclosed in Note 1 to the accounts on page 171 management concluded that, although obligations may arise if refineries cease manufacturing operations, they would only be recognised at the point when sufficient information became available to determine potential settlement dates. In addition, as noted above, management concluded that demand for refined products is expected to remain strong in areas served by its existing refineries. Accordingly, other than where a decision has been made to cease refining operations, no triggers for assessing the need to record a decommissioning provision have been identified; • Climate change-related litigation brought against bp, as disclosed in Note 33 to the financial statements, may lead to an outflow of funds requiring provision in the current year; and This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. 134 bp Annual Report and Form 20-F 2020 How the scope of our audit responded to the key audit matter Financial statements • The announcement of the restructuring of the group and the resulting risk that the costs associated with the restructuring are not appropriately provided for and that following the reduction in size of the workforce the internal controls in place are not appropriately designed, implemented and operating effectively. The above considerations were a significant focus of management during the period which led to this being a matter that we communicated to the audit committee, and which had a significant effect on the overall audit strategy. We therefore identified this as a key audit matter. Overall response We held discussions with management, with Deloitte Climate Change specialists and within the Group engagement team to identify the areas where we felt climate change could have a potential impact on the financial statements. We also established a climate change steering committee comprising a group of senior partners with specific climate change and technical audit and accounting expertise within Deloitte to provide an independent challenge to our key decisions and conclusions with respect to this area. Audit procedures in respect of the three principal audit risks identified The audit response related to the two principal audit risks identified is set out under the key audit matters for impairment of upstream oil and gas PP&E assets on page 136-8 and the write-off of exploration and appraisal assets on page 139. Other audit procedures performed We performed procedures to satisfy ourselves that, other than future oil and gas price assumptions, there were no other assumptions in management’s upstream goodwill impairment test to which reasonably possible changes could cause goodwill to be materially misstated. We obtained evidence which supported management’s conclusion that goodwill relating to downstream segment activities is not impaired. We challenged management’s assertion that the impact of potential changes to upstream decommissioning dates would not have a material impact on the amounts reported in the current period by assessing the analysis of decommissioning timing, and conducting sensitivity analysis as part of our audit procedures. We challenged the results of the impairment testing of downstream PP&E refining assets by considering internal and external market studies of future supply and demand, and conducting sensitivity analysis. For those refining assets where impairment triggers were identified, we tested the mathematical completeness and accuracy of the impairment models and assessed the appropriateness of key assumptions and inputs. We also tested management’s internal controls over the impairment tests. We challenged management’s assertion that no changes are required to the assessed useful economic lives of refining assets as a consequence of COVID-19 and climate change factors. In doing this, we obtained third party reports assessing future refined petroleum product demand for those countries which are included in our group full audit scope for downstream. The future demand forecasts were prepared under a range of scenarios including scenarios noted as being consistent with achieving the 2015 COP 21 Paris agreement goal to limit temperature rises to well below 2°C ('Paris 2°C Goal'). We challenged management’s analysis which supported their judgement that no decommissioning provisions should be recognised in respect of refineries where there is ongoing activity and management has no intention to cease these activities. In doing so we considered the third party forecasts referenced above which, for countries included in our group full audit scope for downstream, show that demand for refined petroleum products is expected to remain significant for at least the current remaining useful economic lives of the refineries, even under scenarios consistent with the Paris 2°C Goal. With regard to climate change litigation, we designed procedures specifically to respond to the risks that provisions could be understated or that contingent liability disclosures may be omitted or be inaccurate including: • Holding discussions with the group general counsel and other senior bp lawyers regarding climate change matters; • Conducting a search for climate change litigation and claims brought against the group; and • Making written inquiries of, and holding discussions with, external legal counsel advising bp in relation to climate change litigation. We held discussions with management and tested the controls in respect of the restructuring provision. We performed substantive procedures to assess whether the provision was appropriately recognised as required by International Accounting Standard (IAS) 37 ‘Provisions, Contingent Liabilities and Contingent Assets’. We read the other information included in the Annual Report and considered (a) whether there was any material inconsistency between the other information and the financial statements; or (b) whether there was any material inconsistency between the other information and our understanding of the business based on audit evidence obtained and conclusions reached in the audit. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 135 Key observations Key observations in relation to oil and gas price assumptions used in upstream oil and gas PP&E asset impairment tests, and the recoverability of exploration and appraisal assets including the impacts of climate change, are set out in the relevant key audit matter below. We are satisfied with the disclosures around the sensitivity analysis performed in respect of goodwill, and that the significant headroom is indicative that the energy transition and other climate change factors could not lead to a material misstatement of this balance. We are satisfied that the disclosure in Note 1 in respect of the impact of timing on decommissioning provisions is appropriate. We are satisfied with the results of our procedures relating to the carrying value of refining assets and that no impairments are required. Based on the market studies we read, we are satisfied with the results of our procedures relating to the assessment of useful economic lives, and therefore depreciation charges, for downstream refining assets. We noted that the third party demand forecasts generally showed a reduction in forecast long term demand, under a Paris 2°C Goal scenario, compared to the equivalent forecasts in the prior year. Nevertheless, we are satisfied that it is not possible to estimate reliably a settlement date for any decommissioning obligations prior to a decision being made to cease refining operations and that therefore no triggers have arisen that would require a decommissioning provision to be recorded for the group’s operating refinery assets. Based on the audit evidence obtained both from internal and external legal counsel, we were satisfied with management’s assertion that no provision should currently be made in respect of climate change litigation. We read management’s disclosure of the contingent liabilities in respect of these matters and concluded that the disclosures are appropriate. We found the controls relating to the restructuring provision to be operating effectively and are satisfied that the restructuring provision is recorded in accordance with IAS 37, ‘Provisions, Contingent Liabilities and Contingent Assets’. We are satisfied that management’s other disclosures in the Annual Report relating to climate change are consistent with the financial statements and our understanding of the business. 5.3 Impairment of upstream oil and gas PP&E assets Key audit matter description The group balance sheet at 31 December 2020 includes PP&E of $115 billion (2019 $133 billion), of which $74 billion (2019 $90 billion) is oil and gas properties within the upstream segment. Management’s best estimate of oil and gas price assumptions for value–in-use impairment tests were revised downwards during 2020 compared to the prior year assumptions, as set out in Note 1 on page 161. The downward revisions reflect an expectation that the aftermath of the COVID-19 pandemic will accelerate the pace of transition to a lower carbon economy and energy system. Given the significance of these revisions, management tested all upstream CGUs for impairment. Management recorded $12.9 billion (2019 $6.8 billion) of pre-tax upstream CGU impairment charges, in large part due to the oil and gas prices revisions detailed above, and $0.1 billion of pre-tax upstream CGU impairment reversals (2019 $0.1 billion). Further information has been provided in Note 1 on page 160 and Note 4 on page 179. Through our audit risk assessment procedures, we identified three key management estimates in management’s determination of the level of impairment charge and/or reversal to record. These are: • Oil and gas prices - bp’s oil and gas price assumptions have a significant impact on many CGU impairment assessments performed across the upstream segment, and are inherently uncertain. As noted above, the estimation of future prices is subject to increased uncertainty given climate change, the global energy transition and the impact of COVID-19. There is a risk that management do not forecast reasonable 'best estimate' oil and gas price forecasts when assessing CGUs for impairment, leading to material misstatements. These price assumptions are highly judgmental and are pervasive inputs to most upstream impairment tests, such that any misstatements would also aggregate. • Discount rates - Given the long timeframes involved, certain CGU impairment assessments are sensitive to the discount rate applied. Discount rates should reflect the return required by the market and the risks inherent in the cash flows being discounted. There is a risk that management do not assume reasonable discount rates, adjusted as applicable for country risks and relevant tax rates, leading to material misstatements. Determining a reasonable discount rate is highly judgmental and, consistent with price assumptions above, the discount rate assumption is also a pervasive input across upstream impairment tests, before adjustments for asset specific risks and tax rates, such that any misstatements would also aggregate. • Reserves and resources estimates - A key input to certain CGU impairment assessments is the oil and gas production forecast, which is based on underlying reserves estimates and field specific development assumptions. Certain CGU production forecasts include specific risk adjusted resource volumes, in addition to proved or probable reserves estimates, that are inherently less certain than reserves; and assumptions related to these volumes can be particularly judgemental. There is a risk that material misstatements could arise from unreasonable production forecasts for individually material CGUs and/or from the aggregation of systematic flaws in bp’s reserves and resources estimation policies across the segment. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. 136 bp Annual Report and Form 20-F 2020 Financial statements We identified certain individual CGUs with a total carrying value of $32.1 billion (2019 $12.3 billion) which we determined would be most at risk of material impairment charges or reversals as a result of a plausible change in the oil and gas price assumptions. We identified that a subset of these CGUs were also sensitive to the discount rate assumption. Accordingly, we identified these as significant audit risks. We also identified CGUs with a further $16.0 billion (2019 $33.4 billion) of combined carrying value which were less sensitive. We identified these as a higher audit risk as they would be potentially at risk, in aggregate, to a material impairment or reversal by a plausible change in some or all of the key assumptions. Further information regarding these sensitivities is given in Note 1 on page 167. How the scope of our audit responded to the key audit matter We tested management’s key internal controls over the estimation of oil and gas prices, discount rates and reserve and resources estimates, as well as key internal controls over the performance of the impairment assessments where we identified audit risks. In addition, we conducted the following substantive procedures. Oil and gas prices • We independently developed a reasonable range of forecasts based on external data obtained, against which we compared management’s oil and gas price assumptions in order to challenge whether they are reasonable. • In developing this range we obtained a variety of reputable and reliable third party forecasts, peer information and other relevant market data. • In challenging management's price assumptions, we considered the extent to which they and each of the forecast pricing scenarios obtained from third parties reflect the impact of lower oil and gas demand due to climate change, the energy transition and COVID-19. • We specifically analysed third party forecasts stated as being, or interpreted by us as being, consistent with achieving the Paris 2°C Goal and considered whether they presented contradictory audit evidence. • We challenged management’s disclosures in Notes 1 and 4 including in relation to the sensitivity of oil and gas price assumptions to reduced demand scenarios whether due to climate change or other reasons. Discount rates • We independently evaluated bp’s discount rates used in impairment tests with input from Deloitte valuation specialists, against relevant third party market and peer data. • We assessed whether specific country risks and tax adjustments were reasonably reflected in bp’s discount rates. • We challenged management’s disclosures in Notes 1 and 4 including in relation to the sensitivity of discount rate assumptions. Reserves and resources estimates With the assistance of Deloitte oil and gas reserves specialists we: • assessed bp’s reserves and resources estimation methods and policies; • assessed, guided by our risk assessment, how these policies had been applied to a sample of bp’s reserves and resources estimates which included those that we judged to represent the greatest risk of material misstatement; • read a sample of reports provided by management’s external experts and assessed the scope of work and findings of these third parties; • assessed the competence, capability and objectivity of bp’s internal and external reserves experts, through understanding their relevant professional qualifications and experience; • compared the production forecasts used in the impairment tests with management’s approved reserves and resources estimates, those estimates having been subjected to the controls that we had tested; and • performed a retrospective assessment to check for indications of estimation bias over time. Other procedures • We challenged management’s CGU determinations, and considered whether there was any contradictory evidence present. • We validated that bp’s impairment methodology was acceptable under IFRS and tested the integrity and mechanical accuracy of certain impairment models based on our risk assessment. • We challenged other CGU specific valuation input assumptions, including but not limited to material cost and tax forecasts, by comparing forecasts to approved internal and third party budgets, development plans, independent expectations and historical actuals. • Where relevant, we assessed management’s historical forecasting accuracy and whether the estimates had been determined and applied on a consistent basis across the group. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 137 Key observations Oil and gas prices We determined that bp’s oil and gas price impairment assumptions are reasonable when compared against a range of third party forecasts that we identified as being appropriate for this purpose, noting in particular that they had been updated for COVID-19. In forming this view, we included each forecaster’s 'base case', 'central case' or 'most likely' estimate. For the purpose of PP&E impairment tests, management is required under IAS 36 to apply its current 'best estimate' of future oil and gas prices. We further observed that, as well as publishing a 'base case', 'central case' or 'most likely' estimate, certain third party price forecasters published other price forecasts including some that were stated as, or were interpreted by us as being, 'Paris 2°C Goal' scenarios. These were typically the lowest of all scenarios from those third parties and we observed that none of those third party forecasters described their 'Paris 2°C Goal' scenarios as their 'base case', 'central case' or 'most likely' estimate. We noted that not all of these third parties had updated their forecasts for COVID-19 although, unlike for the ‘best estimate forecasts’ which had typically been reduced significantly post COVID-19, it is less evident that ‘Paris 2°C forecasts’ would need changing as a result of COVID-19 at least in the longer term and we noted certain updated forecasts that had not changed significantly. Accordingly, in respect of Paris 2°C price scenarios only, we continued to place some weight on certain pre-COVID-19 third party forecasts. Management note on page 160 that they consider their central price assumptions to be broadly in line with a range of transition paths consistent with the goals of the Paris climate change agreement. We observed that for oil, whilst being within the lower half of our range of 'best estimate' forecasts as described above, bp’s price assumptions were overall at the top end of our range of 'Paris 2°C Goal' scenarios. For gas, as well as being within and towards the low end of our range of 'best estimate' forecasts as described above, bp’s price assumptions were within and towards the higher end of our range of 'Paris 2°C Goal' scenarios. We also noted certain other reputable third party sources that set out or implied even higher prices under a Paris 2°C scenario. Accordingly, we consider management’s view as set out above to be reasonable. We reviewed the disclosures included in Note 1 to the accounts in respect of price assumptions, including the sensitivity analysis presented therein. We observed that management’s downside sensitivity, in which oil and gas prices are 10% lower than the best estimate in all future periods, is comfortably within a range of third party Paris 2°C Goal gas price forecasts. For oil, management’s downside sensitivity is comfortably within a range of Paris 2°C Goal forecasts in the period to 2028, but towards the top end of that range by 2050. Discount rates bp’s post-tax nominal 6% weighted average cost of capital, being the starting point for setting discount rates used for impairment testing, was within the independent range calculated by our Deloitte valuation specialists. We were also satisfied with the calculation of country risk premia. Accordingly, we are satisfied with the discount rates used in the impairment testing. Reserves and resources estimates We found that the production forecasts used in the impairment tests that we tested were reasonable and appropriately risked where applicable, for the purposes of management’s impairment tests. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. 138 bp Annual Report and Form 20-F 2020 5.4 Write-off of E&A assets, included within 'Intangible assets' within the Group balance sheet Key audit matter description The group capitalises E&A expenditure on a project-by-project basis in line with IFRS 6 'Exploration for and Evaluation of Mineral Resources'. At 31 December 2020, $4.1 billion (2019 $14.1 billion) of E&A expenditure was carried on the group balance sheet. Financial statements E&A activity carries inherent risk and a significant proportion of projects fail, requiring the write-off or impairment of the related capitalised costs when the relevant criteria in IFRS 6 and bp’s accounting policy are met. Furthermore, similar to upstream PP&E assets discussed above, E&A assets are also potentially exposed to climate change, the global energy transition, and COVID-19, in that a greater number of E&A projects may not proceed as a consequence of lower forecast future demand and oil and gas pricing, lower appetite by management and the board to allocate capital to certain projects, and/or increased objections from stakeholders to the development of certain projects. As a result of bp’s revised strategy announced in 2020, including a reduced capital frame, a net-zero carbon ambition and a decision not to explore in new countries, and reflecting lower oil and gas price assumptions, management identified IFRS 6 impairment indicators at a number of upstream’s largest E&A assets during the year. This led to management recording $9.9 billion of pre-tax E&A write-offs and impairments during 2020 (2019 $0.6 billion), detailed further in Notes 1 and 8 on pages 164 and 184. The determination of when E&A costs should be written off or impaired, or retained on the balance sheet as E&A assets, can be complex and require significant judgement from management in assessing this. There is a risk that certain capitalised E&A costs are written off or impaired when they should not have been, due to inappropriate and/or inconsistent application of IFRS 6 impairment criteria and bp’s accounting policy, leading to material misstatements. There is also a risk that E&A costs remain capitalised on the balance sheet which ought to have been written off or impaired, leading to material misstatements. We identified significant audit risks for the individually material E&A write-offs and impairments recorded in 2020, specifically the Kaskida and Tigris (Paleogene) licenses that were the largest part of the $2.5 billion Gulf of Mexico write-downs, the Terre de Grace oil sands project that was the largest part of the $2.5 billion Canada write-downs and the BM-C-35, BM-C-32 (Itaipu) & BM-C-30 (Wahoo) licenses that were the largest part of the $2.1 billion Brazil write- downs. We also identified higher risks in relation to certain other 2020 E&A write-offs and impairments recorded; and higher risks at certain assets within the $4.1 billion of E&A costs that remain capitalised under IFRS 6 at 31 December 2020. How the scope of our audit responded to the key audit matter We obtained an understanding of the group’s E&A assessment processes and tested management’s key internal controls. This included the new key internal controls operated by management for the key decisions taken as a result of bp’s new strategy, which when taken together with the lower forecast oil and gas prices, led to a large portion of the material write-offs and impairments recorded during 2020. We challenged management’s key E&A judgements, with regards to the impairment criteria of IFRS 6 and bp’s accounting policy. We corroborated key internal and external evidence relevant to significant write-offs and the assets that remained on the balance sheet. This included analysing evidence of future E&A plans, budgets and capital allocation decisions, assessing management’s key accounting judgement papers, holding discussions to challenge top level operational and finance management on the key judgements taken and reading meeting minutes, license documentation and evidence of active dialogue with partners and regulators including negotiations to renew licences or modify key terms, and external press releases. For E&A assets that were written off or impaired by management in 2020, including in particular those based upon decisions taken in line with management’s new strategy, we considered whether evidence (and potential contradictory evidence) about activity in the year, future budgeted expenditure and exploration/appraisal plans, including plans and expectations for licence relinquishment or retention, were consistent with the decisions taken by management to write- off or impair these assets. We assessed whether management had consistently applied IFRS 6 and bp’s accounting policy to impairment assessments, taking account of in year judgements and historical look back considerations, and the relevant facts and circumstances of specific E&A assets. When considering capital allocation decision making, we considered whether the progression of any projects that remain on the balance sheet would be inconsistent with elements of bp’s new strategy and in particular its net zero carbon commitments. We concluded that the key assumptions had been appropriately determined and the judgements management had made were appropriately supported. No inappropriate or untimely E&A impairment charges or write-offs were identified, nor was the need for any additional impairments or write-offs identified from the work we performed. We also confirmed management's view that they did not consider that the progression of any of their E&A assets would be inconsistent with bp’s current strategy and management’s capital frame and capital allocation intentions. Key observations This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 139 5.5 Accounting for structured commodity transactions (SCTs) within the trading and shipping (T&S) function and the valuation of other Level 3 financial instruments, where fraud risks may arise in revenue recognition (potentially impacting all financial statement accounts, in particular finance debt) Key audit matter description In the normal course of business, T&S enters into a variety of transactions for delivering value across the group’s supply chain. The nature of these transactions requires significant audit effort to be directed towards challenging management’s valuation estimates or the adopted accounting treatment. We have undertaken an analysis of the portfolio composition and revisited our risk assessment throughout the year focussing particularly on the impact of COVID-19 on the valuation assertion. This process has provided us with a deeper understanding of the impact of market volatility, demand destruction and the changing structure of the markets in which bp operates. Accounting for structured commodity transactions: T&S may also enter into a variety of transactions which we refer to as SCTs. We generally consider a SCT to be an arrangement having one of the following features: • Two or more counterparties with non-standard contractual terms; • Multiple commodity-based transactions; and/or • Contractual arrangements entered into in contemplation of each other. SCTs are often long-dated, can have a significant multi-year financial impact, and may require the use of complex valuation models or unobservable inputs when determining their fair value, in which case they will be classified as level 3 financial instruments under IFRS 13, ‘Fair Value Measurement’. Accounting for SCTs is typically complex and involves significant judgment, as these transactions often feature multiple elements that will have a material impact on the presentation and disclosure of these transactions in the financial statements and on key performance measures, including in particular the classification of liabilities as finance debt. Accordingly, we have identified the accounting for SCTs as a significant audit risk. Level 3 financial instruments: Unlike other financial instruments whose values or inputs are readily observable and therefore more easily independently corroborated, there are certain transactions for which the valuation is inherently more subjective due to the use of either complex valuation models and/or unobservable inputs. These instruments are classified as level 3 financial assets or liabilities. This degree of subjectivity also gives rise to a risk of potential fraud through management incorporating bias in determining fair values. Accordingly, we have identified these as a significant audit risk. As at 31 December 2020, the group’s total financial assets and liabilities measured at fair value were $12.7 billion (2019 $10.5 billion) and $8.4 billion (2019 $8.8 billion), of which level 3 derivative financial assets were $6.4 billion (2019 $5.5 billion) and level 3 derivative financial liabilities were $5.3 billion (2019 $4.4 billion). How the scope of our audit responded to the key audit matter Accounting for SCTs For structured commodity transactions, we: • Tested controls related to the accounting for complex transactions. • Developed an understanding of the commercial rationale of the transactions through reading transaction documents and executed agreements, and discussions with management. • Performed a detailed accounting analysis for a sample of SCTs involving significant day one profits, deferred working capital arrangements, offtake arrangements and/or commitments. We confirmed that any day one profits were appropriately deferred. For SCTs which were identified during 2018 and 2019 and that continue through 2020, we have refreshed our assessment in 2020 taking account of any amendments to the contracts. To assess the appropriateness of the accounting treatment of SCTs, we embedded technical accounting specialists within the audit team. Level 3 financial instruments: To address the complexities associated with auditing the value of level 3 financial instruments, the engagement team included valuation specialists having significant quantitative and modelling expertise to assist in performing our audit procedures. Our valuation audit procedures included the following control and substantive procedures: • We tested the group’s valuation controls including the: ◦ Model certification control, which is designed to review a model’s theoretical soundness and the appropriateness of its valuation methodology; and ◦ Independent price verification control, which is designed to review the appropriateness of valuation inputs that are not observable and are significant to the financial instrument’s valuation. • We performed substantive valuation testing procedures at interim and year-end balance sheet dates, including: ◦ Comparing management’s input assumptions against the expected assumptions of other market participants and observable market data; ◦ Evaluating management’s valuation methodologies against standard valuation practice and analysing whether a consistent framework is applied across the business period over period; and This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. 140 bp Annual Report and Form 20-F 2020 ◦ Engaging a Deloitte valuations specialist to challenge models, develop fair value estimates and verify consistency in management’s modelling and input assumptions throughout the year. Our independent estimates were established using independently sourced inputs (where available). We evaluated whether the differences between our independent estimates and management’s estimates were within a reasonable range. In situations where we utilised management’s inputs, these were compared to external data sources to determine whether they were reasonable. Financial statements Key observations We assessed the features of the SCTs and determined that the accounting adopted for each of them was appropriate and in accordance with IFRS. We concluded that management’s valuations relating to level 3 instruments were appropriate. We did not identify any indications of inappropriate misrepresentation of revenue recognition in the transactions, valuation estimates or accounting entries that we tested. We did not identify any issues in our testing of the controls related to the accounting for complex transactions and found these to be operating effectively. 5.6 IT controls relating to financial systems (potentially impacting all financial statement accounts) Key audit matter description The group’s financial systems environment is complex, with 113 separate systems scoped as being relevant for the group audit. Due to the reliance on financial systems within the group, IT controls which support these systems are critical to maintaining an effective control environment. We identified IT control deficiencies in two key areas. User Access Management: In 2018 and 2019 we identified a number of deficiencies relating to user access management, both within the group and at the group’s IT service organizations (together ‘access deficiencies’). Management implemented a remediation and mitigation programme throughout 2019 and 2020, which addresses the vast majority of these user access deficiencies. To the extent the controls were not remediated management designed and tested mitigating controls for the period prior to the successful remediation of each control. The remediation program is substantially complete but will continue into 2021 because certain deficiencies are dependent on other bp change programmes including the completion of a new identity management system implementation. The access deficiencies identified increase the risk that individuals across bp had inappropriate access during the period. This results in an increased risk that data, automated controls and reports from the affected systems are not reliable. The access deficiencies impact all components within the scope of our group audit. Change Management: We identified in 2019 deficiencies around the bp IT change management process. In 2020, management continued to identify further inconsistent implementation of the minimum change management controls, specifically around approval of changes and evidence of testing. Management has continued to perform retrospective mitigation throughout 2020. Furthermore, in 2020 bp increased its use of the DevOps model for managing change releases. DevOps is an accepted way of managing change which bridges the development and operations process with the aim of reducing change timelines and enabling agility. The implementation of DevOps allows user privileges to be extended so developers are also able to implement changes, a key segregation of duties (SoD) conflict within the change management lifecycle. To manage this key SoD conflict, additional controls need to be implemented to ensure a developer cannot undermine the change management process through the ability to develop and implement the same change. We identified that 25 applications using the DevOps change model did not have appropriate preventative SoD controls in place. For the systems we identified, this issue was remediated and mitigated in 2020 by management. Management has completed a root cause analysis and is implementing a sustainable forward looking governance and control plan to manage the risk around DevOps. The change management deficiencies identified increase the risk of inappropriate or untested changes being made which could negatively impact the way a system operates and accordingly, the ongoing integrity of the controls, reports and data within key financial systems. The change management issues identified impact all components within the scope of our group audit. Both the user access management controls and the controls over change management are pervasive to the group’s operations and accordingly the level of risk ascribed to our work in this area is dependent on the nature and complexity of the control itself and the risks addressed by the control. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 141 How the scope of our audit responded to the key audit matter We obtained an understanding of management’s processes and relevant financial systems, and tested the associated general IT controls and automated business controls. We also tested the integrity of key reports. In responding to the identified deficiencies our IT specialists: User Access Management: Performed procedures to: • Test the controls that management has implemented or re-designed in order to remediate the deficiencies; • Assess and test the mitigating controls that management identified, including directly testing those controls operated by IT service organizations; and • Determine the impact that utilizing inappropriate levels of access could feasibly have had on the affected systems including assessing the likelihood of inappropriate user access impacting the financial statements. We tested controls implemented by management to identify instances of the use of inappropriate access. Change Management: Performed independent testing over: • Mitigating controls identified by management to confirm the integrity of the change management process. These procedures were designed to address the likelihood and impact of inappropriate or untested changes being implemented; and • Management’s mitigation procedures, which demonstrated that segregation of duties across the development and implementation of change, for those systems impacted by DevOps was retained. These procedures were designed to address the likelihood and impact that a single user could undermine the bp change management process through creation and implementation of a change. Key observations Our testing confirmed that the remediated controls were operating effectively. We also found the mitigating controls management performed to be operating effectively. In addition, our independent testing to demonstrate whether the access and change management deficiencies were exploited during the year, did not identify instances of inappropriate access usage or change implementation. Accordingly, we were satisfied with the results of the remediation to date and the mitigation such that we continued to adopt an audit approach which places reliance on the operating effectiveness of financial controls. Under our methodology, this enables us to apply lower sample sizes in our substantive testing. Management continues to work to remediate fully the access and change management deficiencies identified. 5.7 Management override of controls (potentially impacting all financial statement accounts) Key audit matter description We conducted an assessment of the fraud risks arising from management override of controls by considering potential areas where the group’s financial statements could be manipulated, including: • Inappropriate accounting estimates and judgements; • The posting of fictitious or fraudulent journal entries; or • Accounting for significant unusual transactions arising from changes to the business. In performing this assessment we considered pressures or incentives to achieve certain IFRS or non-GAAP measures due to the remuneration arrangements of people in Financial Reporting Oversight Roles (FRORs), including management and senior executives as well as other opportunities or incentives which could exist in light of the current environment; During our 2018 and 2019 audits we identified control deficiencies relating to the posting of accounting journal entries at the components where testing was performed. Management’s programme to remediate these deficiencies through the design of processes and controls in respect of the posting and review of manual journals was completed by the end of 2020 but has been impacted by the IT Control issues outlined in section 5.6 above. Accordingly, these control deficiencies remained during 2020 and we tested the mitigating controls which had been identified by management during the previous years’ audits or other appropriate controls to mitigate these deficiencies. We expect to be testing the remediated journal controls in 2021 once the related IT control deficiencies have been remediated. This had a significant bearing again this year on the allocation of audit resources and has been discussed with the audit committee throughout the year. Accordingly, we identified this as a key audit matter. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. 142 bp Annual Report and Form 20-F 2020 How the scope of our audit responded to the key audit matter Key observations Financial statements We tested the mitigating controls that management identified as responding to the risk of fraudulent journal entries. In addition, we: • Made inquiries of individuals involved in the financial reporting process about inappropriate or unusual activity relating to the processing of journal entries and other adjustments. • Identified and tested relevant entity-level controls, in particular those related to the bp Code of Conduct, whistleblowing (bp OpenTalk) and controls monitoring financial reporting processes and financial results. • Used our data analytics tools to select journal entries and other adjustments made at the end of a reporting period or otherwise having characteristics associated with common fraud schemes for testing. • Tested journal entries and other adjustments recorded in the general ledger throughout the period, with a particular focus on adjustments that occur late in the financial close process. We have assessed accounting estimates for bias and evaluated whether the circumstances producing the bias, if any, represent a risk of material misstatement due to fraud. A number of the most significant estimates are covered by the other Key Audit Matters set out above. This assessment included: • Evaluating whether the judgements and decisions made by management in making the accounting estimates included in the financial statements, even if they are individually reasonable, indicate a possible bias on the part of bp's management that may represent a risk of material misstatement due to fraud; and • Performing a retrospective analysis of management judgements and assumptions related to significant accounting estimates reflected in the financial statements of the prior year. We considered whether there were any significant transactions that are outside the normal course of business, or that otherwise appear to be unusual due to their nature, timing or size. The risks and responses to the revenue recognition risks within the trading and shipping function are set out on pages 140-141. Mitigating controls to address the risk associated with the design deficiencies were identified. These included low-level analytical reviews, controls over closing balances, period-end analytical review controls and certain automated business controls. Our testing of these controls concluded they were, in combination, appropriately designed and implemented and they were operating effectively for the year. Our substantive testing of journal entries and other adjustments, selected through the use of our data analytics tools, did not identify any inappropriate items. We did not identify evidence of overall bias or any significant unusual transactions for which the business rationale (or the lack thereof) of the transaction suggested that it may have been entered into to engage in fraudulent financial reporting or to conceal misappropriation of assets. Management expects the journal control remediation programme to be completed in 2021. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 143 6. Our application of materiality 6.1 Materiality We define materiality as the magnitude of misstatement in the financial statements that makes it probable that the economic decisions of a reasonably knowledgeable person would be changed or influenced. We use materiality both in planning the scope of our audit work and in evaluating the results of our work. Based on our professional judgement, we determined materiality for the financial statements as a whole as follows: Materiality Basis for determining materiality Rationale for the benchmark applied Parent company financial statements Materiality has been set at $900 million for the current year (2019 $1,200 million). We determined materiality for our audit of the standalone parent using 1% (2019 1%) of net assets. The materiality determined for the standalone parent company financial statements exceeds the group materiality. This is due to the fact that the net asset balance of the parent company financial statements exceeds the net asset balance of the group financial statements. As the company is non­trading and operates primarily as a holding company, we believe the net asset position is the most appropriate benchmark to use. Where there were balances and transactions within the parent company accounts that were within the scope of the audit of the group financial statements, our procedures were undertaken using the lower materiality level applicable to the group audit components. It was only for the purposes of testing balances not relevant to the group audit, such as intercompany investment balances, that the higher level of materiality applied in practice. Group financial statements Materiality has been set at $600 million for the current year. In 2019, we used a materiality of $850 million. The decrease is due to bp’s financial performance in 2020. Due to the significant losses incurred in 2020 as a consequence, inter alia, of the COVID-19 pandemic and in particular the decrease in oil and gas prices, we have changed our chosen metric from profit before tax in 2019 to net assets in 2020. We concluded that loss measures are not appropriate in our determination of materiality. Materiality was determined to be $600 million, which is 0.73% of net assets. In 2019, we determined materiality to be $850 million, which represented 10.3% of profit before taxation, 5% of underlying replacement cost profit before interest and taxation and 0.84% of net assets. Recognising the change in environment and using our professional judgement we have opted to use a conservative (lower) % of net assets given the uncertainty as to the level of future results. We conducted an assessment of which line items are the most important to investors and analysts by reading analyst reports and bp's communications to shareholders and lenders, as well as the communications of peer companies. We then considered the fact that bp reported a loss during the year. This resulted in us selecting net assets as the most appropriate benchmark. Profit before tax is the benchmark ordinarily considered by us when auditing listed entities. It provides comparability against other companies across all sectors, but has limitations when auditing companies whose earnings are strongly correlated to commodity prices, which can be volatile from one period to the next, and therefore may not be representative of the volume of transactions and the overall size of the business in the year, or where the impact of price volatility may result in material impairment charges or reversals in a particular year. As noted above, the COVID-19 pandemic and in particular the decrease in oil and gas prices resulted in significant losses in 2020. We therefore placed our emphasis on net assets in our determination of materiality this year. We further note that the non-GAAP measure underlying replacement cost profit before interest and tax is one of the key metrics communicated by management in bp's results announcements. Although it excludes some of the volatility arising from changes in crude oil, gas and product prices as well as 'non-operating items', the significant decrease in oil and gas prices was such that this measure was also a loss, and therefore we concluded this was not an appropriate metric on which to determine materiality this year. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. 144 bp Annual Report and Form 20-F 2020 Financial statements 6.2 Performance materiality We set performance materiality at a level lower than materiality to reduce the probability that, in aggregate, uncorrected and undetected misstatements exceed the materiality for the financial statements as a whole. Group performance materiality was set at 60% of group materiality for the 2020 audit (2019 60%) and parent company performance materiality was set at 60% of parent company materiality for the 2020 audit (2019 60%). Given the significant changes in the business environment due to the COVID-19 pandemic, we maintained a percentage consistent with that of our 2019 audit rather than increasing it to reflect the quality of the control environment and the fact that we are generally able to rely on controls, the relatively low level of misstatements identified in the current and prior years, as well as the fact that management is generally willing to correct these misstatements. 6.3 Error reporting threshold We agreed with the audit committee that we would report to the committee all audit differences in excess of $30 million (2019 $35 million), as well as differences below that threshold that, in our view, warranted reporting on qualitative grounds. We also report to the audit committee on disclosure matters that we identified when assessing the overall presentation of the financial statements. 7. An overview of the scope of our audit 7.1 Identification and scoping of components As a result of the highly disaggregated nature of the group, with operations in over 70 countries through approximately 920 cons units, a significant portion of our audit planning effort was ensuring that the scope of our work is appropriate in addressing the identified risks of material misstatement. The factors that we considered when assessing the scope of the bp audit, and the level of work to be performed at the cons units that are in scope for group reporting purposes, included the following: • The financial significance of an operating unit (which will typically include multiple cons units) to bp's revenue and loss before tax, or PP&E, including consideration of the financial significance of specific account balances or transactions. • The significance of specific risks relating to an operating unit, history of unusual or complex transactions, identification of significant audit issues or the potential for, or a history of, material misstatements. • The effectiveness of the control environment and monitoring activities, including entity-level controls. • The findings, observations and audit differences that we noted as a result of our 2019 audit engagement. Our audit approach was generally to place reliance on management’s controls over financial reporting. To ensure we were able to obtain sufficient, appropriate audit evidence for the purposes of our audit of the financial statements, we performed full scope audit procedures for 173 reporting cons units (2019 179) which were selected based on their size or risk characteristics. The primary reason for the change in scope is due to certain cons units in the T&S function no longer being used by management to record transactions. Our full-scope audits are in the UK, US, Azerbaijan, Germany, Canada and Singapore. One of the full-scope cons units includes the investment in Rosneft, a material associate not controlled by bp. In addition, component teams performed audit procedures on specified account balances in 62 cons units (2019 55) also covering operations in Angola, Alaska, Trinidad & Tobago, Mauritania & Senegal, and Australia. The group engagement team performed audit procedures on specified account balances to component materiality, with certain additional specific procedures performed by component teams, covering an additional 42 cons units (2019 29). The remaining cons units are not significant individually and include many small, low risk components and balances. On average, they each represent 0.03% of group revenue (2019 0.03%) and 0.03% of property, plant and equipment (2019 0.03%). In our assessment of the residual balances not covered by the above procedures, we have considered in particular the risk that there could be a material misstatement within the large number of geographically dispersed businesses, in particular within the downstream segment. This assessment included use of our analytic tools to interrogate data, preparation of trend analysis and comparison of business performance to market benchmark prices. We also tested management's group-wide controls across a range of locations and segments. We concluded that through this additional risk assessment, we have reduced the audit risk of such a misstatement arising to a sufficiently low level. Our audit coverage of ‘Property, plant and equipment’ and ‘Sales and other operating revenue’ is materially the same as in the prior year. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 145 Net assets $82,155mGroup materiality $600mComponent materiality range$300m to $180mAudit committee reportingthreshold $30mNet assets $82,155mGroup materiality $600m7.2 Our consideration of the control environment Our audit approach was generally to place reliance on management’s relevant controls over all business cycles affecting in scope financial statement line items. As part of our controls testing, we assessed the design and implementation of controls and tested a sample for operating effectiveness through a combination of tests of inquiry, observation, inspection and re-performance. In limited situations where we were not able to take a controls reliance approach due to controls being deficient and there not being sufficient mitigating or alternative controls we could rely on instead, we adopted a non-controls reliance approach. All control deficiencies which we considered to be significant, including those in respect of management override (see above) were communicated to the audit committee. All other deficiencies were communicated to management. For all deficiencies identified we considered the impact and updated our audit plan accordingly. The group’s financial systems environment is complex, with 113 separate IT systems scoped as being relevant to the audit for the following key locations (UK, US, Germany, Angola, Azerbaijan and Australia) as well as other minor locations. These systems are all directly or indirectly relevant to the entity’s financial reporting process. We planned to rely on the General IT Controls (GITCs) associated with these systems, where the GITCs were appropriately designed and implemented, and these were operating effectively. To assess the operating effectiveness of GITCs we performed testing on access security, change management, data centre operations and network operations. We have included our observations on the IT controls in our key audit matter section, (see 'IT controls relating to financial systems' above). 7.3 Working with other auditors The group audit team are responsible for the scope and direction of the audit process and provide direct oversight, review, and coordination of our component audit teams. We interacted regularly with the component Deloitte teams during each stage of the audit and reviewed key working papers. We maintained continuous and open dialogue with our component teams in addition to holding formal meetings quarterly to ensure that we were fully aware of their progress and results of their procedures. Due to the COVID-19 pandemic and the travel restrictions in place during the year, the senior statutory auditor and other group audit partners were unable to conduct visits to meet with the component teams responsible for the full scope locations, and other key locations including the key Global Business Services (GBS) accounting locations. As a result of this, we performed alternative virtual procedures which included attending planning meetings, discussing the audit approach and any issues arising from the component team's work, meetings with local management, and reviewing key audit working papers on higher and significant-risk areas to drive a consistent and high-quality audit. In addition, a global audit planning meeting was held virtually for two days in July led by the senior statutory auditor and involving the group audit team, partners and staff from all full scope component teams, audit teams responsible for testing at key GBS locations, senior management from bp, and the audit committee chairman. We were provided with direct access to Rosneft's auditor in order to evaluate their audit work on the financial statements of Rosneft, used as the basis for bp's equity accounting. We held meetings with Rosneft's auditor throughout the year, issued audit instructions to them, reviewed their written clearance reports responding to these instructions and, through our direct access, were able to exercise appropriate supervision and oversight of their audit work. We also tested directly bp's procedures and controls over its accounting for the investment in Rosneft. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. 146 bp Annual Report and Form 20-F 2020 Property, plant and equipment58%10%7%25%Full audit scopeSpecified account balancesSpecified audit proceduresReview at group levelSales and other operating revenues75%7%18%Full audit scopeSpecified account balancesSpecified audit proceduresReview at group levelFinancial statements 8. Other information The directors are responsible for the other information. The other information comprises the information included in the annual report, other than the financial statements and our auditor’s report thereon. Our opinion on the financial statements does not cover the other information and, except to the extent otherwise explicitly stated in our report, we do not express any form of assurance conclusion thereon. We have nothing to report in respect of these matters. In connection with our audit of the financial statements, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the financial statements or our knowledge obtained in the audit or otherwise appears to be materially misstated. If we identify such material inconsistencies or apparent material misstatements, we are required to determine whether there is a material misstatement in the financial statements or a material misstatement of the other information. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. 9. Responsibilities of directors As explained more fully in the directors’ responsibilities statement, the directors are responsible for the preparation of the financial statements and for being satisfied that they give a true and fair view, and for such internal control as the directors determine is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error. In preparing the financial statements, the directors are responsible for assessing the group’s and the parent company’s ability to continue as a going concern, disclosing as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the group or the parent company or to cease operations, or have no realistic alternative but to do so. 10. Auditor’s responsibilities for the audit of the financial statements Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISAs (UK) will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these financial statements. Details of the extent to which the audit was considered capable of detecting irregularities, including fraud and non-compliance with laws and regulations are set out below. A further description of our responsibilities for the audit of the financial statements is located on the FRC’s website at: frc.org.uk/ auditorsresponsibilities. This description forms part of our auditor’s report. 11. Extent to which the audit was considered capable of detecting irregularities, including fraud We identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and then design and perform audit procedures responsive to those risks, including obtaining audit evidence that is sufficient and appropriate to provide a basis for our opinion. 11.1 Identifying and assessing potential risks related to irregularities In identifying and assessing risks of material misstatement in respect of irregularities, including fraud and non-compliance with laws and regulations, we considered the following: • Our meetings throughout the year with the Group Head of Ethics and Compliance and reviews of bp’s internal ethics and compliance reporting summaries, including those concerning investigations; • Enquiries of management, internal audit, and the audit committee, including obtaining and reviewing supporting documentation, concerning the Group’s policies and procedures relating to: identifying, evaluating and complying with laws and regulations and whether they were aware of any instances of non-compliance ◦ ◦ detecting and responding to the risks of fraud and whether they have knowledge of any actual, suspected or alleged fraud; and ◦ the internal controls established to mitigate risks related to fraud or non-compliance with laws and regulations; • The group’s remuneration policies, key drivers for remuneration and bonus levels; and • Discussions among the engagement team regarding how and where fraud might occur in the financial statements and any potential indicators of fraud. The engagement team includes audit partners and staff who have extensive experience of working with companies in the same sectors as bp operates, and this experience was relevant to the discussion about where fraud risks may arise. The discussions also involved fraud experts from Deloitte's forensic accounting function in the Financial Advisory service line, who advised the engagement team of fraud schemes that had arisen in similar sectors and industries and participated in the initial fraud risk assessment discussions. In common with all audits under ISAs (UK), we are also required to perform specific procedures to respond to the risk of management override. We also obtained an understanding of the legal and regulatory frameworks that the group operates in, focusing on provisions of those laws and regulations that had a direct effect on the determination of material amounts and disclosures in the financial statements. The key laws and regulations we considered in this context included the UK Companies Act, UK Corporate Governance Code, IFRS as issued by the IASB and adopted by the EU, FRS 101, US Securities Exchange Act 1934 and relevant SEC regulations, as well as laws and regulations prevailing in each country in which we identified a full-scope component. In addition, we considered provisions of other laws and regulations that do not have a direct effect on the financial statements but compliance with which may be fundamental to the group’s ability to operate or to avoid a material penalty. These included the group’s operating licences, environmental regulations etc. 11.2 Audit response to risks identified As a result of performing the above, we did not identify any key audit matters related to the potential risk of fraud or non-compliance with laws and regulations. We did identify two key audit matters relating to fraud risks, as described above, being the accounting for SCTs and Level 3 instruments This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 147 within T&S, and management override of controls. The key audit matters section of our report explains the matters in more detail and also describes the specific procedures we performed in response to those key audit matters. In addition to the above, our procedures to respond to risks identified included the following: • reviewing the financial statement disclosures and testing to supporting documentation to assess compliance with provisions of relevant laws and regulations described as having a direct effect on the financial statements; • enquiring of management, the audit committee and in-house / external legal counsel concerning actual and potential litigation and claims; • performing analytical procedures to identify any unusual or unexpected relationships that may indicate risks of material misstatement due to fraud; • reading minutes of meetings of those charged with governance, reviewing internal audit reports and reviewing correspondence with HMRC and IRS; and • in addressing the risk of fraud through management override of controls, testing the appropriateness of journal entries and other adjustments; assessing whether the judgements made in making accounting estimates are indicative of a potential bias; and evaluating the business rationale of any significant transactions that are unusual or outside the normal course of business. We also communicated relevant identified laws and regulations and potential fraud risks to all engagement team members including internal specialists and significant component audit teams, and remained alert to any indications of fraud or non-compliance with laws and regulations throughout the audit. Report on other legal and regulatory requirements 12. Opinions on other matters prescribed by the Companies Act 2006 In our opinion the part of the directors’ remuneration report to be audited has been properly prepared in accordance with the Companies Act 2006. In our opinion, based on the work undertaken in the course of the audit: • The information given in the strategic report and the directors’ report for the financial year for which the financial statements are prepared is consistent with the financial statements; and • The strategic report and the directors’ report have been prepared in accordance with applicable legal requirements. In the light of the knowledge and understanding of the group and the parent company and their environment obtained in the course of the audit, we have not identified any material misstatements in the strategic report or the directors’ report. 13. Corporate Governance Statement The Listing Rules require us to review the directors' statement in relation to going concern, longer-term viability and that part of the Corporate Governance Statement relating to the group’s compliance with the provisions of the UK Corporate Governance Code specified for our review. Based on the work undertaken as part of our audit, we have concluded that each of the following elements of the Corporate Governance Statement is materially consistent with the financial statements and our knowledge obtained during the audit: • the directors’ statement with regards to the appropriateness of adopting the going concern basis of accounting and any material uncertainties identified set out on page 128; • the directors’ explanation as to its assessment of the group’s prospects, the period this assessment covers and why the period is appropriate set out on page 128; • the directors' statement on fair, balanced and understandable set out on page 127; • the board’s confirmation that it has carried out a robust assessment of the emerging and principal risks set out on pages 81; • the section of the annual report that describes the review of effectiveness of risk management and internal control systems set out on page 127; and • the section describing the work of the audit committee set out on pages 94-99. 14. Matters on which we are required to report by exception 14.1 Adequacy of explanations received and accounting records Under the Companies Act 2006 we are required to report to you if, in our opinion: • We have not received all the information and explanations we require for our audit; or • Adequate accounting records have not been kept by the parent company, or returns adequate for our audit have not We have nothing to report in respect of these matters. been received from branches not visited by us; or • The parent company financial statements are not in agreement with the accounting records and returns. 14.2 Directors’ remuneration Under the Companies Act 2006 we are also required to report if in our opinion certain disclosures of directors’ remuneration have not been made or the part of the directors’ remuneration report to be audited is not in agreement with the accounting records and returns. We have nothing to report in respect of these matters. This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. 148 bp Annual Report and Form 20-F 2020 Financial statements 15. Other matters 15.1 Auditor tenure The board appointed Deloitte as the company's auditor with effect from 29 March 2018 to fill the vacancy arising from the resignation of the previous auditor. On 27 May 2020, shareholders resolved at the annual general meeting to reappoint Deloitte as auditor from the conclusion of the meeting until the conclusion of the annual general meeting to be held in 2021 and authorized the directors to set the audit fees. The first accounting period we audited was the 12 month period ended 31 December 2018. The period of total uninterrupted engagement including previous renewals and reappointments of the firm is 3 years, covering the years ending 31 December 2018 to 31 December 2020. 15.2 Consistency of the audit report with the additional report to the audit committee Our audit opinion is consistent with the additional report to the audit committee we are required to provide in accordance with ISAs (UK). 16. Use of our report This report is made solely to the company’s members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work has been undertaken so that we might state to the company’s members those matters we are required to state to them in an auditor’s report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the company’s members as a body, for our audit work, for this report, or for the opinions we have formed. Douglas King FCA (Senior statutory auditor) For and on behalf of Deloitte LLP Statutory Auditor London, United Kingdom 22 March 2021 This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 149 Consolidated financial statements of the bp group Report of Independent Registered Public Accounting Firm To the shareholders and board of directors of BP p.l.c. Opinion on the financial statements We have audited the accompanying consolidated group balance sheets of BP p.l.c. and subsidiaries (together the company) as of 31 December 2020 and 2019, the related consolidated group income statements, group statements of comprehensive income, group statements of changes in equity, and group cash flow statements, for each of the three years in the period ended 31 December 2020, and the related notes (collectively referred to as the 'financial statements'). In our opinion, the financial statements present fairly, in all material respects, the financial position of the company as of 31 December 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended 31 December 2020, in conformity with International Financial Reporting Standards (IFRS) as adopted by the European Union and IFRS as issued by the International Accounting Standards Board. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the company's internal control over financial reporting as of 31 December 2020, based on criteria established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting relating to internal control over financial reporting and our report dated 22 March 2021 expressed an unqualified opinion on the group's internal control over financial reporting. Basis for opinion These financial statements are the responsibility of the group's management. Our responsibility is to express an opinion on the group's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the group in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. 1. Property, plant and equipment (PP&E) assets – Impairment of upstream oil and gas – Notes 1, 4 and 12 to the financial statements Critical Audit Matter Description The group balance sheet at 31 December 2020 includes PP&E of $115 billion, of which $74 billion is oil and gas properties within the upstream segment. Management’s best estimate of oil and gas price assumptions for value–in-use impairment tests were revised downwards during 2020 compared to the prior year assumptions, as set out in Note 1 on page 161. The downward revisions reflect an expectation that the aftermath of the COVID-19 pandemic will accelerate the pace of transition to a lower carbon economy and energy system. Given the significance of these revisions, management tested all upstream CGUs for impairment. Management recorded $12.9 billion of pre-tax upstream CGU impairment charges, in large part due to the oil and gas prices revisions detailed above, and $0.1 billion of pre-tax upstream CGU impairment reversals. Further information has been provided in Note 1 on page 160, Note 4 on page 179 and Note 12 on page 189. Through our audit risk assessment procedures, we have a identified a critical audit matter in respect of PP&E impairment principally due to the following three key management estimates in management’s determination of the level of impairment charge and/or reversal to record. • Oil and gas prices - bp’s oil and gas price assumptions have a significant impact on many CGU impairment assessments performed across the upstream segment, and are inherently uncertain. As noted above, the estimation of future prices is subject to increased uncertainty given climate change, the global energy transition and the impact of COVID-19. There is a risk that management do not forecast reasonable “best estimate” oil and gas price forecasts when assessing CGUs for impairment, leading to material misstatements. These price assumptions are highly judgmental and are pervasive inputs to most upstream impairment tests, such that any misstatements would also aggregate. There is also a risk that management’s oil and gas price related disclosures are not reasonable. • Discount rates - Given the long timeframes involved, certain CGU impairment assessments are sensitive to the discount rate applied. Discount rates should reflect the return required by the market and the risks inherent in the cash flows being discounted. There is a risk that management do not assume reasonable discount rates, adjusted as applicable for country risks and relevant tax rates, leading to material misstatements. Determining a reasonable discount rate is highly judgmental and, consistent with price assumptions above, the discount rate assumption is also a pervasive input across upstream impairment tests, before adjustments for asset specific risks and tax rates, such that any misstatements would also aggregate. • Reserves and resources estimates - A key input to certain CGU impairment assessments is the oil and gas production forecast, which is based on underlying reserves estimates and field specific development assumptions. Certain CGU production forecasts include specific risk adjusted resource volumes, in addition to proved or probable reserves estimates, that are inherently less certain than reserves; and assumptions related to these volumes can be particularly judgemental. There is a risk that material misstatements could arise from unreasonable production forecasts for individually material CGUs and/or from the aggregation of systematic flaws in bp’s reserves and resources estimation policies across the segment. 150 bp Annual Report and Form 20-F 2020 Financial statements We identified certain individual CGUs with a total carrying value of $32.1 billion which we determined would be most at risk of material impairment charges or reversals as a result of a plausible change in the key assumptions, particularly oil and gas price and discount rate assumptions. We also identified CGUs with a further $16.0 billion of combined carrying value which were less sensitive as they would be potentially at risk, in aggregate, to a material impairment or reversal by a plausible change in some or all of the key assumptions. Further information regarding these sensitivities is given in Note 1 on page 167. How the Critical Audit Matter was addressed in the Audit We tested management’s key internal controls over the estimation of oil and gas prices, discount rates and reserve and resources estimates, as well as key internal controls over the performance of the impairment assessments where we identified audit risks. In addition, we conducted the following substantive procedures. Oil and gas prices • We independently developed a reasonable range of forecasts based on external data obtained, against which we compared management’s oil and gas price assumptions in order to challenge whether they are reasonable. • In developing this range we obtained a variety of reputable and reliable third party forecasts, peer information and other relevant market data. • In challenging management's price assumptions, we considered the extent to which they and each of the forecast pricing scenarios obtained from third parties reflect the impact of lower oil and gas demand due to climate change, the energy transition and COVID-19. • We specifically analysed third party forecasts stated as being, or interpreted by us as being, consistent with achieving the Paris 2°C Goal and considered whether they presented contradictory audit evidence. • We challenged management’s disclosures in Notes 1 and 4 including in relation to the sensitivity of oil and gas price assumptions to reduced demand scenarios whether due to climate change or other reasons. Discount rates • We independently evaluated bp’s discount rates used in impairment tests with input from Deloitte valuation specialists, against relevant third party market and peer data. • We assessed whether specific country risks and tax adjustments were reasonably reflected in bp’s discount rates. • We challenged management’s disclosures in Notes 1 and 4 including in relation to the sensitivity of discount rate assumptions. Reserves and resources estimates With the assistance of Deloitte oil and gas reserves specialists we: • assessed bp’s reserves and resources estimation methods and policies; • assessed, guided by our risk assessment, how these policies had been applied to a sample of bp’s reserves and resources estimates which included those that we judged to represent the greatest risk of material misstatement; • read a sample of reports provided by management’s external reserves experts and assessed the scope of work and findings of these third parties; • assessed the competence, capability and objectivity of bp’s internal and external reserve experts; through understanding their relevant professional qualifications and experience. • compared the production forecasts used in the impairment tests with management’s approved reserves and resources estimates, those estimates having been subjected to the controls that we had tested; and • performed a retrospective assessment to check for indications of estimation bias over time Other procedures • We challenged management’s CGU determinations, and considered whether there was any contradictory evidence present. • We validated that bp’s impairment methodology was acceptable under IFRS and tested the integrity and mechanical accuracy of certain impairment models based on our risk assessment. • We challenged other CGU specific valuation input assumptions, including but not limited to material cost and tax forecasts, by comparing forecasts to approved internal and third party budgets, development plans, independent expectations and historical actuals. • Where relevant, we assessed management’s historical forecasting accuracy and whether the estimates had been determined and applied on a consistent basis across the group. 2. Intangible assets – Write-off of Exploration and Appraisal (E&A) assets, included within 'intangible assets' within the Group balance sheet – Notes 1, 8 and 15 to the financial statements Critical Audit Matter Description The group capitalises E&A expenditure on a project-by-project basis in line with IFRS 6 'Exploration for and Evaluation of Mineral Resources'. At 31 December 2020, $4.1 billion of E&A expenditure was carried on the group balance sheet. E&A activity carries inherent risk and a significant proportion of projects fail, requiring the write-off or impairment of the related capitalised costs when the relevant criteria in IFRS 6 and bp’s accounting policy are met. Furthermore, similar to upstream PP&E assets discussed above, E&A assets are also potentially exposed to climate change, the global energy transition, and COVID-19, in that a greater number of E&A projects may not proceed as a consequence of lower forecast future demand and oil and gas pricing, lower appetite by management and the board to allocate capital to certain projects, and/or increased objections from stakeholders to the development of certain projects. As a result of bp’s revised strategy announced in 2020, including a reduced capital frame, a net-zero carbon ambition and a decision not to explore in new countries, and reflecting lower oil and gas price assumptions, management identified IFRS 6 impairment indicators at a number of upstream’s largest E&A assets during the year. This led to management recording $9.9 billion of pre-tax E&A write-offs and impairments during 2020, detailed further in Notes 1 and 8 on pages 164 and 184. The determination of when E&A costs should be written off or impaired, or retained on the balance sheet as E&A assets, can be complex and require significant judgement from management in assessing this. There is a risk that certain capitalised E&A costs are written off or impaired when they bp Annual Report and Form 20-F 2020 151 should not have been, due to inappropriate and/or inconsistent application of IFRS 6 impairment criteria and bp’s accounting policy, leading to material misstatements. There is also a risk that E&A costs remain capitalised on the balance sheet which ought to have been written off or impaired, leading to material misstatements. We identified a critical audit matter for the individually material E&A write-offs recorded in 2020, specifically the Kaskida and Tigris (Paleogene) licenses that were the largest part of the $2.5 billion Gulf of Mexico write downs, the Terre de Grace oil sands project that was the largest part of the $2.5 billion Canada write downs and the three licenses that were the largest part of the $2.1 billion Brazil write-downs. We also identified higher risks in relation to certain other 2020 E&A write-offs and impairments recorded; and higher risks at certain assets within the $4.4 billion of E&A costs that remain capitalised under IFRS 6 at 31 December 2020. How the Critical Audit Matter was addressed in the Audit We obtained an understanding of the group’s E&A assessment processes and tested management’s key internal controls. This included the key internal controls operated by management for the key decisions taken as a result of bp’s new strategy, which when taken together with the lower forecast oil and gas prices, led to a large portion of the material write-offs and impairments recorded during 2020. We challenged management’s key E&A judgements, with regards to the impairment criteria of IFRS 6 and bp’s accounting policy. We corroborated key internal and external evidence relevant to significant write-offs and the assets that remained on the balance sheet. This included analysing evidence of future E&A plans, budgets and capital allocation decisions, assessing management’s key accounting judgement papers, holding discussions to challenge top level operational and finance management on the key judgements taken and reading meeting minutes, license documentation and evidence of active dialogue with partners and regulators including negotiations to renew licences or modify key terms, and external press releases. For E&A assets that were written off or impaired by management in 2020, including in particular those based upon decisions taken in line with management’s new strategy, we considered whether evidence (and potential contradictory evidence) about activity in the year, future budgeted expenditure and exploration/appraisal plans, including plans and expectations for licence relinquishment or retention, were consistent with the decisions taken by management to write-off or impair these assets. We assessed whether management had consistently applied IFRS 6 and bp’s accounting policy to impairment assessments, taking account of in year judgements and historical look back considerations, and the relevant facts and circumstances of specific E&A assets. When considering capital allocation decision making, we considered whether the progression of any projects that remain on the balance sheet would be inconsistent with elements of bp’s new strategy and in particular its net zero carbon commitments. 3. Accounting for structured commodity transactions (SCTs) within the trading and shipping (T&S) function and the valuation of other Level 3 financial instruments, where fraud risks may arise in revenue recognition (potentially impacting all financial statement accounts, in particular finance debt) - Notes 1, 20, 22, 29 and 30 to the financial statements Critical Audit Matter Description In the normal course of business, T&S enters into a variety of transactions for delivering value across the group’s supply chain. The nature of these transactions requires significant audit effort to be directed towards challenging management’s valuation estimates or the adopted accounting treatment. We have undertaken an analysis of the portfolio composition and revisited our risk assessment throughout the year focussing particularly on the impact of COVID-19 on the valuation assertion. This process has provided us with a deeper understanding of the impact of market volatility, demand destruction and the changing structure of the markets in which bp operates. Accounting for structured commodity transactions: T&S may also enter into a variety of transactions which we refer to as SCTs. We generally consider a SCT to be an arrangement having one of the following features: • Two or more counterparties with non-standard contractual terms; • Multiple commodity-based transactions; and/or • Contractual arrangements entered into in contemplation of each other. SCTs are often long-dated, can have a significant multi-year financial impact, and may require the use of complex valuation models or unobservable inputs when determining their fair value, in which case they will be classified as level 3 financial instruments under IFRS 13, ‘Fair Value Measurement’. Accounting for SCTs is typically complex and involves significant judgment, as these transactions often feature multiple elements that will have a material impact on the presentation and disclosure of these transactions in the financial statements and on key performance measures, including in particular the classification of liabilities as finance debt. Accordingly, we have identified the accounting for SCTs as a critical audit matter. Level 3 financial instruments: Unlike other financial instruments whose values or inputs are readily observable and therefore more easily independently corroborated, there are certain transactions for which the valuation is inherently more subjective due to the use of either complex valuation models and/or unobservable inputs. These instruments are classified as level 3 financial assets or liabilities. This degree of subjectivity also gives rise to a risk of potential fraud through management incorporating bias in determining fair values. Accordingly, we have identified these as a significant audit risk. As at 31 December 2020, the group’s total financial assets and liabilities measured at fair value were $12.7 billion and $8.4 billion, of which level 3 derivative financial assets were $6.4 billion and level 3 derivative financial liabilities were $5.3 billion. How the Critical Audit Matter was addressed in the Audit Accounting for SCTs For structured commodity transactions, we: • Tested controls related to the accounting for complex transactions. • Developed an understanding of the commercial rationale of the transactions through reading transaction documents and executed agreements, and discussions with management. • Performed a detailed accounting analysis for a sample of SCTs involving significant day one profits, deferred working capital arrangements, offtake arrangements and/or commitments. We confirmed that any day one profits were appropriately deferred. 152 bp Annual Report and Form 20-F 2020 Financial statements For SCTs which were identified during 2018 and 2019 and that continue through 2020, we have refreshed our assessment in 2020 taking account of any amendments to the contracts. To assess the appropriateness of the accounting treatment of SCTs, we embedded technical accounting specialists within the audit team. Level 3 financial instruments: To address the complexities associated with auditing the value of level 3 financial instruments, the engagement team included valuation specialists having significant quantitative and modelling expertise to assist in performing our audit procedures. Our valuation audit procedures included the following control and substantive procedures: • We tested the group’s valuation controls including the: – Model certification control, which is designed to review a model’s theoretical soundness and the appropriateness of its valuation methodology; and – Independent price verification control, which is designed to review the appropriateness of valuation inputs that are not observable and are significant to the financial instrument’s valuation. • We performed substantive valuation testing procedures at interim and year-end balance sheet date, including: – Comparing management’s input assumptions against the expected assumptions of other market participants and observable market data; – Evaluating management’s valuation methodologies against standard valuation practice and analysing whether a consistent framework is applied across the business period over period; and – Engaging a Deloitte valuations specialist to challenge models, develop fair value estimates and verify consistency in management’s modelling and input assumptions throughout the year. Our independent estimates were established using independently sourced inputs (where available). We evaluated whether the differences between our independent estimates and management’s estimates were within a reasonable range. In situations where we utilised management’s inputs, these were compared to external data sources to determine whether they were reasonable. /s/ Deloitte LLP London United Kingdom 22 March 2021 The first accounting period we audited was the 12 month period ended 31 December 2018. bp Annual Report and Form 20-F 2020 153 Consolidated financial statements of the bp group Report of Independent Registered Public Accounting Firm To the shareholders and board of directors of BP p.l.c. Opinion on internal control over financial reporting We have audited the internal control over financial reporting of BP p.l.c. and subsidiaries (the Company) as at 31 December 2020, based on the criteria established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting relating to internal control over financial reporting (UK FRC Guidance). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as at 31 December 2020, based on the criteria established in the UK FRC Guidance. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as at and for the year ended 31 December 2020, of the Company and our report dated 22 March 2021, expressed an unqualified opinion on those consolidated financial statements. Basis for opinion The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and limitations of internal control over financial reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ Deloitte LLP London, United Kingdom 22 March 2021 1. 2. The maintenance and integrity of the BP p.l.c. web site is the responsibility of BP p.l.c.; the work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements since they were initially presented on the web site. Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions. 154 bp Annual Report and Form 20-F 2020 Group income statement For the year ended 31 December Sales and other operating revenues Earnings from joint ventures – after interest and tax Earnings from associates – after interest and tax Interest and other income Gains on sale of businesses and fixed assets Total revenues and other income Purchases Production and manufacturing expenses Production and similar taxes Depreciation, depletion and amortization Impairment and losses on sale of businesses and fixed assets Exploration expense Distribution and administration expenses Profit (loss) before interest and taxation Finance costs Net finance expense relating to pensions and other post-retirement benefits Profit (loss) before taxation Taxation Profit (loss) for the year Attributable to bp shareholders Non-controlling interests Earnings per share Profit (loss) for the year attributable to bp shareholders Per ordinary share (cents) Basic Diluted Per ADS (dollars) Basic Diluted Financial statements Note 2020 2019 6 16 17 7 4 19 5 5 4 8 7 24 9 180,366 (302) (101) 663 2,874 183,500 132,104 22,494 695 14,889 14,381 10,280 10,397 (21,740) 3,115 33 (24,888) (4,159) (20,729) (20,305) (424) (20,729) $ million 2018 298,756 897 2,856 773 456 303,738 229,878 23,005 1,536 15,457 860 1,445 12,179 19,378 2,528 127 16,723 7,145 9,578 278,397 576 2,681 769 193 282,616 209,672 21,815 1,547 17,780 8,075 964 11,057 11,706 3,489 63 8,154 3,964 4,190 4,026 164 4,190 9,383 195 9,578 11 11 11 11 (100.42) (100.42) 19.84 19.73 (6.03) (6.03) 1.19 1.18 46.98 46.67 2.82 2.80 bp Annual Report and Form 20-F 2020 155 Group statement of comprehensive incomea For the year ended 31 December Profit (loss) for the year Other comprehensive income Items that may be reclassified subsequently to profit or loss Note 2020 (20,729) 2019 4,190 $ million 2018 9,578 Currency translation differences Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale (1,843) 1,538 (3,771) of businesses and fixed assets Cash flow hedges marked to market Cash flow hedges reclassified to the income statement Costs of hedging marked to market Costs of hedging reclassified to the income statement Share of items relating to equity-accounted entities, net of tax Income tax relating to items that may be reclassified Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Cash flow hedges that will subsequently be transferred to the balance sheet Income tax relating to items that will not be reclassified Other comprehensive income Total comprehensive income Attributable to bp shareholders Non-controlling interests a See Note 32 for further information. 30 30 30 30 16, 17 9 24 30 9 (353) 78 (37) 42 22 312 66 (1,713) 170 7 (105) 72 (1,641) (22,370) (21,983) (387) (22,370) 880 (100) 106 (4) 57 82 (70) 2,489 328 (3) (157) 168 2,657 6,847 6,674 173 6,847 — (126) 120 (244) 58 417 4 (3,542) 2,317 (37) (718) 1,562 (1,980) 7,598 7,444 154 7,598 156 bp Annual Report and Form 20-F 2020 Group statement of changes in equitya Financial statements Share capital and capital reserves Treasury shares Foreign currency translation reserve Non-controlling interests $ million Fair value reserves Profit and loss account bp shareholders' equity Hybrid bonds Other interest Total equity At 1 January 2020 Profit for the year Other comprehensive income Total comprehensive income Dividendsb Cash flow hedges transferred to the balance sheet, net of tax Repurchase of ordinary share capital Share-based payments, net of tax Share of equity-accounted entities’ changes in equity, net of tax Issue of perpetual hybrid bonds Payments on perpetual hybrid bonds Tax on issue of perpetual hybrid bonds Transactions involving non-controlling interests, net of tax At 31 December 2020 At 31 December 2018 Adjustment on adoption of IFRS 16, net of tax At 1 January 2019 Profit for the year Other comprehensive income Total comprehensive income Dividendsb Cash flow hedges transferred to the balance sheet, net of tax Repurchase of ordinary share capital Share-based payments, net of tax Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests, net of tax At 31 December 2019 At 31 December 2017 Adjustment on adoption of IFRS 9, net of tax At 1 January 2018 Profit for the year Other comprehensive income Total comprehensive income Dividendsb Cash flow hedges transferred to the balance sheet, net of tax Repurchase of ordinary share capital Share-based payments, net of tax Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests, net of tax At 31 December 2018 a See Note 32 for further information. b See Note 10 for further information. — 256 — 256 — — — — 2,296 100,708 (680) (20,729) (1,641) (643) (22,370) (6,605) (238) 37 — — — 6 (776) 726 46,525 (14,412) — — — — — — — — (6,495) — (2,224) (2,224) — (912) 73,706 — (20,305) 448 98 98 (19,857) (6,367) — 98,412 (20,305) (1,678) (21,983) (6,367) — (776) (638) 6 (776) 726 — — 176 — — 1,188 — — — — — — — — — — — — — — — 6 — — — — — — 1,341 1,341 — — 1,341 (48) — 3 (48) 11,909 (89) — — 3 — 11,861 (89) — 3 — — — — — (64) (64) — 827 763 46,701 (13,224) (8,719) (808) 47,300 71,250 12,076 2,242 85,568 46,352 — 46,352 — — — — (15,767) — (15,767) — — — — (8,902) — (8,902) — 2,407 2,407 — — (987) 78,748 (329) (987) 78,419 4,026 189 4,215 (6,929) — 52 52 — 99,444 (329) 99,115 4,026 2,648 6,674 (6,929) — — 173 — — 1,355 — — — 23 — — — 23 (1,511) (809) (1,511) 719 — — — — — — — — — — (1) 2,104 101,548 (330) 2,103 101,218 4,190 2,657 6,847 (7,142) 164 9 173 (213) — — — 23 (1,511) 719 — — — — 5 5 — — 5 — — — — 316 316 46,525 (14,412) (6,495) (912) 73,706 98,412 46,122 — 46,122 — — — — — (16,958) — (16,958) — — — — — (5,156) — (5,156) — (3,746) (3,746) — — (54) (743) 75,226 (126) (797) 75,100 9,383 — 2,023 (216) (216) 11,406 (6,699) — — 26 98,491 (180) 98,311 9,383 (1,939) 7,444 (6,699) 26 — — 230 1,191 — — — — (355) (718) (355) 703 — — — — — — — — — — — — 233 549 2,296 100,708 — 1,913 100,404 (180) 1,913 100,224 9,578 (1,980) 7,598 (6,869) 26 195 (41) 154 (170) — — — (355) 703 — — — — 14 14 — — 14 — — — — — — 46,352 (15,767) (8,902) (987) 78,748 99,444 — — 207 207 2,104 101,548 bp Annual Report and Form 20-F 2020 157 Group balance sheet At 31 December Non-current assets Property, plant and equipment Goodwill Intangible assets Investments in joint ventures Investments in associates Other investments Fixed assets Loans Trade and other receivables Derivative financial instruments Prepayments Deferred tax assets Defined benefit pension plan surpluses Current assets Loans Inventories Trade and other receivables Derivative financial instruments Prepayments Current tax receivable Other investments Cash and cash equivalents Assets classified as held for sale Total assets Current liabilities Trade and other payables Derivative financial instruments Accruals Lease liabilities Finance debt Current tax payable Provisions Liabilities directly associated with assets classified as held for sale Non-current liabilities Other payables Derivative financial instruments Accruals Lease liabilities Finance debt Deferred tax liabilities Provisions Defined benefit pension plan and other post-retirement benefit plan deficits Total liabilities Net assets Equity bp shareholders’ equity Non-controlling interests Total equity Helge Lund Chairman Bernard Looney Chief executive officer 22 March 2021 158 bp Annual Report and Form 20-F 2020 Note 2020 12 14 15 16 17 18 20 30 9 24 19 20 30 18 25 2 22 30 28 26 23 2 22 30 28 26 9 23 24 114,836 12,480 6,093 8,362 18,975 2,746 163,492 840 4,351 9,755 533 7,744 7,957 194,672 458 16,873 17,948 2,992 1,269 672 333 31,111 71,656 1,326 72,982 267,654 36,014 2,998 4,650 1,933 9,359 1,038 3,761 59,753 46 59,799 12,112 5,404 852 7,329 63,305 6,831 17,200 9,254 122,287 182,086 85,568 $ million 2019 132,642 11,868 15,539 9,991 20,334 1,276 191,650 630 2,147 6,314 781 4,560 7,053 213,135 339 20,880 24,442 4,153 857 1,282 169 22,472 74,594 7,465 82,059 295,194 46,829 3,261 5,066 2,067 10,487 2,039 2,453 72,202 1,393 73,595 12,626 5,537 996 7,655 57,237 9,750 18,498 8,592 120,891 194,486 100,708 32 32 32 71,250 14,318 85,568 98,412 2,296 100,708 Group cash flow statement For the year ended 31 December Operating activities Profit (loss) before taxation Adjustments to reconcile profit before taxation to net cash provided by operating activities Exploration expenditure written off Depreciation, depletion and amortization Impairment and (gain) loss on sale of businesses and fixed assets Earnings from joint ventures and associates Dividends received from joint ventures and associates Interest receivable Interest received Finance costs Interest paid Net finance expense relating to pensions and other post-retirement benefits Share-based payments Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans Net charge for provisions, less payments (Increase) decrease in inventories (Increase) decrease in other current and non-current assets Increase (decrease) in other current and non-current liabilities Income taxes paid Net cash provided by operating activities Investing activities Expenditure on property, plant and equipment, intangible and other assets Acquisitions, net of cash acquired Investment in joint ventures Investment in associates Total cash capital expenditure Proceeds from disposals of fixed assets Proceeds from disposals of businesses, net of cash disposed Proceeds from loan repayments Net cash used in investing activities Financing activities Repurchase of shares Lease liability payments Proceeds from long-term financing Repayments of long-term financing Net increase (decrease) in short-term debt Issue of perpetual hybrid bonds Payments on perpetual hybrid bonds Payments relating to transactions involving non-controlling interests (other) Receipts relating to transactions involving non-controlling interests (other) Dividends paid bp shareholders Non-controlling interests Net cash provided by (used in) financing activities Currency translation differences relating to cash and cash equivalents Increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of year Cash and cash equivalents at end of year Financial statements Note 2020 2019 $ million 2018 (24,888) 8,154 16,723 8 5 4 7 24 24 3 4 4 10 9,920 14,889 11,507 403 1,442 (258) 74 3,115 (2,728) 33 723 (282) 735 3,963 4,230 (8,278) (2,438) 12,162 (12,306) (44) (567) (1,138) (14,055) 491 4,989 717 (7,858) (776) (2,442) 14,736 (12,179) (1,234) 11,861 (89) (8) 665 (6,340) (238) 3,956 379 8,639 22,472 31,111 631 17,780 7,882 (3,257) 1,962 (441) 416 3,489 (2,870) 63 730 (238) (176) (3,406) (2,335) 2,823 (5,437) 25,770 (15,418) (3,562) (137) (304) (19,421) 500 1,701 246 (16,974) (1,511) (2,372) 8,597 (7,118) 180 — — — 566 (6,946) (213) (8,817) 25 4 22,468 22,472 1,085 15,457 404 (3,753) 1,535 (468) 348 2,528 (1,928) 127 690 (386) 986 672 (2,858) (2,577) (5,712) 22,873 (16,707) (6,986) (382) (1,013) (25,088) 940 1,911 666 (21,571) (355) (35) 9,038 (7,175) 1,317 — — — — (6,699) (170) (4,079) (330) (3,107) 25,575 22,468 bp Annual Report and Form 20-F 2020 159 Notes on financial statements 1. Significant accounting policies, judgements, estimates and assumptions Authorization of financial statements and statement of compliance with International Financial Reporting Standards The consolidated financial statements of BP p.l.c and its subsidiaries (collectively referred to as bp or the group) for the year ended 31 December 2020 were approved and signed by the chief executive officer and chairman on 22 March 2021 having been duly authorized to do so by the board of directors. BP p.l.c. is a public limited company incorporated and domiciled in England and Wales. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS adopted pursuant to Regulation (EC) No 1606/2002 as it applies in the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006 as applicable to companies reporting under international accounting standards. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB. The differences have no impact on the group’s consolidated financial statements for the years presented. As a result of the UK's withdrawal from the EU, with effect for periods starting subsequent to the year ended 31 December 2020, the consolidated financial statements will also be prepared in accordance with UK-adopted international accounting standards. There were no differences between IFRS as adopted by the EU and UK-adopted international accounting standards as at 1 January 2021. The UK’s withdrawal from the EU has not had and is not expected to have a significant impact on the consolidated financial statements. The significant accounting policies and accounting judgements, estimates and assumptions of the group are set out below. Basis of preparation The consolidated financial statements have been prepared on a going concern basis and in accordance with IFRS and IFRS Interpretations Committee (IFRIC) interpretations issued and effective for the year ended 31 December 2020. The accounting policies that follow have been consistently applied to all years presented, except where otherwise indicated. The consolidated financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where otherwise indicated. Significant accounting policies: use of judgements, estimates and assumptions Inherent in the application of many of the accounting policies used in preparing the consolidated financial statements is the need for bp management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and assumptions used. The accounting judgements and estimates that have a significant impact on the results of the group are set out in boxed text below, and should be read in conjunction with the information provided in the Notes on financial statements. The areas requiring the most significant judgement and estimation in the preparation of the consolidated financial statements are: accounting for the investment in Rosneft; exploration and appraisal intangible assets; the recoverability of asset carrying values, including the estimation of reserves; supplier financing arrangements; derivative financial instruments; provisions and contingencies; and pensions and other post-retirement benefits. Judgements and estimates, not all of which are significant, made in assessing the impact of the COVID-19 pandemic, and climate change and the transition to a lower carbon economy on the consolidated financial statements are also set out in boxed text below. Where an estimate has a significant risk of resulting in a material adjustment to the carrying amounts of assets and liabilities within the next financial year this is specifically noted within the boxed text. Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy Climate change and the transition to a lower carbon economy were considered in preparing the consolidated financial statements. These may have significant impacts on the currently reported amounts of the group’s assets and liabilities discussed below and on similar assets and liabilities that may be recognized in the future. Impairment of property, plant and equipment, and goodwill The energy transition is likely to impact the future prices of commodities such as oil and natural gas which in turn may affect the recoverable amount of property, plant and equipment, and goodwill in the oil and gas industry. Management’s best estimate of oil and natural gas price assumptions for value-in-use impairment testing were revised downwards during 2020 and the period covered extended to 2050. The revised assumptions sit within the range of external forecasts considered by management and are broadly in line with a range of transition paths consistent with the goals of the Paris climate change agreement. See significant judgements and estimates: recoverability of asset carrying values for further information including sensitivity analysis in relation to reasonably possible changes in the price assumptions. Impairments were recognized during 2020 on certain Upstream oil and gas properties as a result of the lower price assumptions. See note 4 for further information. No material impairments were recognized on Downstream assets. Though the energy transition may impact demand for certain refined products in the future, management anticipates sufficiently robust demand for the remainder of each refinery’s useful life. Headroom on goodwill balances was reduced, however the recoverable amount exceeds the carrying amount. See note 14 for further information including sensitivity analysis on the assumptions used to test goodwill for impairment. Management will continue to review price assumptions as the energy transition progresses and this may result in impairment charges or reversals in the future. Exploration and appraisal intangible assets The energy transition may affect the future development or viability of exploration prospects. The lower price assumptions and work to develop bp’s new strategy resulted in a review of the recoverability of exploration and appraisal intangible assets during 2020. Certain intangible assets were subsequently written-off. See significant judgement: exploration and appraisal intangible assets and note 8 for further information. The revised long-term price assumptions for investment appraisal (see page 28) help create a framework that seeks to help ensure that currently unsanctioned future capital expenditure on property plant and equipment, and exploration and appraisal intangibles, is aligned with bp’s new strategy. Property, plant and equipment – depreciation and expected useful lives The energy transition may curtail the expected useful lives of oil and gas industry assets thereby accelerating depreciation charges. However, the significant majority of bp’s existing Upstream oil and natural gas properties are likely to be fully depreciated within the next 10 years and, as outlined in bp's new strategy, oil and natural gas production will remain an important part of bp’s business activities over that period. Similarly, for Downstream refineries, demand for refined products is expected to remain strong over the remaining useful life of existing assets. 160 bp Annual Report and Form 20-F 2020 Financial statements 1. Significant accounting policies, judgements, estimates and assumptions – continued Therefore, management does not expect the useful lives of bp’s reported property, plant and equipment to change and do not consider this to be a significant accounting judgement or estimate. Significant capital expenditure is still required for ongoing projects and therefore the useful lives of future capital expenditure may, however, be different. See significant accounting policy: property, plant and equipment for more information. Provisions: decommissioning The energy transition may bring forward the decommissioning of oil and gas industry assets thereby increasing the present value of associated decommissioning provisions. The majority of bp’s Upstream oil and gas properties are expected to start decommissioning within the next two decades and management does not expect any reasonable change in the expected timeframe to have a material effect on the Upstream decommissioning provisions, assuming cash flows remain unchanged. Decommissioning cost estimates are based on the known regulatory and external environment. These cost estimates may change in the future, including as a result of the transition to a lower carbon economy. For Downstream refineries, decommissioning provisions are generally not recognized as the associated obligations have indeterminate settlement dates, typically driven by the cessation of manufacturing. Management will continue to review facts and circumstances to assess if decommissioning provisions need to be recognized. See significant judgements and estimates: provisions for further information. Judgements and estimates made in assessing the impact of the COVID-19 pandemic and the economic environment In preparing the consolidated financial statements, the following areas involving judgement and estimates were identified as most relevant with regards to the impact of the COVID-19 pandemic and current economic environment. Going concern Forecast liquidity has been assessed under a number of stressed scenarios, including a significant decline in oil prices over the 12-month period. Reverse stress tests performed indicated that the group will continue to operate as a going concern for at least 12 months from the date of approval of the consolidated financial statements even if the Brent price fell to zero. No material uncertainties over going concern or significant judgements or estimates in the assessment were identified. See also Note 29 Financial instruments and financial risk factors – Liquidity risk for further information. Discount rate assumptions The discount rates used for impairment testing and provisions were reassessed during the year in light of changing economic and geopolitical outlooks. The impact was determined not to be significant and the post-tax impairment discount rate and nominal provisions discount rate were unchanged from 2019. Pre-tax impairment discount rates and post-tax premiums for certain higher-risk countries were changed but this did not have a material impact. See significant judgements and estimates: recoverability of asset carrying values and provisions for further information. Oil and natural gas price assumptions The price assumptions used in value-in-use impairment testing were revised downwards during the year, in part due to lower demand for oil and natural gas. Material impairment charges and exploration write-offs were recognized in the Upstream segment as a consequence of these price assumption changes. See significant judgements and estimates: recoverability of asset carrying values and exploration and appraisal intangible assets for further information. Demand constraints for refined products during the year did not result in any material impairment charges on Downstream refinery assets. Pensions and other post-retirement benefits The volatility in the financial markets during 2020 impacted the assumptions used for determining the fair value of plan assets and the present value of defined benefit obligations in the group’s defined benefit pension plans. See significant estimate: pensions and other post-retirement benefits and note 24 for further information. Impairment of financial assets measured at amortized cost The current economic environment and future credit risk outlook were considered in updating the estimate of expected credit loss allowances on financial assets measured at amortized cost. Whilst credit risk increased relative to 31 December 2019, there was also a significant reduction in the group's trade and other receivables balance. Therefore, the total expected credit loss allowances recognized as at 31 December 2020 did not significantly increase. Management does not consider the calculation of expected credit loss allowances to be a significant accounting estimate. See note 21 and 29 for further information. Income taxes The carrying amounts of the group’s deferred tax assets were reviewed and updated to the extent that there are changes in the probability of sufficient taxable profits being available to utilize the reported deferred tax assets. Management does not consider the measurement of deferred tax assets to be a significant accounting estimate. See significant accounting policy: income taxes and Note 9 for further information. Basis of consolidation The consolidated group financial statements consolidate the financial statements of BP p.l.c. and its subsidiaries drawn up to 31 December each year. Subsidiaries are consolidated from the date of their acquisition, being the date on which the group obtains control, including when control is obtained via potential voting rights, and continue to be consolidated until the date that control ceases. The financial statements of subsidiaries are prepared for the same reporting year as the parent company, using consistent accounting policies. Intra-group balances and transactions, including unrealized profits arising from intra-group transactions, have been eliminated. Unrealized losses are eliminated unless the transaction provides evidence of an impairment of the asset transferred. Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to bp shareholders. Included within non-controlling interests are perpetual subordinated hybrid bonds issued by a subsidiary and for which the group has the unconditional right to avoid transferring cash or another financial asset to the bondholders. Profit or loss attributable to bp shareholders is adjusted to reflect the coupon related to these hybrid bonds whether or not such distribution has been deferred. Interests in other entities Business combinations and goodwill Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities assumed are recognized at their fair values at the acquisition date. Goodwill is initially measured as the excess of the aggregate of the consideration transferred, the amount recognized for any non-controlling interest and the acquisition-date fair values of any previously held interest in the acquiree over the fair value of the identifiable assets acquired and liabilities assumed at the acquisition date. The amount recognized for any non-controlling interest is measured at the present ownership's proportionate share in bp Annual Report and Form 20-F 2020 161 1. Significant accounting policies, judgements, estimates and assumptions – continued the recognized amounts of the acquiree’s identifiable net assets. At the acquisition date, any goodwill acquired is allocated to each of the cash- generating units, or groups of cash-generating units, expected to benefit from the combination’s synergies. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill arising on business combinations prior to 1 January 2003 is stated at the previous carrying amount under UK generally accepted accounting practice, less subsequent impairments. Goodwill may arise upon investments in joint ventures and associates, being the surplus of the cost of investment over the group’s share of the net fair value of the identifiable assets and liabilities. Any such goodwill is recorded within the corresponding investment in joint ventures and associates. Goodwill may also arise upon acquisition of interests in joint operations that meet the definition of a business. The amount of goodwill separately recognized is the excess of the consideration transferred over the group's share of the net fair value of the identifiable assets and liabilities. Interests in joint arrangements The results, assets and liabilities of joint ventures are incorporated in these consolidated financial statements using the equity method of accounting as described below. Certain of the group’s activities, particularly in the Upstream segment, are conducted through joint operations. bp recognizes, on a line-by-line basis in the consolidated financial statements, its share of the assets, liabilities and expenses of these joint operations incurred jointly with the other partners, along with the group’s income from the sale of its share of the output and any liabilities and expenses that the group has incurred in relation to the joint operation. Interests in associates The results, assets and liabilities of associates are incorporated in these consolidated financial statements using the equity method of accounting as described below. Significant judgement: investment in Rosneft Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. For bp, the judgement that the group has significant influence over Rosneft Oil Company (Rosneft), a Russian oil and gas company is significant. As a consequence of this judgement, bp uses the equity method of accounting for its investment and bp's share of Rosneft's oil and natural gas reserves is included in the group's estimated net proved reserves of equity-accounted entities. If significant influence was not present, the investment would be accounted for as an investment in an equity instrument measured at fair value as described under 'Financial assets' below and no share of Rosneft's oil and natural gas reserves would be reported. Significant influence is defined in IFRS as the power to participate in the financial and operating policy decisions of the investee but is not control or joint control of those policies. Significant influence is presumed when an entity owns 20% or more of the voting power of the investee. Significant influence is presumed not to be present when an entity owns less than 20% of the voting power of the investee. bp owns 19.75% of the voting shares of Rosneft. Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is wholly owned by the Russian government. At 31 December 2020, Rosneftegaz held 40.4% (2019 50% plus one share) of the voting shares of Rosneft . IFRS identifies several indicators that may provide evidence of significant influence, including representation on the board of directors of the investee and participation in policy-making processes. bp’s group chief executive, Bernard Looney, was approved as a member of the board of directors of Rosneft in June 2020 as one of bp’s two nominated directors. bp’s other nominated director, Bob Dudley, has been a member of the Rosneft board since 2013. He is also chairman of the Rosneft board’s Strategic and Sustainable Development Committee. bp also holds the voting rights at general meetings of shareholders conferred by its 19.75% stake in Rosneft. Transactions by Rosneft in its own shares during the year have increased bp’s economic interest in Rosneft to 22.03% (2019 19.75%). bp's management considers, therefore, that the group has significant influence over Rosneft, as defined by IFRS. The equity method of accounting Under the equity method, an investment is carried on the balance sheet at cost plus post-acquisition changes in the group’s share of net assets of the entity, less distributions received and less any impairment in value of the investment. Loans advanced to equity-accounted entities that have the characteristics of equity financing are also included in the investment on the group balance sheet. The group income statement reflects the group’s share of the results after tax of the equity-accounted entity, adjusted to account for depreciation, amortization and any impairment of the equity- accounted entity’s assets based on their fair values at the date of acquisition. The group statement of comprehensive income includes the group’s share of the equity-accounted entity’s other comprehensive income. The group’s share of amounts recognized directly in equity by an equity-accounted entity is recognized in the group’s statement of changes in equity. Financial statements of equity-accounted entities are prepared for the same reporting year as the group. Where material differences arise in the accounting policies used by the equity-accounted entity and those used by bp, adjustments are made to those financial statements to bring the accounting policies used into line with those of the group. Unrealized gains on transactions, apart from those that meet the definition of a derivative, between the group and its equity-accounted entities are eliminated to the extent of the group’s interest in the equity-accounted entity. The group assesses investments in equity-accounted entities for impairment whenever there is objective evidence that the investment is impaired. If any such objective evidence of impairment exists, the carrying amount of the investment is compared with its recoverable amount, being the higher of its fair value less costs of disposal and value in use. If the carrying amount exceeds the recoverable amount, the investment is written down to its recoverable amount. Segmental reporting The group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the group chief executive, bp’s chief operating decision maker, in deciding how to allocate resources and in assessing performance. The accounting policies of the operating segments are the same as the group’s accounting policies described in this note, except that IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker. For bp, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit before interest and tax. Replacement cost profit for the group is not a recognized measure under IFRS. For further information see Note 5. For information on changes to bp's segmental reporting see ‘Change in segmentation from 1 January 2021’ below. 162 bp Annual Report and Form 20-F 2020 Financial statements 1. Significant accounting policies, judgements, estimates and assumptions – continued Foreign currency translation In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency of those entities at the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included in the income statement, unless hedge accounting is applied. Non-monetary items, other than those measured at fair value, are not retranslated subsequent to initial recognition. In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, joint ventures, associates, and related goodwill, are translated into US dollars at the spot exchange rate on the balance sheet date. The results and cash flows of non-US dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars using average rates of exchange. In the consolidated financial statements, exchange adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars are recognized in a separate component of equity and reported in other comprehensive income. Exchange gains and losses arising on long-term intra-group foreign currency borrowings used to finance the group’s non- US dollar investments are also reported in other comprehensive income if the borrowings form part of the net investment in the subsidiary, joint venture or associate. On disposal or for certain partial disposals of a non-US dollar functional currency subsidiary, joint venture or associate, the related accumulated exchange gains and losses recognized in equity are reclassified from equity to the income statement. Non-current assets held for sale Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell. Significant non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets. Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale, and actions required to complete the plan of sale should indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. Property, plant and equipment and intangible assets are not depreciated or amortized once classified as held for sale. Intangible assets Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, computer software, patents, licences and trademarks and are stated at the amount initially recognized, less accumulated amortization and accumulated impairment losses. Intangible assets are carried initially at cost unless acquired as part of a business combination. Any such asset is measured at fair value at the date of the business combination and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights. Intangible assets with a finite life, other than capitalized exploration and appraisal costs as described below, are amortized on a straight-line basis over their expected useful lives. For patents, licences and trademarks, expected useful life is the shorter of the duration of the legal agreement and economic useful life, and can range from three to fifteen years. Computer software costs generally have a useful life of three to five years. The expected useful lives of assets and the amortization method are reviewed on an annual basis and, if necessary, changes in useful lives or the amortization method are accounted for prospectively. Oil and natural gas exploration, appraisal and development expenditure Oil and natural gas exploration, appraisal and development expenditure is accounted for using the principles of the successful efforts method of accounting as described below. Licence and property acquisition costs Exploration licence and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still under way or planned or that it has been determined, or work is under way to determine, that the discovery is economically viable based on a range of technical and commercial considerations, and sufficient progress is being made on establishing development plans and timing. If no future activity is planned, the remaining balance of the licence and property acquisition costs is written off. Lower value licences are pooled and amortized on a straight- line basis over the estimated period of exploration. Upon internal approval for development and recognition of proved or sanctioned probable reserves of oil and natural gas, the relevant expenditure is transferred to property, plant and equipment. Exploration and appraisal expenditure Geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are initially capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, rig costs and payments made to contractors. If potentially commercial quantities of hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an asset. If it is determined that development will not occur, that is, the efforts are not successful, then the costs are expensed. Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalized as an intangible asset. Upon internal approval for development and recognition of proved or sanctioned probable reserves, the relevant expenditure is transferred to property, plant and equipment. If development is not approved and no further activity is expected to occur, then the costs are expensed. The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within one year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover potentially economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. an offshore platform or a pipeline) would be required before production could begin, and where the economic viability of that major capital expenditure depends on the successful completion of further exploration or appraisal work in the area, remain capitalized on the balance sheet as long as such work is under way or firmly planned. bp Annual Report and Form 20-F 2020 163 1. Significant accounting policies, judgements, estimates and assumptions – continued Development expenditure Expenditure on the construction, installation and completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including service and unsuccessful development or delineation wells, is capitalized within property, plant and equipment and is depreciated from the commencement of production as described below in the accounting policy for property, plant and equipment. Significant judgement: exploration and appraisal intangible assets Judgement is required to determine whether it is appropriate to continue to carry costs associated with exploration wells and exploratory-type stratigraphic test wells on the balance sheet. This includes costs relating to exploration licences or leasehold property acquisitions. It is not unusual to have such costs remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and natural gas field is performed or while the optimum development plans and timing are established.The costs are carried based on the current regulatory and political environment or any known changes to that environment. All such carried costs are subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value from, the discovery. Where this is no longer the case, the costs are immediately expensed. As a result of the revised price assumptions detailed in Significant judgements and estimates: recoverability of asset carrying values below and a review of bp’s long-term strategic plan, management reviewed bp’s exploration prospects and the carrying value of the associated intangible assets. The outcome of the review resulted in revised judgements over management's expectations to extract value from certain prospects, thereby leading to material write-offs of the associated exploration and appraisal intangible assets in 2020. The carrying amount of capitalized costs and further information on the write-offs are included in Note 8. Property, plant and equipment Property, plant and equipment owned by the group is stated at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into the location and condition necessary for it to be capable of operating in the manner intended by management, the initial estimate of any decommissioning obligation, if applicable, and, for assets that necessarily take a substantial period of time to get ready for their intended use, directly attributable general or specific finance costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated with the item will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Inspection costs associated with major maintenance programmes are capitalized and amortized over the period to the next inspection. Overhaul costs for major maintenance programmes, and all other maintenance costs are expensed as incurred. Oil and natural gas properties, including certain related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is amortized over proved developed reserves. Licence acquisition, common facilities and future decommissioning costs are amortized over total proved reserves. The unit-of-production rate for the depreciation of common facilities takes into account expenditures incurred to date, together with estimated future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed through these common facilities. Information on the carrying amounts of the group’s oil and natural gas properties, together with the amounts recognized in the income statement as depreciation, depletion and amortization is contained in Note 12 and Note 5 respectively. Estimates of oil and natural gas reserves determined in accordance with US Securities and Exchange Commission (SEC) regulations, including the application of prices using 12-month historical price data in assessing the commerciality of technical volumes, are typically used to calculate depreciation, depletion and amortization charges for the group’s oil and gas properties. Therefore, where this approach is adopted, charges are not dependent on management forecasts of future oil and gas prices. However, for certain oil and natural gas assets, the use of reserves determined in accordance with SEC regulations would result in a charge that is not reflective of the pattern in which the future economic benefits are expected to be consumed. In these limited instances other approaches are applied to determine the reserves base used to calculate depreciation, depletion and amortization, including the use of management’s best estimate of price assumptions as disclosed in Significant judgements and estimates: recoverability of asset carrying values, to determine the commerciality of technical proved reserves. The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining carrying value of the asset over the expected future production. The estimation of oil and natural gas reserves and bp’s process to manage reserves bookings is described in Supplementary information on oil and natural gas on page 231, which is unaudited. Details on bp’s proved reserves and production compliance and governance processes are provided on page 312. The 2020 movements in proved reserves are reflected in the tables showing movements in oil and natural gas reserves by region in Supplementary information on oil and natural gas (unaudited) on page 231. Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life. The typical useful lives of the group’s other property, plant and equipment are as follows: Land improvements Buildings Refineries Petrochemicals plants Pipelines Service stations Office equipment Fixtures and fittings 15 to 25 years 20 to 50 years 20 to 30 years 20 to 30 years 10 to 50 years 15 years 3 to 10 years 5 to 15 years The expected useful lives and depreciation method of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives or the depreciation method are accounted for prospectively.An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in the period in which the item is derecognized. 164 bp Annual Report and Form 20-F 2020 Financial statements 1. Significant accounting policies, judgements, estimates and assumptions – continued Impairment of property, plant and equipment, intangible assets, and goodwill The group assesses assets or groups of assets, called cash-generating units (CGUs), for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or CGU may not be recoverable; for example, changes in the group’s business plans, plans to dispose rather than retain assets, changes in the group’s assumptions about commodity prices, low plant utilization, evidence of physical damage or, for oil and gas assets, significant downward revisions of estimated reserves or increases in estimated future development expenditure or decommissioning costs. If any such indication of impairment exists, the group makes an estimate of the asset’s or CGU’s recoverable amount. Individual assets are grouped into CGUs for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. A CGU’s recoverable amount is the higher of its fair value less costs of disposal and its value in use. If it is probable that the value of the CGU will be primarily recovered through a disposal transaction, the expected disposal proceeds are considered in determining the recoverable amount. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the determination of value in use. They contain forecasts for oil and natural gas production, refinery throughputs, sales volumes for various types of refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. Carbon taxes and costs of emissions allowances are included in estimates of future cash flows, where applicable, based on the regulatory environment in each jurisdiction in which the group operates. As an initial step in the preparation of these plans, various assumptions regarding market conditions, such as oil prices, natural gas prices, refining margins, refined product margins and cost inflation rates are set by senior management. These assumptions take account of existing prices, global supply-demand equilibrium for oil and natural gas, other macroeconomic factors and historical trends and variability. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset group that are not reflected in the discount rate and are discounted to their present value typically using a pre-tax discount rate that reflects current market assessments of the time value of money. Fair value less costs of disposal is the price that would be received to sell the asset in an orderly transaction between market participants and does not reflect the effects of factors that may be specific to the group and not applicable to entities in general. In limited circumstances where recent market transactions are not available for reference, discounted cash flow techniques are applied. Where discounted cash flow analyses are used to calculate fair value less costs of disposal, estimates are made about the assumptions market participants would use when pricing the asset, CGU or group of CGUs containing goodwill and the test is performed on a post-tax basis. An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to the lower of its recoverable amount and the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Impairment reversals are recognized in profit or loss. After a reversal, the depreciation charge is adjusted in future periods to allocate the asset’s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life. Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the group of CGUs to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of the group of CGUs to which goodwill has been allocated is compared with its recoverable amount. Where the recoverable amount of the group of CGUs is less than the carrying amount (including goodwill), an impairment loss is recognized. An impairment loss recognized for goodwill is not reversed in a subsequent period. bp Annual Report and Form 20-F 2020 165 1. Significant accounting policies, judgements, estimates and assumptions – continued Significant judgements and estimates: recoverability of asset carrying values Determination as to whether, and by how much, an asset, CGU, or group of CGUs containing goodwill is impaired involves management estimates on highly uncertain matters such as the effects of inflation and deflation on operating expenses, discount rates, capital expenditure, production profiles, reserves and resources, and future commodity prices, including the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas and refined products. Judgement is required when determining the appropriate grouping of assets into a CGU or the appropriate grouping of CGUs for impairment testing purposes. For example, individual oil and gas properties may form separate CGUs whilst certain oil and gas properties with shared infrastructure may be grouped together to form a single CGU. Alternative groupings of assets or CGUs may result in a different outcome from impairment testing. See Note 14 for details on how these groupings have been determined in relation to the impairment testing of goodwill. As described above, the recoverable amount of an asset is the higher of its value in use and its fair value less costs of disposal. Fair value less costs of disposal may be determined based on expected sales proceeds or similar recent market transaction data. Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts of assets are shown in Note 12, Note 14 and Note 15. The estimates for assumptions made in impairment tests in 2020 relating to discount rates and oil and gas properties are discussed below. Changes in the economic environment or other facts and circumstances may necessitate revisions to these assumptions and could result in a material change to the carrying values of the group's assets within the next financial year. Discount rates For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. Value-in-use calculations are typically discounted using a pre-tax discount rate based upon the cost of funding the group derived from an established model, adjusted to a pre-tax basis and incorporating a market participant capital structure and country risk premiums. Fair value less costs of disposal discounted cash flow calculations use the post-tax discount rate. The discount rates applied in impairment tests are reassessed each year and in 2020, the post-tax discount rate was 6% (2019 6%). Where the CGU is located in a country that was judged to be higher risk an additional premium of 1% to 3% was reflected in the post-tax discount rate (2019 1% to 4%). The judgement of classifying a country as higher risk and the applicable premium takes into account various economic and geopolitical factors. The pre-tax discount rate typically ranged from 7% to 15% (2019 7% to 13%) depending on the risk premium and applicable tax rate in the geographic location of the CGU. Oil and natural gas properties For Upstream oil and natural gas properties, expected future cash flows are estimated using management’s best estimate of future oil and natural gas prices, and production and reserves volumes. The estimated future level of production in all impairment tests is based on assumptions about future commodity prices, production and development costs, field decline rates, current fiscal regimes and other factors. In 2020, the group identified Upstream oil and gas properties with carrying amounts totalling $45,027 million (2019 $25,092 million) where the headroom, based on the most recent impairment test performed in the year on those assets, was less than or equal to 20% of the carrying value. A change in the discount rate, reserves, resources or the oil and gas price assumptions in the next financial year may result in a recoverable amount of one or more of these assets above or below the current carrying amount and therefore there is a risk of impairment reversals or charges in that period. Management considers that reasonably possible changes in the discount rate or forecast revenue, arising from a change in oil and natural gas prices and/or production could result in a material change in their carrying amounts within the next financial year,see Sensitivity analyses, below. The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and development expenditure above. Oil and natural gas prices The price assumptions used for value in use impairment testing are based on those used for investment appraisal. The investment appraisal price assumptions are recommended by the senior vice president economic & energy insights after considering a range of external prices, and supply and demand forecasts under various energy transition scenarios. They are reviewed and approved by management. As a result of the current uncertainty over the pace of transition to lower-carbon supply and demand and the social, political and environmental actions that will be taken to meet the goals of the Paris climate change agreement, the forecasts and scenarios considered include those where those goals are met as well as those where they are not met. bp sees the prospect of an enduring impact on the global economy as a result of the COVID-19 pandemic, with the potential for weaker demand for energy for a sustained period. bp’s management also expects that the aftermath of the pandemic will accelerate the pace of transition to a lower carbon economy and energy system as countries seek to ‘build back better’ so that their economies will be more resilient in the future. As a result of all the above, bp revised its price assumptions for value-in-use impairment testing, lowering them compared to those used in 2019 and extending the period covered to 2050. These price assumptions are derived from the central case investment appraisal assumptions (see page 28). A summary of the group’s revised price assumptions, in real 2020 terms, is provided below. The assumptions represent management’s best estimate of future prices, which sit within the range of external forecasts considered as appropriate for the purpose. They are considered by bp to be broadly in line with a range of transition paths consistent with the Paris climate goals. However, they do not correspond to any specific Paris-consistent scenario. An inflation rate of 2% (2019 2%) is applied to determine the price assumptions in nominal terms. Brent oil ($/bbl) Henry Hub gas ($/mmBtu) 2021 50 3.00 2025 50 3.00 2030 60 3.00 2040 60 3.00 2050 50 2.75 166 bp Annual Report and Form 20-F 2020 Financial statements 1. Significant accounting policies, judgements, estimates and assumptions – continued Material impairment charges were recognized in 2020 following the downward revision of the price assumptions. See Note 4 for further information. The long-term price assumptions used to determine recoverable amount based on value-in-use impairments tests in 2019 were $70 per barrel for Brent and $4 per mmBtu for Henry Hub gas, both in 2015 prices. These long-term prices were applied from 2025 and 2032 respectively inflated for the remaining life of the asset. The price assumptions used in 2019 over the periods to 2025 and 2032 were set such that there was a linear progression from our best estimate of 2020 prices to the long-term assumptions. The majority of bp’s reserves and resources that support the carrying value of the group’s existing oil and gas properties are expected to be produced over the next 10 years. Oil prices fell 35% in 2020 from 2019 due to trade tensions, a macroeconomic downturn and a slowdown in oil demand, reflecting the impact of the COVID-19 pandemic. OPEC+ production restraint, unplanned outages, and sanctions on Venezuela and Iran kept prices from falling further. bp's long- term assumption for oil prices is higher than the 2020 price average, based on the judgement that current price levels would not encourage sufficient investment to meet global oil demand sustainably in the longer term, especially given the financial requirements of key low-cost oil producing economies. US gas prices dropped by around 20% in 2020 compared to 2019. Henry Hub gas prices were already low in early 2020 due to mild weather. The drop in demand from the second quarter onward as a result of the COVID-19 pandemic as well as significant US LNG shut-ins contributed to prices remaining below $2/mmBtu during the second and third quarters, despite a record consumption in the power sector and the drop in natural gas production. Prices recovered in the fourth quarter due to the seasonal gas demand increase and the strong recovery in US LNG exports. bp's long- term price assumption for US gas reflects the fact that over the coming decades US gas production increases with an increasing proportion of production being used as feedstock to supply expanding LNG exports, while in the longer-term falling gas consumption and declining demand for global LNG exports leads to increasing competitive pressure on US gas production. Oil and natural gas reserves In addition to oil and natural gas prices, significant technical and commercial assessments are required to determine the group’s estimated oil and natural gas reserves. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of the group’s estimates of its oil and natural gas reserves. bp bases its reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements. Reserves assumptions for value-in-use tests reflect the reserves and resources that management currently intend to develop. The recoverable amount of oil and gas properties is determined using a combination of inputs including reserves, resources and production volumes. Risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved or probable. Sensitivity analyses A change in revenue from Upstream oil and gas properties can arise either due to changes in oil and natural gas prices, changes in oil and natural gas production, or a combination of the two. Management tested the impact of a change in revenue cash flows in value-in-use impairment testing arising from changes in price assumptions and/ or production volumes up to a combined effect on revenue of 10% in all future years. Revenue reductions of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of bp’s Upstream oil and gas properties in the range of $6-7 billion, which is approximately 5-6% of the net book value of property, plant and equipment as at 31 December 2020. Revenue increases of this magnitude in isolation could indicatively lead to an increase in the carrying amount of bp’s Upstream oil and gas properties in the range of $4-5 billion, which is approximately 3-4% of the net book value of property, plant and equipment as at 31 December 2020. This potential increase in the carrying amount would arise due to reversals of previously recognized impairments. These sensitivity analyses do not, however, represent management’s best estimate of any impairment charges or reversals that might be recognized as they do not fully incorporate consequential changes that may arise, such as changes in costs and business plans and phasing of development. For example, costs across the industry are more likely to decrease as oil and natural gas prices fall. The above sensitivity analyses therefore do not reflect a linear relationship between revenue and value that can be extrapolated. The interdependency of these inputs and risk factors plus the diverse characteristics of our Upstream oil and gas properties limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to the price assumptions or production volumes. Management also tested the impact of a one percentage point change in the discount rate used for value-in-use impairment testing of Upstream oil and gas properties. If the discount rate was one percentage point higher across all tests performed, the impairment charge recognized in 2020 would have been approximately $2.4 billion higher. If the discount rate was one percentage point lower, the impairment charge recognized would have been approximately $2.7 billion lower. Goodwill Irrespective of whether there is any indication of impairment, bp is required to test annually for impairment of goodwill acquired in business combinations. The group carries goodwill of approximately $12.5 billion on its balance sheet (2019 $11.9 billion), principally relating to the Atlantic Richfield, Burmah Castrol, Devon Energy and Reliance transactions. Sensitivities and additional information relating to impairment testing of goodwill in the Upstream segment are provided in Note 14. Inventories Inventories, other than inventories held for short-term trading purposes, are stated at the lower of cost and net realizable value. Cost is determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses. Net realizable value is determined by reference to prices existing at the balance sheet date, adjusted where the sale of inventories after the reporting period gives evidence about their net realizable value at the end of the period. Inventories held for short-term trading purposes are stated at fair value less costs to sell and any changes in fair value are recognized in the income statement. Supplies are valued at the lower of cost on a weighted average basis and net realizable value. bp Annual Report and Form 20-F 2020 167 1. Significant accounting policies, judgements, estimates and assumptions – continued Leases Agreements that convey the right to control the use of an identified asset for a period of time in exchange for consideration are accounted for as leases. The right to control is conveyed if bp has both the right to obtain substantially all of the economic benefits from, and the right to direct the use of, the identified asset throughout the period of use. An asset is identified if it is explicitly or implicitly specified by the agreement and any substitution rights held by the lessor over the asset are not considered substantive. Agreements that convey the right to control the use of an intangible asset including rights to explore for or use hydrocarbons are not accounted for as leases. See significant accounting policy: intangible assets. A lease liability is recognized on the balance sheet on the lease commencement date at the present value of future lease payments over the lease term. The discount rate applied is the rate implicit in the lease if readily determinable, otherwise an incremental borrowing rate is used. The incremental borrowing rate is determined based on factors such as the group’s cost of borrowing, lessee legal entity credit risk, currency and lease term. The lease term is the non-cancellable period of a lease together with any periods covered by an extension option that bp is reasonably certain to exercise, or periods covered by a termination option that bp is reasonably certain not to exercise. The future lease payments included in the present value calculation are any fixed payments, payments that vary depending on an index or rate, payments due for the reasonably certain exercise of options and expected residual value guarantee payments. Repayments of principal are presented as financing cash flows and payments of interest are presented as operating cash flows. Payments that vary based on factors other than an index or a rate such as usage, sales volumes or revenues are not included in the present value calculation and are recognized in the income statement and presented as operating cash flows. The lease liability is recognized on an amortized cost basis with interest expense recognized in the income statement over the lease term, except for where capitalized as exploration, appraisal or development expenditure. The right-of-use asset is recognized on the balance sheet as property, plant and equipment at a value equivalent to the initial measurement of the lease liability adjusted for lease prepayments, lease incentives, initial direct costs and any restoration obligations. The right-of-use asset is depreciated typically on a straight-line basis over the lease term. The depreciation charge is recognized in the income statement except for where capitalized as exploration, appraisal or development expenditure. Right-of-use assets are assessed for impairment in line with the accounting policy for impairment of property, plant and equipment, intangible assets and goodwill. Agreements may include both lease and non-lease components. Payments for lease and non-lease components are allocated on a relative stand-alone selling price basis except for leases of retail service stations where the group has elected not to separate non-lease payments from the calculation of the lease liability and right-of-use asset. If the lease term at commencement of the agreement is less than 12 months, a lease liability and right-of-use asset are not recognized, and a lease expense is recognized in the income statement on a straight-line basis. If a significant event or change in circumstances, within the control of bp, arises that affects the reasonably certain lease term or there are changes to the lease payments, the present value of the lease liability is remeasured using the revised term and payments, with the right-of-use asset adjusted by an equivalent amount. Modifications to a lease agreement beyond the original terms and conditions are accounted for as a re-measurement of the lease liability with a corresponding adjustment to the right-of-use asset. Any gain or loss on modification is recognized in the income statement. Modifications that increase the scope of the lease at a price commensurate with the stand-alone selling price are accounted for as a separate new lease. The group recognizes the full lease liability, rather than its working interest share, for leases entered into on behalf of a joint operation if the group has the primary responsibility for making the lease payments. This may be the case if for example bp, as operator of the joint operation, is the sole signatory to the lease. In such cases, bp’s working interest share of the right-of-use asset is recognized if it is jointly controlled by the group and the other joint operators, and a receivable is recognized for the share of the asset transferred to the other joint operators. If bp is a non-operator, a payable to the operator is recognized if they have the primary responsibility for making the lease payments and bp has joint control over the right-of-use asset, otherwise no balances are recognized. Financial assets Financial assets are recognized initially at fair value, normally being the transaction price. In the case of financial assets not measured at fair value through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their classification, as set out below. The group derecognizes financial assets when the contractual rights to the cash flows expire or the rights to receive cash flows have been transferred to a third party and either substantially all of the risks and rewards of the asset have been transferred, or substantially all the risks and rewards of the asset have neither been retained nor transferred but control of the asset has been transferred. This includes the derecognition of receivables for which discounting arrangements are entered into. The group classifies its financial asset debt instruments as measured at amortized cost, fair value through other comprehensive income or fair value through profit or loss. The classification depends on the business model for managing the financial assets and the contractual cash flow characteristics of the financial asset. Financial assets measured at amortized cost Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets are derecognized or impaired and when interest is recognized using the effective interest method. This category of financial assets includes trade and other receivables. Financial assets measured at fair value through other comprehensive income Financial assets are classified as measured at fair value through other comprehensive income when they are held in a business model the objective of which is both to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely payments of principal and interest. Financial assets measured at fair value through profit or loss Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at amortized cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category. 168 bp Annual Report and Form 20-F 2020 Financial statements 1. Significant accounting policies, judgements, estimates and assumptions – continued Investments in equity instruments Investments in equity instruments are subsequently measured at fair value through profit or loss unless an election is made on an instrument-by- instrument basis to recognise fair value gains and losses in other comprehensive income. Derivatives designated as hedging instruments in an effective hedge Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities. Cash equivalents Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets measured at amortized cost or, in the case of certain money market funds, fair value through profit or loss. Impairment of financial assets measured at amortized cost The group assesses on a forward-looking basis the expected credit losses associated with financial assets classified as measured at amortized cost at each balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is exposed to credit risk. As lifetime expected credit losses are recognized for trade receivables and the tenor of substantially all other in-scope financial assets is less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group. The measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit loss is estimated as the difference between the asset’s carrying amount and the present value of the future cash flows the group expects to receive discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain or loss recognized in the income statement. A financial asset or group of financial assets classified as measured at amortized cost is considered to be credit-impaired if there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due. Equity instruments Instruments are classified as either financial liabilities or as equity in accordance with the substance of the contractual arrangements. Instruments that cannot be settled in the group’s own equity instruments and that include no contractual obligation to deliver cash or another financial asset or to exchange financial assets or financial liabilities with another entity that are potentially unfavourable are classified as equity. Equity instruments issued by the group are recognized at the proceeds received, net of direct issue costs. Financial liabilities Financial liabilities are recognized when the group becomes party to the contractual provisions of the instrument. The group derecognizes financial liabilities when the obligation specified in the contract is discharged, cancelled or expired. The measurement of financial liabilities depends on their classification, as follows: Financial liabilities measured at fair value through profit or loss Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category. Derivatives designated as hedging instruments in an effective hedge Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities. Financial liabilities measured at amortized cost All other financial liabilities are initially recognized at fair value, net of directly attributable transaction costs. For interest-bearing loans and borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing. After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively. This category of financial liabilities includes trade and other payables and finance debt. Significant judgement: supplier financing arrangements The group’s trade payables include some supplier arrangements that utilize letter of credit facilities. Judgement is required to assesses the payables subject to these arrangements to determine whether they should continue to be classified as trade payables and give rise to operating cash flows or finance debt and financing cash flows. The criteria used in making this assessment include the payment terms for the amount due relative to terms commonly seen in the markets in which bp operates and whether the arrangements significantly change the nature of the liability. Liabilities subject to these arrangements with payment terms of up to approximately 60 days are generally considered to be trade payables and give rise to operating cash flows. See Note 29 - Liquidity risk for further information. Financial guarantees The group issues financial guarantee contracts to make specified payments to reimburse holders for losses incurred because certain associates, joint ventures or third-party entities fail to make payments when due in accordance with the original or modified terms of a debt instrument such as a loan. The liability for a financial guarantee contract is initially measured at fair value and subsequently measured at the higher of the contract’s estimated expected credit loss and the amount initially recognized less, where appropriate, cumulative amortization.   Derivative financial instruments and hedging activities The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and commodity prices, as well as for trading purposes. These derivative financial instruments are recognized initially at fair value on the date on which a derivative contract is entered into and subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative. bp Annual Report and Form 20-F 2020 169 1. Significant accounting policies, judgements, estimates and assumptions – continued Contracts to buy or sell a non-financial item (for example, oil, oil products, gas or power) that can be settled net in cash, with the exception of contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the group’s expected purchase, sale or usage requirements, are accounted for as financial instruments. Gains or losses arising from changes in the fair value of derivatives that are not designated as effective hedging instruments are recognized in the income statement. If, at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation methodology is not recognized in the income statement but is deferred on the balance sheet and is commonly known as a ‘day-one gain or loss’. This deferred gain or loss is recognized in the income statement over the life of the contract until substantially all the remaining contract term can be valued using observable market data at which point any remaining deferred gain or loss is recognized in the income statement. Changes in valuation subsequent to the initial valuation at inception of a contract are recognized immediately in the income statement. For the purpose of hedge accounting, hedges are classified as: • Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability. • Cash flow hedges when hedging exposure to variability in cash flows that is attributable to either a particular risk associated with a recognized asset or liability or a highly probable forecast transaction. Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for undertaking the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the existence at inception of an economic relationship and subsequent measurement of the hedging instrument's effectiveness in offsetting the exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged risk, the hedge ratio and sources of hedge ineffectiveness. Hedges meeting the criteria for hedge accounting are accounted for as follows: Fair value hedges The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the risk being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss, where it offsets. The group applies fair value hedge accounting when hedging interest rate risk and certain currency risks on fixed rate finance debt. Fair value hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This includes when the risk management objective changes or when the hedging instrument is sold, terminated or exercised. The accumulated adjustment to the carrying amount of a hedged item at such time is then amortized prospectively to profit or loss as finance interest expense over the hedged item's remaining period to maturity. Cash flow hedges The effective portion of the gain or loss on a cash flow hedging instrument is reported in other comprehensive income, while the ineffective portion is recognized in profit or loss. Amounts reported in other comprehensive income are reclassified to the income statement when the hedged transaction affects profit or loss. Where the hedged item is a highly probably forecast transaction that results in the recognition of a non-financial asset or liability, such as a forecast foreign currency transaction for the purchase of property, plant and equipment, the amounts recognized within other comprehensive income are transferred to the initial carrying amount of the non-financial asset or liability. Where the hedged item is an equity investment, the amounts recognized in other comprehensive income remain in the separate component of equity until the hedged cash flows affect profit or loss. Where the hedged item is recognized directly in profit or loss, the amounts recognized in other comprehensive income are reclassified to production and manufacturing expenses or sales and other operating revenues as appropriate. Cash flow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable to occur, or when the hedging instrument is sold, terminated or exercised without replacement or rollover. When cash flow hedge accounting is discontinued amounts previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to profit or loss or transferred to the initial carrying amount of a non-financial asset or liability as above. If the forecast transaction is no longer expected to occur, amounts previously recognized within other comprehensive income will be immediately reclassified to profit or loss. Costs of hedging The foreign currency basis spread of cross-currency interest rate swaps are excluded from hedge designations and accounted for as costs of hedging. Changes in fair value of the foreign currency basis spread are recognized in other comprehensive income to the extent that they relate to the hedged item. For time-period related hedged items, the amount recognized in other comprehensive income is amortized to profit or loss on a straight line basis over the term of the hedging relationship. Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The group categorizes assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed in their measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs that are observable, either directly or indirectly, other than quoted prices included within level 1 for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or bp’s assumptions about pricing by market participants. 170 bp Annual Report and Form 20-F 2020 Financial statements 1. Significant accounting policies, judgements, estimates and assumptions – continued Significant estimate and judgement: derivative financial instruments In some cases the fair values of derivatives are estimated using internal models due to the absence of quoted prices or other observable, market- corroborated data. This primarily applies to the group’s longer-term derivative contracts. The majority of these contracts are valued using models with inputs that include price curves for each of the different products that are built up from available active market pricing data (including volatility and correlation) and modelled using the maximum available external information. Additionally, where limited data exists for certain products, prices are determined using historical and long-term pricing relationships. The use of alternative assumptions or valuation methodologies may result in significantly different values for these derivatives. A reasonably possible change in the price assumptions used in the models relating to index price would not have a material impact on net assets and the Group income statement primarily as a result of offsetting movements between derivative assets and liabilities. For more information, including the carrying amounts of level 3 derivatives, see Note 30. In some cases, judgement is required to determine whether contracts to buy or sell commodities meet the definition of a derivative or to determine appropriate presentation and classification of transactions in certain cases. In particular contracts to buy and sell LNG are not considered to meet the definition as they are not considered capable of being net settled due to a lack of liquidity in the LNG market and the inability or lack of history of net settlement and so are accounted for on an accruals basis, rather than as a derivative. Offsetting of financial assets and liabilities Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met: the group currently has a legally enforceable right to set off the recognized amounts; and the group intends to either settle on a net basis or realize the asset and settle the liability simultaneously. A right of set off is the group’s legal right to settle an amount payable to a creditor by applying against it an amount receivable from the same counterparty. The relevant legal jurisdiction and laws applicable to the relationships between the parties are considered when assessing whether a current legally enforceable right to set off exists. Provisions and contingencies Provisions are recognized when the group has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk-free rate that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to the passage of time is recognized within finance costs. Provisions are discounted using a nominal discount rate of 2.5% (2019 2.5%). Provisions are split between amounts expected to be settled within 12 months of the balance sheet date (current) and amounts expected to be settled later (non-current). Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within the control of the group, or present obligations where it is not probable that an outflow of resources will be required or the amount of the obligation cannot be measured with sufficient reliability. Contingent liabilities are not recognized in the consolidated financial statements but are disclosed unless the possibility of an outflow of economic resources is considered remote. Decommissioning Liabilities for decommissioning costs are recognized when the group has an obligation to plug and abandon a well, dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Where an obligation exists for a new facility or item of plant, such as oil and natural gas production or transportation facilities, this liability will be recognized on construction or installation. Similarly, where an obligation exists for a well, this liability is recognized when it is drilled. An obligation for decommissioning may also crystallize during the period of operation of a well, facility or item of plant through a change in legislation or through a decision to terminate operations; an obligation may also arise in cases where an asset has been sold but the subsequent owner is no longer able to fulfil its decommissioning obligations, for example due to bankruptcy. The amount recognized is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. The provision for the costs of decommissioning wells, production facilities and pipelines at the end of their economic lives is estimated using existing technology, at future prices, depending on the expected timing of the activity, and discounted using the nominal discount rate. An amount equivalent to the decommissioning provision is recognized as part of the corresponding intangible asset (in the case of an exploration or appraisal well) or property, plant and equipment. The decommissioning portion of the property, plant and equipment is subsequently depreciated at the same rate as the rest of the asset. Other than the unwinding of discount on or utilisation of the provision, any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding asset where that asset is generating or is expected to generate future economic benefits. Environmental expenditures and liabilities Environmental expenditures that are required in order for the group to obtain future economic benefits from its assets are capitalized as part of those assets. Expenditures that relate to an existing condition caused by past operations that do not contribute to future earnings are expensed. Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Generally, the timing of recognition of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The amount recognized is the best estimate of the expenditure required to settle the obligation. Provisions for environmental liabilities have been estimated using existing technology, at future prices and discounted using a nominal discount rate. Emissions Liabilities for emissions are recognized when the cumulative volumes of gases emitted by the group at the end of the reporting period exceed the allowances granted free of charge held for own use or a set baseline for emissions. The provision is measured at the best estimate of the expenditure required to settle the present obligation at the balance sheet date. It is based on the excess of actual emissions over the free allowances held or set baseline in tonnes (or other appropriate quantity) and is valued at the actual cost of any allowances that have been purchased and held for own use on a first-in-first-out (FIFO) basis, and, if insufficient allowances are held, for the remaining requirement on the basis of the spot market price of allowances at the balance sheet date. The cost of allowances purchased to cover a shortfall is recognized separately on the balance sheet as an intangible asset unless the emission allowances acquired or generated by the group are risk-managed by the integrated supply and trading function, then they are recognized on the balance sheet as inventory. bp Annual Report and Form 20-F 2020 171 1. Significant accounting policies, judgements, estimates and assumptions – continued Restructuring provisions The reinvent bp programme, expected to reduce headcount by around 10,000 positions, has resulted in recognition of provisions where a detailed formal plan exists, and a valid expectation of risk of redundancy has been made to those affected but where the specific outcomes remain uncertain . Where formal redundancy offers have been made, the obligations for those amounts are reported as payables and, if not, as provisions if unpaid at the year-end. Significant judgements and estimates: provisions The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest decommissioning obligations facing bp relate to the plugging and abandonment of wells and the removal and disposal of oil and natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly changing, as are political, environmental, safety and public expectations. The timing and amounts of future cash flows are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognized. Any changes in the expected future costs are reflected in both the provision and the asset. If oil and natural gas production facilities and pipelines are sold to third parties, judgement is required to assess whether the new owner will be unable to meet their decommissioning obligations, whether bp would then be responsible for decommissioning, and if so the extent of that responsibility. The group has assessed that no material decommissioning provisions should be recognized as at 31 December 2020 (2019 no material provisions) for assets sold to third parties where the sale transferred the decommissioning obligation to the new owner. Decommissioning provisions associated with downstream refineries are generally not recognized, as the potential obligations cannot be measured, given their indeterminate settlement dates.Obligations may arise if refineries cease manufacturing operations and any such obligations would be recognized in the period when sufficient information becomes available to determine potential settlement dates. The group performs periodic reviews of its downstream refineries for any changes in facts and circumstances including those relating to the energy transition, that might require the recognition of a decommissioning provision. The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from current estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology. The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually. The interest rate used in discounting the cash flows is reviewed quarterly. The nominal interest rate used to determine the balance sheet obligations at the end of 2020 was 2.5% (2019 2.5%), which was based on long-dated US government bonds. The weighted average period over which decommissioning and environmental costs are generally expected to be incurred is estimated to be approximately 18 years (2019 18 years) and 6 years (2019 6 years) respectively. Costs at future prices are determined by applying an inflation rate of 1.5% (2019 1.5%) to decommissioning costs and 2% (2019 2%) for all other provisions. A lower rate is applied to decommissioning as certain costs are expected to remain fixed at current or past prices. Further information about the group’s provisions is provided in Note 23. Changes in assumptions in relation to the group's provisions could result in a material change in their carrying amounts within the next financial year. A 0.5 percentage point decrease in the nominal discount rate applied could increase the group’s provision balances by approximately $1.3 billion (2019 $1.4 billion). The pre-tax impact on the group income statement would be a charge of approximately $0.5 billion. The discounting impact on the group's Upstream decommissioning provisions of a two-year change in the timing of expected future decommissioning expenditures would not be material. Management currently does not consider a change of greater than two years to be reasonably possible in the next financial year. If all expected future decommissioning expenditures were 10% higher, the group's Upstream decommissioning provisions would increase by approximately $1.4 billion and a pre-tax charge of approximately $0.5 billion would be recognized. As described in Note 33, the group is subject to claims and actions for which no provisions have been recognized. The facts and circumstances relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized or revised. Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the outcome of litigation is difficult to predict. Employee benefits Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the balance sheet date are valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the award vests. The accounting policies for share-based payments and for pensions and other post-retirement benefits are described below. Share-based payments Equity-settled transactions The cost of equity-settled transactions with employees is measured by reference to the fair value of the equity instruments on the date on which they are granted and is recognized as an expense over the vesting period, which ends on the date on which the employees become fully entitled to the award. A corresponding credit is recognized within equity. Fair value is determined by using an appropriate, widely used, valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of the shares of the company (market conditions). Non-vesting conditions, such as the condition that employees contribute to a savings-related plan, are taken into account in the grant-date fair value, and failure to meet a non-vesting condition, where this is within the control of the employee is treated as a cancellation and any remaining unrecognized cost is expensed. For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are measured at the fair value of the goods or services received unless their fair value cannot be reliably estimated. If the fair value of the goods and services received cannot be reliably estimated, the transaction is measured by reference to the fair value of the equity instruments granted. 172 bp Annual Report and Form 20-F 2020 Financial statements 1. Significant accounting policies, judgements, estimates and assumptions – continued Cash-settled transactions The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the corresponding liability which is recognized on the balance sheet. The liability is remeasured at fair value at each balance sheet date until settlement, with changes in fair value recognized in the income statement. Pensions and other post-retirement benefits The cost of providing benefits under the group’s defined benefit plans is determined separately for each plan using the projected unit credit method, which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to determine the present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company becomes committed to a change. Net interest expense relating to pensions and other post-retirement benefits, which is recognized in the income statement, represents the net change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking into account expected changes in the obligation or plan assets during the year. Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not subsequently reclassified to profit and loss. The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the present value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, either by way of a refund from the plan or reductions in future contributions to the plan. Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable. Significant estimate: pensions and other post-retirement benefits Accounting for defined benefit pensions and other post-retirement benefits involves making significant estimates when measuring the group's pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties. Pensions and other post-retirement benefit assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group's balance sheet, and pension and other post-retirement benefit expense for the following year. The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate, salary growth and mortality levels. Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in material changes to the carrying amounts of the group's pension and other post-retirement benefit obligations within the next financial year, in particular for the UK, US and Eurozone plans. Any differences between these assumptions and the actual outcome will also affect future net income and net assets. The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and obligation used are provided in Note 24. Income taxes Income tax expense represents the sum of current tax and deferred tax. Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity. Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are taxable or deductible in other periods as well as items that are never taxable or deductible. The group’s liability for current tax is calculated using tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for all taxable temporary differences except: • Where the deferred tax liability arises on the initial recognition of goodwill. • Where the deferred tax liability arises on the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss. • In respect of taxable temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements, where the group is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred tax assets are recognized for deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits and unused tax losses can be utilized, except where the deferred tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss. In respect of deductible temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized. The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable or increased to the extent that it is probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized. bp Annual Report and Form 20-F 2020 173 1. Significant accounting policies, judgements, estimates and assumptions – continued Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and liabilities are not discounted. Deferred tax assets and liabilities are offset only when there is a legally enforceable right to set off current tax assets against current tax liabilities and when the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the current tax assets and liabilities on a net basis or to realize the assets and settle the liabilities simultaneously. Where tax treatments are uncertain, if it is considered probable that a taxation authority will accept the group's proposed tax treatment, income taxes are recognized consistent with the group's income tax filings. If it is not considered probable, the uncertainty is reflected within the carrying amount of the applicable tax asset or liability using either the most likely amount or an expected value, depending on which method better predicts the resolution of the uncertainty. The computation of the group’s income tax expense and liability involves the interpretation of applicable tax laws and regulations in many jurisdictions throughout the world. The resolution of tax positions taken by the group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Therefore, judgement is required to determine whether provisions for income taxes are required and, if so, estimation is required of the amounts that could be payable. In addition, the group has carry-forward tax losses and tax credits in certain taxing jurisdictions that are available to offset against future taxable profit. However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused tax losses or tax credits can be utilized. Management judgement is exercised in assessing whether this is the case and estimates are required to be made of the amount of future taxable profits that will be available.Such judgements are inherently impacted by estimates affecting future taxable profits such as oil and natural gas prices and decommissioning expenditure, see significant judgements and estimates: recoverability of asset carrying values and provisions Management do not assess there to be a significant risk of a material change to the group’s tax provisioning or recognition of deferred tax assets within the next financial year, however the tax position remains inherently uncertain and therefore subject to change. To the extent that actual outcomes differ from management’s estimates, income tax charges or credits, and changes in current and deferred tax assets or liabilities, may arise in future periods. For more information see Note 9 and Note 33. Judgement is also required when determining whether a particular tax is an income tax or another type of tax (for example a production tax). Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes; rather such taxes are recognized in the income statement in accordance with the applicable accounting policy such as Provisions and contingencies. No new significant judgements were made in 2020 in this regard. Customs duties and sales taxes Customs duties and sales taxes that are passed on or charged to customers are excluded from revenues and expenses. Assets and liabilities are recognized net of the amount of customs duties or sales tax except: • Customs duties or sales taxes incurred on the purchase of goods and services which are not recoverable from the taxation authority are recognized as part of the cost of acquisition of the asset. • Receivables and payables are stated with the amount of customs duty or sales tax included. The net amount of sales tax recoverable from, or payable to, the taxation authority is included within receivables or payables in the balance sheet. Own equity instruments – treasury shares The group’s holdings in its own equity instruments are shown as deductions from shareholders’ equity. Treasury shares represent bp shares repurchased and available for specific and limited purposes. For accounting purposes, shares held in Employee Share Ownership Plans (ESOPs) to meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are, therefore, included in the consolidated financial statements as treasury shares. The cost of treasury shares subsequently sold or reissued is calculated on a weighted-average basis. Consideration, if any, received for the sale of such shares is also recognized in equity. No gain or loss is recognized in the income statement on the purchase, sale, issue or cancellation of equity shares. Shares repurchased under the share buy-back programme which are immediately cancelled are not shown as treasury shares, but are shown as a deduction from the profit and loss account reserve in the group statement of changes in equity. Revenue and other income Revenue from contracts with customers is recognized when or as the group satisfies a performance obligation by transferring control of a promised good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products, and other items usually coincides with title passing to the customer and the customer taking physical possession. The group principally satisfies its performance obligations at a point in time; the amounts of revenue recognized relating to performance obligations satisfied over time are not significant. When, or as, a performance obligation is satisfied, the group recognizes as revenue the amount of the transaction price that is allocated to that performance obligation. The transaction price is the amount of consideration to which the group expects to be entitled. The transaction price is allocated to the performance obligations in the contract based on standalone selling prices of the goods or services promised. Contracts for the sale of commodities are typically priced by reference to quoted prices. Revenue from term commodity contracts is recognized based on the contractual pricing provisions for each delivery. Certain of these contracts have pricing terms based on prices at a point in time after delivery has been made. Revenue from such contracts is initially recognized based on relevant prices at the time of delivery and subsequently adjusted as appropriate. All revenue from these contracts, both that recognized at the time of delivery and that from post-delivery price adjustments, is disclosed as revenue from contracts with customers. Certain forward contracts entered into by the group that result in physical delivery of products such as crude oil, natural gas and refined products are required to be accounted for as derivative financial instruments. Revenue recognized relating to such contracts when physical delivery occurs is measured at the contractual transaction price plus the carrying amount of the related derivative at the date of settlement and presented as other operating revenues. Changes in the fair value of derivative assets and liabilities prior to physical delivery are also classified as other operating revenues. See also Other significant accounting policy changes - IFRIC agenda decision on IFRS 9 'Financial instruments' below. 174 bp Annual Report and Form 20-F 2020 Financial statements 1. Significant accounting policies, judgements, estimates and assumptions – continued Where forward sale and purchase contracts for oil, natural gas or power have been determined to be for short-term trading purposes, the associated sales and purchases are reported net within sales and other operating revenues whether or not physical delivery has occurred. Physical exchanges with counterparties in the same line of business in order to facilitate sales to customers are reported net, as are sales and purchases made with a common counterparty, as part of an arrangement similar to a physical exchange. Where the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is recognized but no purchase or sale is recorded. Interest income is recognized as the interest accrues (using the effective interest rate, that is, the rate that exactly discounts estimated future cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset). Dividend income from investments is recognized when the shareholders’ right to receive the payment is established. Contract asset and contract liability balances are included within amounts presented for trade receivables and other payables respectively. Finance costs Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are substantially ready for their intended use. All other finance costs are recognized in the income statement in the period in which they are incurred. Updates to significant accounting policies Impact of new International Financial Reporting Standards bp adopted ‘Interest Rate Benchmark Reform – Phase I – Amendments to IFRS 9 ‘Financial instruments’ and IFRS 7 ‘Financial instruments: Disclosures’’ with effect from 1 January 2020. There are no other new or amended standards or interpretations adopted during the year that have a significant impact on the consolidated financial statements. 'Interest Rate Benchmark Reform – Phase I’ Financial authorities in the US, UK, EU and other territories are currently undertaking reviews of key interest rate benchmarks such as the London Inter- bank Offered Rate (LIBOR) with a view to replacing them with alternative benchmarks. Uncertainty around the method and timing of transition from Inter-bank Offered Rates (IBORs) to alternative risk-free rates (RfRs) may impact the assessment of whether hedge accounting can be applied to certain hedging relationships. This first phase of amendments to IFRS 9 provide temporary relief from applying specific hedge accounting requirements to hedging relationships directly affected by interest rate benchmark reforms. In accordance with the transition provisions, the amendments have been adopted retrospectively to hedging relationships that existed at the start of the current reporting period and have been applied to new hedging relationships designated after that date. The reliefs have meant that the uncertainty over the interest rate benchmark reforms has not resulted in discontinuation of hedge accounting for any of bp’s fair value hedges. See Note 29 Financial instruments and financial risk factors - interest rate risk and Note 30 Derivative financial instruments - Fair value hedges for further information. Impact of new International Financial Reporting Standards - Not yet adopted The following pronouncements from the IASB have not been adopted by the group in these financial statements as they will only become effective for future financial reporting periods. There are no other standards, amendments or interpretations in issue but not yet adopted that the directors anticipate will have a material effect on the reported income or net assets of the group. IFRS 17 ' Insurance Contracts' IFRS 17 'Insurance Contracts' provides a new general model for accounting for contracts where the issuer accepts significant insurance risk from another party and agrees to compensate that party if a future uncertain event adversely affects them. IFRS 17 replaces IFRS 4 'Insurance Contracts' and will be effective for bp for the financial reporting period commencing 1 January 2023. The standard has not yet been endorsed by the UK and the EU. bp's assessment of the impact of IFRS 17 is at an initial stage but it is not expected to have a significant effect on future financial reporting. ‘Interest Rate Benchmark Reform – Phase II’ Amendments to IFRS 9, IFRS 7, IFRS 4 and IFRS 16 ‘Leases’ were issued by the IASB in August 2020 to provide practical expedients and reliefs in relation to modifications of financial instruments and leases that arise from transition from IBORs to RFRs. Phase II also provides further reliefs to hedge accounting requirements. These amendments were effective for bp from 1 January 2021. The amendments have been endorsed by the UK and by the EU. bp’s working group on interest rate benchmark reform is monitoring and managing the transition to alternative benchmark rates and is currently assessing the impact on contracts and arrangements that are linked to existing interest rate benchmarks for example, borrowings, leases and derivative contracts. bp is also participating on external committees and task forces dedicated to interest rate benchmark reform. Other changes to significant accounting policies Physically settled derivative contracts In March 2019, IFRIC issued an agenda decision on the application of IFRS 9 to the physical settlement of contracts to buy or sell a non-financial item, such as commodities, that are not accounted for as 'own-use' contracts. IFRIC concluded that such contracts are settled by the delivery or receipt of a non-financial item in exchange for both cash and the settlement of the derivative asset or liability. bp routinely enters into transactions for the sale and purchase of commodities that are physically settled and meet the definition of a derivative financial instrument. As described in the group's accounting policy for revenue in bp Annual Report and Form 20-F 2019, revenue recognized at the time such contracts were physically settled was measured at the contractual transaction price and was presented together with revenue from contracts with customers in those financial statements. bp Annual Report and Form 20-F 2020 175 1. Significant accounting policies, judgements, estimates and assumptions – continued bp changed its accounting policy for these contracts, in accordance with the conclusions included in the agenda decision, with effect from 1 April 2020, as follows: • Revenues and purchases from such contracts are measured at the contractual transaction price plus the carrying amount of the related derivative at the date of settlement. Realized derivative gains and losses on physically settled derivative contracts are included in other revenues. • There is no significant effect on current period or comparative information for ‘Sales and other operating revenues’ and ‘Purchases’ as presented in the group income statement, therefore no comparative information has been re-stated. • There is no significant effect on net assets or on comparative information for ‘Profit before taxation’ or ‘Profit after taxation’ as presented in the group income statement. In addition, bp chose to change its presentation of revenues from physically settled derivative sales contracts from 1 January 2020. Revenues from physically settled derivative sales contracts are no longer presented together with revenue from contracts with customers. In these financial statements they are now presented as other revenues. Comparative information in Note 6 for revenue from contracts with customers and other revenues have been re-presented to align with the current period as set out below. 2019 (previously reported) 2019 (re- presented – see note 6) Presentational adjustments 2018 (previously reported) 2018 (re- presented – see note 6) Presentational adjustments $ million Crude oil Oil products Natural gas, LNG and NGLs Non-oil products and other revenues from contracts with customers Revenue from contracts with customers Other operating revenues Total sales and other operating revenues 62,130 20,167 13,254 9,141 180,528 102,408 18,909 12,169 54,945 86,951 1,251 1,279 276,079 142,627 133,452 296,255 151,829 144,426 (144,426) — 10,331 65,276 52,989 78,120 195,466 108,515 20,494 21,745 12,489 13,768 2,501 146,927 — 298,756 298,756 2,318 135,770 278,397 278,397 1,258 1,085 (133,452) Voluntary changes to significant accounting policies - not yet adopted Net presentation of revenues and purchases relating to physically settled derivative contracts from 1 January 2021 As described above, bp routinely enters into transactions for the sale and purchase of commodities that are physically settled and meet the definition of a derivative financial instrument. These contracts are within the scope of IFRS 9 and as such, prior to settlement, changes in the fair value of these derivative contracts are presented as gains and losses within other operating revenues. The group currently presents revenues and purchases for such contracts on a gross basis in the group income statement upon physical settlement. These transactions have historically represented a substantial portion of the revenues and purchases reported in the group’s consolidated financial statements. The change in strategic direction of the group supported by organisational changes to implement the strategy from 1 January 2021, results in the group determining that the revenue and corresponding purchases relating to such transactions should be presented net as gains or losses within other operating revenues. Additionally the group’s trading activity has continued to evolve over time from one of capturing third party physical trades to provide flow assurance to one with increasing levels of optimisation, taking advantage of price volatility and fluctuations in demand and supply, which will continue under the new strategy, further supporting the change in presentation. The new presentation provides reliable and more relevant information for users of the accounts as the group’s revenue recognition will be more closely aligned with its assessment of ‘Scope 3’ emissions from its products, its ‘Net Zero’ ambition and how management monitors and manages performance of such contracts. Comparative information for Sales and other operating revenues and purchases for 2019 and 2020 will be restated and will be presented under the new policy alongside group’s 2021 financial information. Change in segmentation During the first quarter of 2021, the group's reportable segments changed consistent with a change in the way that resources are allocated and performance is assessed by the chief operating decision maker, who for bp is the group chief executive, from that date. From the first quarter of 2021, the group's reportable are gas & low carbon energy, oil production & operations, customers & products, and Rosneft. At 31 December 2020, the group's reportable segments were Upstream, Downstream and Rosneft. Gas & low carbon energy comprises regions with upstream businesses that predominantly produce natural gas, gas trading activities and the group's renewables businesses, including biofuels, solar and wind. Gas producing regions were previously in the Upstream segment. The group's renewables businesses were previously part of 'Other businesses and corporate'. Oil production & operations comprises regions with upstream activities that predominantly produce crude oil. These activities were previously in the Upstream segment. Customers & products comprises the group's convenience and mobility business, which manages the sale of fuels to wholesale and retail customers, convenience products, aviation fuels, and Castrol lubricants; and refining, supply and trading. The petrochemicals business will also be reported in restated comparative information as part of the customers and products segment up to its sale in December 2020. The customers & products segment is, therefore, substantially unchanged from the former Downstream segment with the exception of the Petrochemicals disposal. The Rosneft segment is unchanged and continues to include equity-accounted earnings from the group's investment in Rosneft. The segment measure of profit or loss continues to be replacement cost profit or loss before interest and tax, which reflects the replacement cost of supplies by excluding from profit or loss before interest and tax inventory holding gains and losses. See Note 5 for further information. In the group's financial reporting for 2021, comparative information for 2019 and 2020 will be restated to reflect the changes in reportable segments. Reporting under the new segment structure will begin with the first quarter 2021 interim financial statements. Segmental information presented in these financial statements is based on the segment structure as at 31 December 2020. 176 bp Annual Report and Form 20-F 2020 Financial statements 2. Non-current assets held for sale The carrying amount of assets classified as held for sale at 31 December 2020 is $1,326 million (2019 $7,465 million), with associated liabilities of $46 million (2019 $1,393 million). Upstream segment The balance consists primarily of a 20% participating interest from bp’s 60% participating interest in Block 61 in Oman. As announced on 1 February 2021, bp has agreed to sell this interest to PTT Exploration and Production Public Company Limited of Thailand for a total consideration of up to $2.6 billion, subject to final adjustments. Under the terms of the agreement, bp will receive $2,450 million on completion, with up to an additional $140 million receivable contingent on pre-agreed future conditions. Subject to approvals, the transaction is expected to complete during 2021. Assets of $1,298 million and associated liabilities of $10 million have been classified as held for sale in the group balance sheet at 31 December 2020. Transactions that have been classified as held for sale during 2020, but were completed by 31 December 2020, are described below. Downstream segment On 29 June 2020 bp announced that it had agreed to sell its global petrochemicals business to INEOS for a total consideration of $5 billion, subject to customary closing adjustments. The assets and liabilities of the business were classified as held for sale from that date until the disposal completed on 31 December 2020. Under the terms of the agreement, INEOS paid bp a deposit of $400 million and a further $3.6 billion on completion less $0.1 billion of third-party indebtedness remaining in petrochemicals on completion. The remaining $1 billion was received in February 2021. The business had interests in manufacturing plants in Asia, Europe and the US, including interests held in equity-accounted entities. See note 4 for further information. Upstream segment On 27 August 2019, bp announced that it had agreed to sell its Alaska operations and interests to Hilcorp Energy for up to $5.6 billion, subject to customary closing adjustments. The sale included bp’s upstream and midstream business in the state, including BP Exploration (Alaska) Inc., which owned all of bp’s upstream oil and gas interests in Alaska, and BP Pipelines (Alaska) Inc.’s 49% interest in the Trans Alaska Pipeline System (TAPS). These assets and associated liabilities were classified as held for sale in the 31 December 2019 group balance sheet. The disposal of BP Exploration (Alaska) Inc. completed on 30 June 2020. The disposal of TAPS completed on 18 December 2020. bp received $800 million prior to or on completion of the disposals and has recognized a loan note with a principal amount of $2,100 million receivable from Hilcorp. The group has also recognized other assets totalling $1,722 million as at 31 December 2020, principally in relation to the ‘earn-out’ provisions of the agreement. See note 4 for information on impairment charges relating to the Alaska business. bp retained decommissioning liability relating to the TAPS, which will be partially offset by a 30% cost reimbursement from Hilcorp when incurred. In November 2019, bp agreed to sell its interests in the San Juan basin in Colorado and New Mexico to IKAV. These assets and associated liabilities were classified as held for sale in the 31 December 2019 group balance sheet. The transaction completed on 28 February 2020. The total assets and liabilities held for sale at 31 December 2020 and 2019, which are all in the Upstream segment, are set out in the table below. Property, plant and equipment Goodwill Intangible assets Investments in associates Inventories Trade and other receivables Assets classified as held for sale Trade and other payables Lease liabilities Provisions Defined benefit pension plan and other post-retirement benefit plan deficits Liabilities directly associated with assets classified as held for sale 3. Business combinations and other significant transactions Business combinations 2020 2020 1,099 199 — — — 28 1,326 (36) — (10) — (46) $ million 2019 6,359 — 610 43 318 135 7,465 (33) (280) (1,012) (68) (1,393) The group undertook a number of business combinations during 2020. The fair value of the net assets (including goodwill) and non-controlling interests recognized were $617 million and $574 million, respectively. These principally related to an acquisition in our US Fuels business. 2019 As agreed as part of the original transaction, $3,480 million was paid in 2019 in respect of the 2018 acquisition of Petrohawk Energy Corporation from BHP Billiton. A number of other individually insignificant business combinations were also undertaken by bp in 2019. bp Annual Report and Form 20-F 2020 177 4. Disposals and impairment The following amounts were recognized in the income statement in respect of disposals and impairments. Gains on sale of businesses and fixed assets Upstream Downstream Other businesses and corporate Losses on sale of businesses and fixed assets, and closures Upstream Downstream Other businesses and corporate Impairment losses Upstream Downstream Other businesses and corporate Impairment reversals Upstream Downstream Other businesses and corporate Impairment and losses on sale of businesses and fixed assets, and closures Disposals Disposal proceeds and principal gains and losses on disposals by segment are described below. Proceeds from disposals of fixed assets Proceeds from disposals of businesses, net of cash disposed By business Upstream Downstream Other businesses and corporate 2020 2019 360 2,320 194 2,874 143 50 — 193 2020 2019 383 296 2 681 12,917 840 32 13,789 (86) — (3) (89) 14,381 2020 491 4,989 5,480 1,175 3,959 346 5,480 415 57 887 1,359 6,752 65 30 6,847 (131) — — (131) 8,075 2019 500 1,701 2,201 2,048 152 1 2,201 $ million 2018 437 15 4 456 $ million 2018 707 59 11 777 400 12 254 666 (580) (2) (1) (583) 860 $ million 2018 940 1,911 2,851 2,145 120 586 2,851 Proceeds from disposals of business in 2020 includes $3,888 million in respect of the disposal of the Petrochemical business and $347 million in respect of the disposal of the Alaska business. At 31 December 2020, deferred consideration relating to disposals amounted to $1,291 million receivable within one year (2019 $159 million and 2018 $35 million) and $2,402 million receivable after one year (2019 $125 million and 2018 $304 million). The deferred consideration principally relates to the disposals of our Petrochemical and Alaskan businesses. In addition, contingent consideration receivable relating to disposals amounted to $1,999 million at 31 December 2020 (2019 $598 million and 2018 $893 million).The contingent consideration at 31 December 2020 relates to the disposal of our Alaskan business and prior period disposals in the North Sea. These amounts of contingent consideration are reported within Other investments on the group balance sheet - see Note 18 for further information. Gains and losses on sale of businesses and fixed assets, and closures Upstream In 2020, gains principally resulted from adjustments to disposals in prior periods. Gains include $130 million from the disposal of our Alaska operations and interests and $166 million fair value movements in relation to deferred and contingent consideration in relation to the Alaska disposal and prior disposals in the North Sea. Losses included $134 million fair value movements in relation to deferred and contingent consideration arising from prior period disposals in the North Sea, $120 million in relation to the likely disposal of an exploration asset, and $78 million from the disposal of certain properties in the US. In 2019, losses included $191 million fair value movements in relation to contingent consideration arising from the prior period disposal of the Bruce, Keith and Devenick assets and $171 million in relation to severance costs associated with the divestment of our Alaskan business. In 2018, gains principally resulted from the disposal of interests in the Bruce, Keith and Rhum fields in the UK North Sea, from the disposal of certain properties in the US, and from adjustments to disposals in prior periods. Losses included $335 million resulting from the disposal of our interest in the Magnus field and associated assets in the UK North Sea, $221 million from the disposal of our interest in the Greater Kuparuk Area in the US, and adjustments to disposals in prior periods. 178 bp Annual Report and Form 20-F 2020 Financial statements 4. Disposals and impairment – continued Downstream In 2020, gains principally resulted from the $2.3 billion gain recognised on the disposal of our Petrochemicals business which completed in December 2020. Losses included $229 million in relation to cessation of manufacturing operations at the Kwinana Refinery following the decision to cease fuel production. Other businesses and corporate In 2020 the gain on disposal of businesses and fixed assets was principally in respect of the sale and leaseback of our St James's Square London headquarters - see Note 28 for further information. In 2019 losses on disposal of businesses and fixed assets were principally in respect of the reclassification of accumulated foreign exchange losses from reserves to the income statement upon the contribution of our Brazilian biofuels business to a new 50:50 joint venture BP Bunge Bioenergia. In 2018 proceeds from disposals were principally in respect of life insurance policies in the US and wind farms within our US wind business. Summarized financial information relating to the sale of businesses is shown in the table below. The principal transactions categorized as a business disposal in 2020 were the sales of our Petrochemical and Alaskan businesses. See Note 2 for further information. The principal transaction categorized as a business disposal in 2019 was the sale of our interests in the Gulf of Suez oil concessions in Egypt. The principal transaction categorized as a business disposal in 2018 was the disposal of our interest in the Greater Kuparuk Area in the US. Non-current assets Current assets Non-current liabilities Current liabilities Total carrying amount of net assets disposed Recycling of foreign exchange on disposal Costs on disposal Gains (losses) on sale of businesses Alaska 5,143 693 (923) (344) 4,569 — (6) 4,563 260 4,823 (219) (4,257) 347 Petrochemicals 2,592 846 (178) (425) 2,835 (331) (25) 2,479 2,414 4,893 — (1,005) 3,888 2020 2019 Other 1,357 — (538) (13) 806 3 44 853 (104) 749 — 5 754 Total 9,092 1,539 (1,639) (782) 8,210 (328) 13 7,895 2,570 10,465 (219) (5,257) 4,989 1,653 507 (257) (108) 1,795 880 190 2,865 (1,190) 1,675 (938) 964 1,701 $ million 2018 3,274 173 (250) (97) 3,100 — 3 3,103 (221) 2,882 (282) (689) 1,911 Total consideration Non-cash consideration Consideration received (receivable)a Proceeds from the sale of businesses, net of cash disposedb a In 2019 $633 million relates to deposits received in advance of the disposal of our Alaska business and certain assets in our BPX business. b Proceeds are stated net of cash and cash equivalents disposed of $101 million (2019 $30 million and 2018 $15 million). Impairments Impairment losses and impairment reversals in each segment are described below. For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment, intangibles and goodwill within Note 1. See also Note 12, and Note 15 for further information on impairments by asset category. Upstream Impairment losses and reversals in all years relate primarily to producing and midstream assets. The 2020 impairment loss of $12,917 million primarily relates to losses incurred in respect of producing and development assets in the UK North Sea ($2,796 million), the US ($2,744 million), Trinidad ($2,416 million), Mauritania and Senegal ($1,909 million), India ($1,313 million) and Canada ($865 million). Impairment losses were primarily driven by a reduction in bp’s future oil and gas price assumptions and, to a lesser extent, certain technical reserves revisions. The recoverable amount of the impaired CGUs in total is $33,415 million. The principal CGUs on which significant impairment losses were incurred in 2020 were $1,909 million for Tortue in Mauritania and Senegal; $1,313 million for KGD6 in India; $1,181 million for Schiehallion in the UK North Sea; $1,044 million for Mahogany in Trinidad, $960 million for Cassia in Trinidad; $1,011 million for Hawkville in BPX Energy; $747 million for ETAP in the UK North Sea and $742 million for Sunrise in Canada. The recoverable amount for each of these CGUs was their value in use, which in total was $13,200 million. In addition, impairment losses of $939 million were incurred relating to the disposal of bp’s business in Alaska. The recoverable amount of the Alaska business was its fair value less costs of disposal; see note 2 for further information. The 2019 impairment losses of $6,752 million related to various assets, with the most significant charges arising in the US. Impairment losses arose primarily as a result of the decision to dispose of certain assets, including $4,703 million in relation to completed and expected disposals in BPX Energy and $1,264 million relating to the expected disposal of our Alaskan business; of these amounts $355 million primarily relates to impairment of associated goodwill. The 2018 impairment losses of $400 million related to a number of different assets, with the most significant charges arising in Australia and the US. Impairment losses arose primarily as a result of changes to project activity, asset obsolescence and the decision to dispose of certain assets. The 2018 impairment reversals of $580 million related to a number of different assets, with the most significant reversals arising in the North Sea and Angola following a change to decommissioning cost estimates. Downstream Impairment losses totalling $840 million, $65 million, and $12 million were recognized in 2020, 2019 and 2018 respectively. The amount for 2020 principally relates to portfolio changes in the fuels business, including the conversion of Kwinana refinery to an import terminal. None of the impairment charges were individually material. bp Annual Report and Form 20-F 2020 179 4. Disposals and impairment – continued Other businesses and corporate Impairment losses totalling $32 million, $30 million, and $254 million were recognized in 2020, 2019 and 2018 respectively. The amount for 2018 is in respect of assets within our US wind business in advance of their disposal in December 2018. 5. Segmental analysis The group’s organizational structure reflects the various activities in which bp is engaged. At 31 December 2020, bp had three reportable segments: Upstream, Downstream and Rosneft. Upstream’s activities include oil and natural gas exploration, field development and production; midstream transportation, storage and processing; and the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs). Downstream’s activities include the refining, manufacturing, marketing, transportation, and supply and trading of crude oil, petroleum, petrochemicals products and related services to wholesale and retail customers. bp’s interest in Rosneft is accounted for using the equity method and is reported as a separate operating segment, reflecting the way in which the investment is managed. Other businesses and corporate comprises the biofuels and wind businesses, the group’s shipping and treasury functions, and corporate activities worldwide. The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. However, IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for the purposes of performance assessment and resource allocation. For bp, this measure of profit or loss is replacement cost profit or loss before interest and tax which reflects the replacement cost of supplies by excluding from profit or loss before interest and tax inventory holding gains and lossesa. Replacement cost profit or loss before interest and tax for the group is not a recognized measure under IFRS. Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers by region are based on the location of the group subsidiary which made the sale. The UK region includes the UK-based international activities of Downstream. All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-retirement benefit plans are allocated to Other businesses and corporate. However, the periodic expense relating to these plans is allocated to the operating segments based upon the business in which the employees work. Certain financial information is provided separately for the US as this is an individually material country for bp, and for the UK as this is bp’s country of domicile. In February 2020, bp announced plans for a reorganization of the group’s organizational structure.  The group’s segmental reporting structure as described above remained in place throughout 2020. Changes to this structure, as described in Note 1 - Voluntary changes to significant accounting policies - not yet adopted, came into effect from 1 January 2021. a Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. 180 bp Annual Report and Form 20-F 2020   5. Segmental analysis – continued By business Upstream Downstream Rosneft Financial statements Other businesses and corporate Consolidation adjustment and eliminations $ million 2020 Total group Segment revenues Sales and other operating revenues Less: sales and other operating revenues between segments Third party sales and other operating revenues Earnings from joint ventures and associates – after interest and tax Segment results Replacement cost profit (loss) before interest and taxation Inventory holding gains (losses)a Profit (loss) before interest and taxation Finance costs Net finance expense relating to pensions and other post- retirement benefits Profit before taxation Other income statement items Depreciation, depletion and amortization US Non-US Charges for provisions, net of write-back of unused provisions, including change in discount rate 34,197 162,974 (17,130) 17,067 (158) 162,816 — — — 1,716 (18,521) 180,366 (1,233) 483 18,521 — — 180,366 (268) 214 (229) (120) — (403) (21,547) 17 (21,530) 3,418 (2,796) 622 (149) (89) (238) (683) — (683) 89 — 89 (18,872) (2,868) (21,740) (3,115) (33) (24,888) 3,772 7,447 1,359 1,631 56 1,903 — — — 63 617 543 — — 5,194 9,695 — 2,502 Segment assets Investments in joint ventures and associates Additions to non-current assetsb a See explanation of inventory holding gains and losses on page 180. b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates. 10,749 8,743 3,671 5,359 11,808 — By business Upstream Downstream Rosneft 1,109 655 — — 27,337 14,757 Other businesses and corporate Consolidation adjustment and eliminations $ million 2019 Total group Segment revenues Sales and other operating revenues Less: sales and other operating revenues between segments Third party sales and other operating revenues Earnings from joint ventures and associates – after interest and tax Segment results Replacement cost profit (loss) before interest and taxation Inventory holding gains (losses)a Profit (loss) before interest and taxation Finance costs Net finance expense relating to pensions and other post- retirement benefits Profit before taxation Other income statement items Depreciation, depletion and amortization US Non-US Charges for provisions, net of write-back of unused provisions, including change in discount rate 54,501 (27,034) 250,897 (973) 27,467 249,924 — — — 1,788 (782) 1,006 (28,789) 28,789 278,397 — — 278,397 603 374 2,295 (15) — 3,257 4,917 (8) 4,909 6,502 685 7,187 2,316 (10) 2,306 (2,771) — (2,771) 75 — 75 11,039 667 11,706 (3,489) (63) 8,154 4,672 9,560 1,335 1,586 118 507 — — — 55 572 560 — — 6,062 11,718 — 1,185 Segment assets Investments in joint ventures and associates Additions to non-current assetsb a See explanation of inventory holding gains and losses on page 180. b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates. 12,196 16,254 3,609 4,014 12,927 — 1,593 2,345 — — 30,325 22,613 bp Annual Report and Form 20-F 2020 181                                                                     5. Segmental analysis – continued By business Upstream Downstream Rosneft Other businesses and corporate Consolidation adjustment and eliminations $ million 2018 Total group Segment revenues Sales and other operating revenues Less: sales and other operating revenues between segments Third party sales and other operating revenues Earnings from joint ventures and associates – after interest and tax Segment results Replacement cost profit (loss) before interest and taxation Inventory holding gains (losses)a Profit (loss) before interest and taxation Finance costs Net finance expense relating to pensions and other post- retirement benefits Profit before taxation Other income statement items Depreciation, depletion and amortization US Non-US Charges for provisions, net of write-back of unused provisions, including change in discount rate 56,399 (28,565) 270,689 (574) 27,834 270,115 — — — 1,678 (871) 807 (30,010) 30,010 298,756 — — 298,756 951 589 2,283 (70) — 3,753 14,328 (6) 14,322 6,940 (862) 6,078 2,221 67 2,288 (3,521) — (3,521) 211 — 211 20,179 (801) 19,378 (2,528) (127) 16,723 4,211 8,907 900 1,177 — — 59 203 — — 5,170 10,287 355 834 — 1,557 — 2,746 Segment assets Investments in joint ventures and associates Additions to non-current assetsb c a See explanation of inventory holding gains and losses on page 180. b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates. c Amounts have been restated to include acquisitions. 12,785 24,266 2,772 3,609 10,074 — By geographical area 689 477 — — 26,320 28,352 US Non-US $ million 2020 Total Revenues Third party sales and other operating revenuesa Other income statement items Production and similar taxes Non-current assets Non-current assetsb c a Non-US region includes UK $42,729 million b Non-US region includes UK $19,583 million c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments. 55,611 124,755 180,366 57 638 695 52,493 108,786 161,279 By geographical area US Non-US $ million 2019 Total Revenues Third party sales and other operating revenuesa Other income statement items Production and similar taxes Non-current assets Non-current assetsb c a Non-US region includes UK $63,194 million. b Non-US region includes UK $22,881 million. c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments. 89,334 189,063 278,397 315 1,232 1,547 57,757 133,398 191,155 182 bp Annual Report and Form 20-F 2020                                     5. Segmental analysis – continued By geographical area Financial statements US Non-US $ million 2018 Total Revenues Third party sales and other operating revenuesa Other income statement items Production and similar taxes Non-current assets Non-current assetsb c a Non-US region includes UK $65,630 million. b Non-US region includes UK $19,426 million. c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments. 98,066 200,690 298,756 369 1,167 1,536 68,188 124,060 192,248 6. Sales and other operating revenues Crude oil Oil products Natural gas, LNG and NGLs Non-oil products and other revenues from contracts with customers Revenue from contracts with customers Other operating revenuesa Total sales and other operating revenues a Principally relates to physically settled derivative sales contracts. 2020 5,048 63,564 12,726 9,840 91,178 89,188 180,366 2019 9,141 102,408 18,909 12,169 142,627 135,770 278,397 $ million 2018 10,331 108,515 20,494 12,489 151,829 146,927 298,756 An analysis of third-party sales and other operating revenues by segment and region is provided in Note 5. The group’s sales to customers of crude oil and oil products were substantially all made by the Downstream segment. The group’s sales to customers of natural gas, LNG and NGLs were made by the Upstream segment. A significant majority of the group’s sales of non-oil products and other revenues from contracts with customers were made by the Downstream segment. Amounts shown for revenue from contracts with customers and other operating revenues for 2018 and 2019 have been represented to align with the current period. See Note 1 - Other changes to significant accounting policies - Physically settled derivative contracts for further information. 7. Income statement analysis Interest and other income Interest income from Financial assets measured at amortized cost Financial assets measured at fair value through profit or loss Other income Currency exchange losses charged to the income statementa Expenditure on research and development Costs relating to the Gulf of Mexico oil spill (pre-interest and tax)b Finance costs Interest expense on lease liabilitiesc Interest expense on other liabilities measured at amortized costd Capitalized at 2.75% (2019 3.50% and 2018 3.56%)e Unwinding of discount on provisionsf Unwinding of discount on other payables measured at amortized cost a Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss. b Included within production and manufacturing expenses. c Interest payable on lease liabilities in 2018 comparative period relates to leases previously classified as finance leases under IAS 17. d 2020 includes a loss of $158 million associated with the buyback of finance debt. e Tax relief on capitalized interest is approximately $83 million (2019 $51 million and 2018 $55 million). f From 1 July 2018, the group changed its method of discounting and unwinding provisions from using real rates to using nominal rates. 2020 2019 215 25 423 663 38 332 255 337 2,166 (345) 437 520 3,115 371 49 349 769 37 364 319 379 2,410 (374) 505 569 3,489 $ million 2018 421 39 313 773 368 429 714 51 2,147 (419) 210 539 2,528 bp Annual Report and Form 20-F 2020 183       8. Exploration for and evaluation of oil and natural gas resources The following financial information represents the amounts included within the group totals relating to activity associated with the exploration for and evaluation of oil and natural gas resources. All such activity is recorded within the Upstream segment. For information on significant judgements made in relation to oil and natural gas accounting see Intangible assets in Note 1. 2020 2019 $ million 2018 Exploration and evaluation costs Exploration expenditure written offa Other exploration costs Exploration expense for the year Impairment losses Intangible assets – exploration and appraisal expenditureb c Liabilities Net assets Cash used in operating activities Cash used in investing activities a 2020 includes $2,643 million in the Gulf of Mexico primarily relating to the Paleogene assets, $2,539 million in Canada primarily relating to Terre de Grace, $2,141 million in Brazil, $952 million in Egypt and $832 million in Angola. 2018 included $447 million in the deepwater Gulf of Mexico principally relating to licence expiries. For further information see Upstream – Exploration on page . b 2019 includes approximately $2.5 billion relating to Canadian oil sands. c Amount capitalized at 31 December 2020 relates to assets in various regions. The largest of these is $0.7 billion capitalised in the Middle East region. 9,920 360 10,280 156 4,113 71 4,042 360 674 631 333 964 2 14,091 73 14,018 333 1,215 1,085 360 1,445 137 15,989 60 15,929 360 1,119 9. Taxation Tax on profit Current tax Charge for the year Adjustment in respect of prior yearsa Deferred taxb Origination and reversal of temporary differences in the current year Adjustment in respect of prior years 2020 2019 2,095 50 2,145 5,316 (68) 5,248 $ million 2018 6,217 (221) 5,996 (7,826) 1,522 (6,304) (4,159) (1,190) (94) (1,284) 3,964 907 242 1,149 7,145 Tax charge (credit) on profit or loss a The adjustments in respect of prior years reflect the reassessment of the current tax balances for prior years in light of changes in facts and circumstances during the year. b Origination and reversal of temporary differences in the current year include the impact of tax rate changes on deferred tax balances. The adjustments in respect of prior years reflect the reassessment of deferred tax balances for prior periods in light of all other changes in facts and circumstances during the year; 2020 includes charges for the reassessment of deferred tax asset recognition in light of revisions to price assumptions. In 2020, the total tax charge recognized within other comprehensive income was $39 million (2019 $227 million charge and 2018 $714 million charge), primarily comprising the deferred tax impact of the remeasurements of the net pension and other post-retirement benefit liability or asset. See Note 32 for further information. The total tax charge recognized directly in equity was $154 million (2019 $37 million charge and 2018 $17 million charge). 2020 principally relates to a non-controlling interest transaction entered into by Rosneft. Reconciliation of the effective tax rate The following table provides a reconciliation of the group weighted average statutory corporate income tax rate to the effective tax rate of the group on profit or loss before taxation. 184 bp Annual Report and Form 20-F 2020 9. Taxation – continued Profit (loss) before taxation Tax charge (credit) on profit or loss Effective tax rate Tax rate computed at the weighted average statutory ratea Increase (decrease) resulting from Tax reported in equity-accounted entities Adjustments in respect of prior years Deferred tax not recognized Tax incentives for investment Foreign exchange Items not deductible for tax purposes Other Financial statements 2020 (24,888) (4,159) 17% 2019 8,154 3,964 49% $ million 2018 16,723 7,145 43% 31 52 — (6) (3) 1 (1) (3) (2) 17 (7) (2) (2) (3) 1 4 6 49 % 43 (5) — 1 (2) 3 1 2 43 Effective tax rate a Calculated based on the statutory corporate income tax rate applicable in the countries in which the group operates, weighted by the profits and losses before tax in the respective countries. Deferred tax Analysis of movements during the year in the net deferred tax (asset) liability At 31 December Adjustment on adoption of IFRS 16 At 1 January Exchange adjustments Credit for the year in the income statement Charge for the year in other comprehensive income Charge for the year in equity Acquisitions and disposals At 31 December 2020 5,190 — 5,190 55 (6,304) 48 154 (56) (913) $ million 2019 6,106 (75) 6,031 72 (1,284) 233 37 101 5,190 The following table provides an analysis of deferred tax in the income statement and the balance sheet by category of temporary difference: Deferred tax liability Depreciation Pension plan surpluses Derivative financial instruments Other taxable temporary differences Deferred tax asset Depreciation Lease liabilities Pension plan and other post-retirement benefit plan deficits Decommissioning, environmental and other provisions Derivative financial instruments Tax credits Loss carry forward Other deductible temporary differences Net deferred tax charge (credit) and net deferred tax (asset) liabilityb Of which – deferred tax liabilities – deferred tax assets Income statementa $ million Balance sheet 2020 2019 2018 2020 2019 (7,295) 69 33 (32) (7,225) (849) 286 2 438 — 310 543 191 921 (6,304) (1,436) (31) 29 159 (1,279) — 264 62 (472) 63 (336) 12 402 (5) (1,284) (1,297) 65 (36) (57) (1,325) — 8 (6) 1,505 (31) 123 559 316 2,474 1,149 15,361 2,691 63 1,562 19,677 (849) (1,122) (1,548) (7,155) (25) (3,652) (5,319) (920) (20,590) (913) 6,831 7,744 22,627 2,290 29 1,496 26,442 — (1,380) (1,367) (7,579) (24) (3,964) (5,834) (1,104) (21,252) 5,190 9,750 4,560 a The 2018 income statement is impacted by the reduction in US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018. b Included within the net deferred tax (asset) liability is a deferred tax asset balance of $5,471 million (2019 $5,526 million) related to the Gulf of Mexico oil spill. bp Annual Report and Form 20-F 2020 185 9. Taxation – continued Of the $7,744 million of deferred tax assets recognised on the group balance sheet at 31 December 2020 (2019 $4,560 million), $7,659 million (2019 $2,421 million) relates to entities that have suffered a loss in either the current or preceding period. This amount is supported by forecasts that indicate sufficient future taxable profits will be available to utilize such assets. For 2020, $3,906 million relates to the US, $707 million relates to India, $637 million relates to Australia and $588 million relates to Trinidad & Tobago (2019 $2,421 million relates to the US). A summary of temporary differences, unused tax credits and unused tax losses for which deferred tax has not been recognized is shown in the table below. $ billion At 31 December Unused US state tax lossesa Unused tax losses – other jurisdictionsb Unused tax credits 2020 2.4 6.0 26.9 23.0 3.9 46.1 0.8 2019 2.3 3.5 25.4 21.5 3.9 40.4 1.5 of which – arising in the UKc               – arising in the USd Deductible temporary differencese Taxable temporary differences associated with investments in subsidiaries and equity-accounted entities a For 2020 these losses expire in the period 2021-2040 with applicable tax rates ranging from 3% to 10%. b The majority of the unused tax losses have no fixed expiry date. c The UK unused tax credits arise predominantly in overseas branches of UK entities based in jurisdictions with higher statutory corporate income tax rates than the UK. No deferred tax asset has been recognized on these tax credits as they are unlikely to have value in the future; UK taxes on these overseas branches are largely mitigated by double tax relief in respect of overseas tax. These tax credits have no fixed expiry date. d For 2020 the US unused tax credits expire in the period 2021-2030. e The majority comprises fixed asset temporary differences in the UK. Substantially all of the temporary differences have no expiry date. Impact of previously unrecognized deferred tax or write-down of deferred tax assets on tax charge Current tax benefit relating to the utilization of previously unrecognized deferred tax assets Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets Deferred tax benefit relating to the recognition of previously unrecognized deferred tax assets Deferred tax expense arising from the write-down of a previously recognized deferred tax asset 2020 46 11 — 1,622 2019 272 96 364 73 $ million 2018 83 — 112 169 10. Dividends The quarterly dividend which is expected to be paid on 26 March 2021 in respect of the fourth quarter 2020 is 5.25 cents per ordinary share ($0.315 per American Depositary Share (ADS)). The corresponding amount in sterling was announced on 15 March 2021. Dividends announced and paid in cash Preference shares Ordinary shares March June September December Dividend announced, paid in March 2021 Pence per share Cents per share 2020 2019 2018 2020 2019 2018 2020 2019 $ million 2018 8.1558 7.7382 7.1691 8.3421 8.0655 7.4435 4.0433 8.3475 7.9296 3.9169 7.8250 8.0251 24.4581 31.9762 30.5673 10.25 10.25 10.25 10.25 41.00 10.00 10.00 10.25 10.25 40.50 10.50 10.50 5.25 5.25 31.50 5.25 1 1 1 1,435 1,779 1,656 2,075 6,946 1,828 1,727 1,409 1,734 6,699 2,102 2,119 1,059 1,059 6,340 1,067 The amount of unclaimed dividends recognised as a liability at 31 December 2020 is $50 million (2019 $22 million). The details of the scrip dividends issued are shown in the table below. The board decided not to offer a scrip dividend alternative in respect of any dividends announced since the third quarter 2019, including the fourth quarter 2020 dividend expected to be paid on 26 March 2021. Number of shares issued (thousand) Value of shares issued ($ million) 2020 2019 2018 — 208,927 195,305 1,381 1,387 — The financial statements for the year ended 31 December 2020 do not reflect the dividend announced on 2 February 2021 and paid in March 2021; this will be treated as an appropriation of profit in the year ending 31 December 2021. 186 bp Annual Report and Form 20-F 2020 11. Earnings per share Per ordinary share Basic earnings per share Diluted earnings per share Per American Depositary Share (ADS) Basic earnings per share Diluted earnings per share Financial statements 2020 (100.42) (100.42) 2020 (6.03) (6.03) 2019 19.84 19.73 2019 1.19 1.18 Cents per share 2018 46.98 46.67 Dollars per share 2018 2.82 2.80 Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to bp ordinary shareholders by the weighted average number of ordinary shares outstanding during the year. The weighted average number of shares outstanding includes certain shares that will be issuable in the future under employee share-based payment plans and excludes treasury shares, which includes shares held by the Employee Share Ownership Plan trusts (ESOPs). For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the average number of shares that are potentially issuable in connection with employee share-based payment plans. If the inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate diluted earnings per share. Profit attributable to bp shareholders Less: dividend requirements on preference shares Profit for the year attributable to bp ordinary shareholders Basic weighted average number of ordinary shares Potential dilutive effect of ordinary shares issuable under employee share-based payment plans Weighted average number of ordinary shares outstanding used to calculate diluted earnings per share Basic weighted average number of ordinary shares – ADS equivalent Potential dilutive effect of ordinary shares (ADS equivalent) issuable under employee share-based payment plans Weighted average number of ordinary shares (ADS equivalent) outstanding used to calculate diluted earnings per share 2020 (20,305) 1 (20,306) 2019 4,026 1 4,025 $ million 2018 9,383 1 9,382 2020 2019 20,221,514 20,284,859 Shares thousand 2018 19,970,215 — 114,811 132,278 20,221,514 20,399,670 20,102,493 2020 2019 3,370,252 3,380,809 Shares thousand 2018 3,328,369 — 19,136 22,046 3,370,252 3,399,945 3,350,415 The number of ordinary shares outstanding at 31 December 2020, excluding treasury shares, and including certain shares that will be issuable in the future under employee share-based payment plans was 20,264,027,711. Between 31 December 2020 and 25 February 2021, the latest practicable date before the completion of these financial statements, there was a net increase of 66,249,231 in the number of ordinary shares outstanding primarily as a result of share issues in relation to employee share-based payment plans. Employee share-based payment plans The group operates share and share option plans for directors and certain employees to obtain ordinary shares and ADSs in the company. Information on these plans for directors is shown in the Directors remuneration report on pages 103-126. The following table shows the number of shares potentially issuable under equity-settled employee share option plans, including the number of options outstanding, the number of options exercisable at the end of each year, and the corresponding weighted average exercise prices. The dilutive effect of these plans at 31 December is also shown. Share options Number of optionsa b thousand 28,171 1,874 2,497 2020 Weighted average exercise price $ 2019 Number of optionsa b thousand 17,112 1,067 3,990 Weighted average exercise price $ 4.91 3.97 n/a Outstanding Exercisable Dilutive effect a Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares). b At 31 December 2020 the quoted market price of one bp ordinary share was £2.55 (2019 £4.72). In addition, the group operates a number of equity-settled employee share plans under which share units are granted to the group’s senior leaders and certain other employees. These plans typically have a three-year performance or restricted period during which the units accrue net notional dividends which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for qualifying reasons. The number of shares that are expected to vest each year under employee share plans are shown in the table below. The dilutive effect of the employee share plans at 31 December is also shown. 3.79 5.02 n/a bp Annual Report and Form 20-F 2020 187 11. Earnings per share – continued Share plans Vesting Within one year 1 to 2 years 2 to 3 years 3 to 4 years Over 4 years 2020 2019 Number of sharesa Number of sharesa thousand 87,517 85,720 147,097 749 349 321,432 104,068 thousand 91,105 89,939 80,844 725 576 263,189 92,343 Dilutive effect a Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares). There has been a net decrease of 29,718,486 in the number of potential ordinary shares relating to employee share-based payment plans between 31 December 2020 and 25 February 2021. 188 bp Annual Report and Form 20-F 2020 12. Property, plant and equipment (PP&E) Financial statements Land and land improvements Buildings Oil and gas propertiesa Plant, machinery and equipment Fittings, fixtures and office equipment Transportation Oil depots, storage tanks and service stations $ million Total Cost - owned PP&E At 1 January 2020 Exchange adjustments Additions Acquisitions Transfers from intangible assets Reclassified as assets held for sale Deletions At 31 December 2020 Depreciation - owned PP&E At 1 January 2020 Exchange adjustments Charge for the year Impairment losses Impairment reversals Reclassified as assets held for sale Deletions At 31 December 2020 Owned PP&E - net book amount at 31 December 2020 Right-of-use assets - net book amount at 31 December 2020b Total PP&E - net book amount at 31 December 2020 Cost - owned PP&E At 1 January 2019 Exchange adjustments Additions Acquisitions Transfers from intangible assets Reclassified as assets held for sale Deletions At 31 December 2019 Depreciation - owned PP&E At 1 January 2019 Exchange adjustments Charge for the year Impairment losses Impairment reversals Reclassified as assets held for sale Deletions At 31 December 2019 Owned PP&E - net book amount at 31 December 2019 Right-of-use assets - net book amount at 31 December 2019b Total PP&E - net book amount at 31 December 2019 Assets under construction included above At 31 December 2020 At 31 December 2019 Depreciation charge for the year on right-of-use assets 219 101 3,609 1,422 214,352 46,724 801 1,539 35 — — (6,185) (146) 3,872 1,210 214,323 42,914 6 63 89 — — — — — (281) — 6,922 — 605 (1,425) (6,131) 6 697 124,766 21,527 581 424 — 35 1,312 46 10,068 113 744 9 11,705 8 — (83) — (1) (326) — — — (3,976) (5,579) (126) (45) 631 140,551 20,031 692 2,532 33 586 5 — — (738) 2,418 2,006 26 170 2 — — (359) 1,845 3,474 8 49 9 — — (491) 3,049 2,744 9 77 4 (5) — (448) 2,381 8,694 280,807 1,670 10,124 514 605 (1,425) (14,233) 10,276 278,062 603 864 376 — — (261) 4,865 157,186 379 879 740 12,526 3 12,475 — (89) — (326) (10,734) (201) 5,786 171,917 3,180 579 73,772 22,883 573 668 4,490 106,145 — 1,254 77 792 21 2,855 3,692 8,691 3,180 1,833 73,849 23,675 594 3,523 8,182 114,836 5 3,562 1,502 232,684 45,721 (158) — (22) 2,433 93 13,237 88 — — 51 — — 1,885 — — — (26) — (22,602) (1,272) (178) (10,852) (44) 3,609 1,422 214,352 46,724 5 697 133,687 20,512 626 (63) — (4) 1,705 59 13,012 44 64 5,871 1 1 — (129) — — — — — (17,764) (65) (86) (691) (9,911) 697 124,766 21,527 581 2,747 15 172 — — (76) (326) 2,532 2,041 12 168 1 — (69) (147) 2,006 10,183 (3) 274 — — (6,708) (272) 3,474 7,819 (3) 173 404 (2) (5,478) (169) 2,744 8,866 305,265 (232) 16,941 59 1,885 (29,412) (13,699) 8,694 280,807 (69) 644 8 — — (755) 5,146 170,528 (98) 15,581 6,346 (131) (23,311) (11,729) 4,865 157,186 (45) 420 4 — — (660) 3,028 725 89,586 25,197 526 730 3,829 123,621 — 1,196 128 1,241 16 3,385 3,055 9,021 3,028 1,921 89,714 26,438 542 4,115 6,884 132,642 17,259 23,897 2020 2019 a For information on significant estimates and judgements made in relation to the estimation of oil and natural reserves see Property, plant and equipment within Note 1. b $284 million (2019 $653 million) of drilling rig right-of-use assets and $2,521 million (2019 $2,929 million) of shipping vessel right-of-use assets are included in Plant, machinery and equipment and 192 220 829 784 579 526 637 671 43 31 10 9 2,290 2,241 Transportation respectively. bp Annual Report and Form 20-F 2020 189 13. Capital commitments Authorized future capital expenditure for property, plant and equipment (excluding right-of-use assets) by group companies for which contracts had been signed at 31 December 2020 amounted to $8,009 million (2019 $11,382 million, 2018 $8,319 million). bp has contracted capital commitments amounting to $1,087 million (2019 $77 million, 2018 $25 million) in relation to joint ventures and $183 million (2019 $787 million, 2018 $1,227 million) in relation to associates. bp’s share of contracted capital commitments of joint ventures amounted to $900 million (2019 $1,024 million, 2018 $619 million). 14. Goodwill and impairment review of goodwill Cost At 1 January Exchange adjustments Acquisitions and other additionsa Reclassified as assets held for sale Deletions At 31 December Impairment losses At 1 January Exchange adjustments Impairment losses for the year Deletions At 31 December Net book amount at 31 December Net book amount at 1 January a 2020 principally relates to an acquisition in the US Fuels business. Impairment review of goodwill Goodwill at 31 December Upstream Downstream Other businesses and corporate 2020 12,865 184 632 (199) (389) 13,093 997 1 1 (386) 613 12,480 11,868 2020 7,765 4,660 55 12,480 $ million 2019 12,815 79 26 — (55) 12,865 611 — 386 — 997 11,868 12,204 $ million 2019 7,958 3,904 6 11,868 Goodwill acquired through business combinations has been allocated to groups of cash-generating units that are expected to benefit from the synergies of the acquisition. For Upstream, goodwill is allocated to all oil and gas assets in aggregate at the segment level. For Downstream, goodwill has been allocated to Lubricants, US Fuels, European Fuels and Other. For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment, intangible assets and goodwill in Note 1. Upstream Goodwill Excess of recoverable amount over carrying amount 2020 7,765 31,749 $ million 2019 7,958 93,250 The table above shows the carrying amount of goodwill for the segment at the period end and the excess of the recoverable amount, based on a pre- tax value-in-use calculation, over the carrying amount (headroom) at the date of the most recent test. The reduction in headroom since the prior period principally relates to the impact of changes to price assumptions. No impairment of the Upstream goodwill balance was recognized during 2020 (2019 $386 million). The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates of cessation of production of each producing field, based on current estimates of reserves and resources, appropriately risked. Midstream and supply and trading activities and equity-accounted entities are generally not included in the impairment review of goodwill, as they do not represent part of the grouping of cash-generating units to which the goodwill relates and which is used to monitor the goodwill for internal management purposes. Where such activities form part of a wider Upstream cash-generating unit, they are reflected in the test. As the production profile and related cash flows can be estimated from bp’s past experience, management believes that the cash flows generated over the estimated life of field is the appropriate basis upon which to assess goodwill and individual assets for impairment. The estimated date of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons, production costs, the contractual duration of the production concession and the selling price of the hydrocarbons produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of each field is computed using appropriate individual economic models and key assumptions agreed by bp management. Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis, including operating and capital expenditure, are derived from the business segment plan. The production profiles used are consistent with the reserve and resource volumes approved as part of bp’s centrally controlled process for the estimation of proved and probable reserves and total resources. Oil and gas price assumptions and discount rate assumptions used were as disclosed in Note 1. The average production for the purposes of goodwill impairment testing over the next 15 years is 877 mmboe per year (2019 829 mmboe per year). The weighted average pre-tax discount rate used in the test is 11% (2019 12%). 190 bp Annual Report and Form 20-F 2020 Financial statements 14. Goodwill and impairment review of goodwill – continued The most recent review for impairment was carried out in the fourth quarter. The key assumptions used in the value-in-use calculation are oil and natural gas prices, production volumes and the discount rate. The value-in-use calculation has been prepared solely for the purposes of determining whether the goodwill balance was impaired. Estimated future cash flows were prepared on the basis of certain assumptions prevailing at the time of the test. The actual outcomes may differ from the assumptions made. For example, reserves and resources estimates and production forecasts are subject to revision as further technical information becomes available and economic conditions change. Due to economic developments, regulatory change and emissions reduction activity arising from climate concern and other factors, future commodity prices and other assumptions may differ from the forecasts used in the calculations. Sensitivities to different variables have been estimated using certain simplifying assumptions. For example, lower oil and gas price or production sensitivities do not fully reflect the specific impacts for each contractual arrangement and will not capture all favourable impacts that may arise from cost deflation or savings. A detailed calculation at any given price or production profile may, therefore, produce a different result. Adverse changes in input assumptions applied in respect to assets carried at or close to their value in use, primarily being those assets previously impaired, would have a limited effect on goodwill headroom, instead resulting in a direct impairment of the particular cash-generating unit's net book value. Conversely, a reduction in the value in use of those assets carried at a value below their respective values in use would result in an adverse impact on the goodwill headroom. It is estimated that a 21% reduction in revenue throughout each year of the remaining life of those assets, either as a result of adverse price or production conditions or a combination of each, would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment. It is estimated that no reasonably possible change in the discount rate would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the segment. Downstream Goodwill Lubricants US Fuels 2,865 606 European Fuels 913 Other 276 Total 4,660 Lubricants US Fuels 2,779 — European Fuels 858 Other 267 Total 3,904 2020 $ million 2019 Cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of up to five years. To determine the value in use for each of the cash-generating units, cash flows for a period of 10 years are discounted and aggregated with a terminal value. Lubricants As permitted by IAS 36, the detailed calculations of Lubricants’ recoverable amount performed in the most recent detailed calculation in 2018 was used as the basis for the tests in 2020 as the criteria of IAS 36 were considered satisfied: the headroom was substantial in 2018; there have been no significant changes in the assets and liabilities; and the likelihood that the recoverable amount would be less than the carrying amount is remote. The key assumptions to which the calculation of value in use for the Lubricants unit is most sensitive are operating unit margins, sales volumes, and discount rate. Operating margin and sales volumes assumptions used in the detailed impairment review of goodwill calculation are consistent with the assumptions used in the Lubricants unit’s business plan and values assigned to these key assumptions reflect past experience. No reasonably possible change in any of these key assumptions would cause the unit’s carrying amount to exceed its recoverable amount. Cash flows beyond the plan period are extrapolated using a nominal 2.8% growth rate. 15. Intangible assets Cost At 1 January Exchange adjustments Acquisitions Additions Transfers to property, plant and equipment Reclassified as assets held for sale Deletions At 31 December Amortization At 1 January Exchange adjustments Exploration expenditure written off Charge for the year Impairment losses Reclassified as assets held for sale Deletions At 31 December Net book amount at 31 December Net book amount at 1 January a For further information see Intangible assets within Note 1 and Note 8. Exploration and appraisal expenditurea Other intangibles 15,306 — — 703 (605) — (987) 14,417 1,215 — 9,920 — 156 — (987) 10,304 4,113 14,091 4,900 138 318 645 — — (379) 5,622 3,452 93 — 372 9 — (284) 3,642 1,980 1,448 2020 Total 20,206 138 318 1,348 (605) — (1,366) 20,039 4,667 93 9,920 372 165 — (1,271) 13,946 6,093 15,539 Exploration and appraisal expenditurea Other intangibles 17,053 — — 1,268 (1,885) (671) (459) 15,306 1,064 — 631 — 2 (61) (421) 1,215 14,091 15,989 4,504 2 35 457 — — (98) 4,900 3,209 4 — 331 2 — (94) 3,452 1,448 1,295 $ million 2019 Total 21,557 2 35 1,725 (1,885) (671) (557) 20,206 4,273 4 631 331 4 (61) (515) 4,667 15,539 17,284 bp Annual Report and Form 20-F 2020 191 16. Investments in joint ventures The following table provides aggregated summarized financial information relating to the group’s share of joint ventures. Sales and other operating revenues Profit before interest and taxation Finance costs Profit before taxation Taxation Non-controlling interest Profit for the year Other comprehensive income Total comprehensive income Non-current assets Current assets Total assets Current liabilities Non-current liabilities Total liabilities Net assets Less: non-controlling interests Group investment in joint ventures Group share of net assets (as above) Loans made by group companies to joint ventures a 2019 has been restated to include non-controlling interest 2020 10,545 (151) 201 (352) (51) 1 (302) (5) (307) 12,646 3,424 16,070 2,644 5,023 7,667 8,403 39 8,364 2019a 14,139 976 109 867 289 2 576 (6) 570 13,457 3,738 17,195 2,514 4,676 7,190 10,005 49 9,956 8,364 (2) 8,362 9,956 35 9,991 Transactions between the group and its joint ventures are summarized below. Sales to joint ventures Product LNG, crude oil and oil products, natural gas 2020 Amount receivable at 31 December 180 Sales 2,974 2019 Amount receivable at 31 December 431 Sales 4,884 Sales 4,603 Purchases from joint ventures Product 2020 Amount payable at 31 December 2019 Amount payable at 31 December Purchases Purchases Purchases $ million 2018 13,258 1,396 85 1,311 414 — 897 6 903 $ million 2018 Amount receivable at 31 December 251 $ million 2018 Amount payable at 31 December LNG, crude oil and oil products, natural gas, refinery operating costs, plant processing fees 959 84 1,812 225 1,336 300 The terms of the outstanding balances receivable from joint ventures are typically 30 to 45 days. The balances are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above. bp's share of impairment charges taken by joint ventures in 2020 was $433 million (2019 $25 million reversal) of which $336 million (2019 $25 million reversal) was in the Upstream segment. 17. Investments in associates The following table provides aggregated summarized financial information for the group’s associates as it relates to the amounts recognized in the group income statement and on the group balance sheet. Rosneft Other associates Income statement Earnings from associates - after interest and tax $ million Balance sheet Investments in associates 2020 (229) 128 (101) 2019 2,295 386 2,681 2018 2,283 573 2,856 2020 11,808 7,167 18,975 2019 12,927 7,407 20,334 The associate that is material to the group at both 31 December 2020 and 2019 is Rosneft. 192 bp Annual Report and Form 20-F 2020 Financial statements 17. Investments in associates – continued bp owns 19.75% of the voting shares of Rosneft which are listed on the MICEX stock exchange in Moscow and its global depository receipts are listed on the London Stock Exchange. Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is wholly owned by the Russian government. At 31 December 2020, Rosneftegaz held 40.4% (2019 50.0% plus one share) of the voting shares of Rosneft. bp classifies its investment in Rosneft as an associate because, in management’s judgement, bp has significant influence over Rosneft; see Interests in other entities within Note 1 for further information. The group’s investment in Rosneft is a foreign operation whose functional currency is the Russian rouble. The decrease in the group's equity-accounted investment balance for Rosneft at 31 December 2020 compared with 31 December 2019 principally relates to adverse foreign exchange effects, which have been recognized in other comprehensive income, and dividends, partially offset by bp's share of Rosneft’s changes in equity. During 2020 Rosneft completed a transaction to transfer all of its interest and cease participation in its Venezuelan businesses to a company owned by the government of the Russian Federation. In consideration, Rosneft received shares equal to a 9.6% share of its own equity. The shares are held by a 100% subsidiary of Rosneft and accounted for as treasury shares. Rosneft also entered into share buyback transactions during the year. These are also accounted for as treasury shares. bp retains 19.75% of the voting rights at meetings of Rosneft shareholders and will continue to be entitled to dividends based on its current shareholding. bp’s economic interest, however, increased as a result of its indirect interest in the shares held by the subsidiary of Rosneft. bp’s share of profit or loss of Rosneft reflects its economic interest. At 31 December 2020, bp's economic interest was 22.03%. On 28 December 2020 Rosneft completed the acquisition of 100% stakes in JSC Taimyrneftegaz and LLC Taimyrburservis, and the sale of a 10% interest in LLC Vostok Oil. A preliminary assessment of the fair values of the assets and liabilities acquired and the consideration transferred in respect of the acquisitions has been undertaken and the further impact, if any, on bp’s accounting for its equity-accounted investment in Rosneft will be updated once this has been finalised. The value of bp’s 19.75% shareholding in Rosneft based on the quoted market share price of $5.64 per share (2019 $7.21 per share) was $11,804 million at 31 December 2020 (2019 $15,090 million). The value of bp's 22.03% economic interest based on the quoted market share price was $13,167 million at 31 December 2020. The following table provides summarized financial information relating to Rosneft. This information is presented on a 100% basis and reflects adjustments made by bp to Rosneft’s own results in applying the equity method of accounting. bp adjusts Rosneft’s results for the accounting required under IFRS relating to bp’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the disposal of bp’s interest in TNK- BP. Sales and other operating revenues Profit before interest and taxation Finance costs Profit (loss) before taxation Taxation Non-controlling interests Profit (loss) for the year Other comprehensive income Total comprehensive income Non-current assets Current assets Total assets Current liabilities Non-current liabilities Total liabilities Net assets Less: non-controlling interests $ million Gross amount 2018 131,322 18,886 2,785 16,101 2,957 1,585 11,559 2,086 13,645 2020 82,786 1,270 1,742 (472) 208 482 (1,162) 1,653 491 175,978 42,459 218,437 49,781 96,727 146,508 71,929 10,897 61,032 2019 134,046 17,473 1,281 16,192 3,058 1,514 11,620 572 12,192 161,327 38,657 199,984 44,459 79,327 123,786 76,198 10,744 65,454 The group received dividends, net of withholding tax, of $480 million from Rosneft in 2020 (2019 $785 million and 2018 $620 million). bp Annual Report and Form 20-F 2020 193 17. Investments in associates – continued Summarized financial information for the group’s share of associates is shown below. 2020 2019 Sales and other operating revenues Profit before interest and taxation Finance costs Profit (loss) before taxation Taxation Non-controlling interests Profit (loss) for the year Other comprehensive income Total comprehensive income Non-current assets Current assets Total assets Current liabilities Non-current liabilities Total liabilities Net assets Less: non-controlling interests Group investment in associates Group share of net assets (as above) Loans made by group companies to associates Rosnefta 17,535 295 372 (77) 51 101 (229) 336 107 Rosnefta Other Total 5,946 23,481 26,474 3,451 571 253 452 3,198 119 604 118 102 299 2,295 (101) 317 113 2,408 216 276 80 196 67 1 128 (19) 109 Rosnefta Other Total 7,934 34,408 25,936 3,730 4,239 550 340 3,180 3,899 584 919 313 299 2,283 2,681 412 88 2,695 2,769 788 87 701 315 — 386 (25) 361 1,924 7,635 8,238 1,749 9,987 33,754 11,449 45,203 31,862 11,504 43,366 9,559 41,992 13,198 55,190 39,497 13,428 52,925 1,908 10,689 4,577 20,244 6,485 30,933 6,943 21,992 2,122 6,943 19,870 1,346 10,881 8,781 4,709 23,267 15,667 6,055 34,148 24,448 7,143 21,042 15,049 2,122 2,091 7,143 18,951 12,927 9,535 18,558 28,093 13,899 2,091 11,808 — — 11,808 7,143 18,951 12,927 6,943 19,870 — 11,808 24 — 7,167 18,975 12,927 24 464 464 7,407 20,334 $ million bp share 2018 Other Total 9,134 35,070 4,880 1,150 628 78 4,252 1,072 1,083 499 — 313 2,856 573 (1) 411 3,267 572 a In 2014-2019, Rosneft adopted hedge accounting in relation to a portion of highly probable future export revenue denominated in US dollars. Foreign exchange gains and losses arising on the retranslation of borrowings denominated in currencies other than the Russian rouble and designated as hedging instruments were recognized initially in other comprehensive income, and were reclassified to the income statement as the hedged revenue was recognized. During the year, bp and Reliance Industries completed the formation of a new fuels and mobility venture, Reliance BP Mobility Limited, that will operate across India under the Jio-bp brand. bp invested $1 billion to acquire a 49% stake in the company. Transactions between the group and its associates are summarized below. Sales to associates Product LNG, crude oil and oil products, natural gas 2020 Amount receivable at 31 December 169 Sales 855 2019 Amount receivable at 31 December 243 Sales 1,544 Sales 2,064 Purchases from associates Product 2020 Amount payable at 31 December 2019 Amount payable at 31 December Purchases Purchases Crude oil and oil products, natural gas, transportation tariff 4,926 1,280 9,503 1,641 Purchases 14,112 $ million 2018 Amount receivable at 31 December 393 $ million 2018 Amount payable at 31 December 2,069 In addition to the transactions shown in the table above, in 2018 bp acquired a 49% stake in LLC Kharampurneftegaz, a Rosneft subsidiary, which develops resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets in northern Russia. bp’s interest in LLC Kharampurneftegaz is accounted for as an associate. The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above. The majority of purchases from associates relate to crude oil and oil products transactions with Rosneft. Sales to associates are related to various entities. bp has commitments amounting to $10,777 million (2019 $11,198 million), primarily in relation to contracts with its associates for the purchase of transportation capacity. For information on capital commitments in relation to associates see Note 13. bp's share of impairment charges taken by associates in 2020 was $414 million (2019 $152 million). 194 bp Annual Report and Form 20-F 2020 18. Other investments Equity investmentsa Contingent consideration Other Financial statements Current Non-current Current 2020 — 317 16 333 913 1,682 151 2,746 — 122 47 169 $ million 2019 Non-current 571 476 229 1,276 a Approximately half of the group's equity investments are unlisted. Contingent consideration relates to amounts arising on disposals which are financial assets classified as measured at fair value through profit or loss. The fair value is determined using an estimate of discounted future cash flows that are expected to be received and is considered a level 3 valuation under the fair value hierarchy. Future cash flows are estimated based on inputs including oil and natural gas prices, production volumes and operating costs related to the disposed operations. The discount rate used is based on a risk-free rate adjusted for asset-specific risks. The contingent consideration principally relates to the disposal of our Alaskan business. 19. Inventories Crude oil Natural gas Emissions allowancesa Refined petroleum and petrochemical products Trading inventories Supplies 2020 4,498 265 1,297 8,791 14,851 292 15,143 1,730 16,873 132,104 $ million 2019 5,610 222 1,193 11,714 18,739 182 18,921 1,959 20,880 209,672 Cost of inventories expensed in the income statement a Comparative period has been re-presented to align with the current period. The inventory valuation at 31 December 2020 is stated net of a provision of $584 million (2019 $650 million) to write down inventories to their net realizable value, of which $216 million (2019 $290 million) relates to hydrocarbon inventories. The net credit to the income statement in the year in respect of inventory net realizable value provisions was $17 million (2019 $348 million credit), of which $71 million credit (2019 $309 million credit) related to hydrocarbon inventories. Trading inventories are valued using quoted benchmark prices adjusted as appropriate for location and quality differentials. They are predominantly categorized within level 2 of the fair value hierarchy. 20. Trade and other receivables Financial assets Trade receivables Amounts receivable from joint ventures and associates Receivables related to disposalsa Other receivables Non-financial assets Gulf of Mexico oil spill trust fund reimbursement asset Sales taxes and production taxes Other receivables 2020 $ million 2019 Current Non-current Current Non-current 12,926 339 1,291 2,628 17,184 32 557 175 764 17,948 19 10 2,402 637 3,068 — 504 779 1,283 4,351 19,424 672 159 3,166 23,421 201 640 180 1,021 24,442 22 2 125 701 850 — 538 759 1,297 2,147 a For further information see Note 4 - Disposals and Impairment. In both 2020 and 2019 the group entered into non-recourse arrangements to discount certain receivables in support of supply and trading activities and the management of credit risk. Trade and other receivables, other than certain receivables related to disposals, are predominantly non-interest bearing. See Note 29 for further information. bp Annual Report and Form 20-F 2020 195 21. Valuation and qualifying accounts 2020 2019 $ million 2018 Trade and other receivables Fixed asset investments Trade and other receivables Fixed asset investments Trade and other receivables Fixed asset investments 314 416 509 At 1 January – IAS 39 Adjustment on adoption of IFRS 9 At 1 January – IFRS 9 Charged to costs and expenses Charged to other accountsa Deductions At 31 December a Principally exchange adjustments. Valuation and qualifying accounts relating to trade and other receivables comprise expected credit loss allowances. The adjustment on adoption of IFRS 9 relates to the additional loss allowance required by IFRS 9's expected credit loss model. The expected credit loss allowance comprises $456 million (2019 $414 million, 2018 $327 million) relating to receivables that were credit-impaired at the end of the year and $99 million (2019 $95 million, 2018 $89 million) relating to receivables that were not credit-impaired at the end of the year. Whilst credit risk has increased since 31 December 2019, there has also been a significant reduction in the group's trade and other receivables balance. Therefore, the total expected credit loss allowances recognized as at 31 December 2020 have not significantly increased during the year. — 509 214 2 (170) 555 — 416 206 (2) (111) 509 — 235 28 — (14) 249 115 450 30 (12) (52) 416 249 — 249 103 — (166) 186 (85) 229 10 (1) (3) 235 235 335 Valuation and qualifying accounts relating to fixed asset investments comprise impairment provisions for investments in equity-accounted entities. The adjustment on adoption of IFRS 9 primarily relates to amounts provided against investments in equity instruments that were held at cost less impairment losses under IAS 39 but that are classified as measured at fair value through profit or loss under IFRS 9. In addition to the amounts presented above, expected loss allowances on cash and cash equivalents classified as measured at amortized cost totalled $11 million (2019 $11 million). For further information on the group's credit risk management policies and how the group recognizes and measures expected losses see Note 29. Valuation and qualifying accounts are deducted in the balance sheet from the assets to which they apply. 22. Trade and other payables Financial liabilities Trade payables Amounts payable to joint ventures and associates Payables for capital expenditure and acquisitions Payables related to the Gulf of Mexico oil spill Other payables Non-financial liabilities Sales taxes, customs duties, production taxes and social security Other payables 2020 $ million 2019 Current Non-current Current Non-current 23,157 1,364 2,297 1,399 5,041 33,258 2,103 653 2,756 36,014 — — 1,033 9,988 681 11,702 73 337 410 12,112 30,538 1,866 3,868 1,617 5,810 43,699 2,381 749 3,130 46,829 — — 1,196 10,863 133 12,192 33 401 434 12,626 Materially all of bp's trade payables have payment terms in the range of 30 to 60 days and give rise to operating cash flows. Trade and other payables, other than those relating to the Gulf of Mexico oil spill, are predominantly interest free. See Note 29 (c) for further information. Payables related to the Gulf of Mexico oil spill include amounts payable under the 2016 consent decree and settlement agreement with the United States and five Gulf coast states, including amounts payable for natural resource damages, state claims and Clean Water Act penalties. On a discounted basis the amounts included in payables related to the Gulf of Mexico oil spill for these elements of the agreements are $4,837 million payable over 12 years, $2,584 million payable over 13 years and $3,549 million payable over 12 years respectively at 31 December 2020. Reported within net cash provided by operating activities in the group cash flow statement is a net cash outflow of $1,786 million (2019 outflow of $2,694 million, 2018 outflow of $3,531 million) related to the Gulf of Mexico oil spill, which includes payments made in relation to these agreements. For 2018 payments under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident are also included. For full details of these agreements, see bp Annual Report and Form 20-F 2015 - Legal Proceedings. Payables related to the Gulf of Mexico oil spill at 31 December 2020 also include amounts payable for settled economic loss and property damage claims which are payable over a period of up to seven years. 196 bp Annual Report and Form 20-F 2020 23. Provisions At 1 January 2020 Exchange adjustments Increase (decrease) in existing provisions Write-back of unused provisions Unwinding of discount Utilization Reclassified to other payables Reclassified as liabilities directly associated with assets held for sale Deletions At 31 December 2020 Of which – current – non-current Decommissioning Environmental 15,110 96 (686) (11) 369 (7) (245) (10) (140) 14,476 428 14,048 1,620 9 297 (88) 39 (246) — — (2) 1,629 273 1,356 Litigation and claims 1,281 1 260 (12) 18 (508) (129) — (1) 910 260 650 Emissions 919 25 1,429 (17) — (687) — — — 1,669 1,621 48 Financial statements $ million Total 20,951 215 2,274 (469) 437 (1,826) (460) (10) (151) 20,961 3,761 17,200 Other 2,021 84 974 (341) 11 (378) (86) — (8) 2,277 1,179 1,098 The decommissioning provision comprises the future cost of decommissioning oil and natural gas wells, facilities and related pipelines. The environmental provision includes provisions for costs related to the control, abatement, clean-up or elimination of environmental pollution relating to soil, groundwater, surface water and sediment contamination. The litigation and claims category includes provisions for matters related to, for example, commercial disputes, product liability, and allegations of exposures of third parties to toxic substances. The emissions provision relates to the group’s obligation to transfer emissions allowances under relevant regulations. The provision will principally be settled through allowances already held as inventory in the group balance sheet. Included within the other category at 31 December 2020 are reinvent bp restructuring provisions for employee termination payments of $428 million. For information on significant estimates and judgements made in relation to provisions, see Provisions and contingencies within Note 1. Gulf of Mexico oil spill The group has recognized certain assets, payables and provisions and incurs certain residual costs relating to the Gulf of Mexico oil spill that occurred in 2010. In addition to the Litigation and claims narrative provided in this note, for further information see Notes 7, 9, 20, 22, 29, 33. Litigation and claims The Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) with the Plaintiff's Steering Committee (PSC) provides for a court-supervised settlement programme, the Deepwater Horizon Court Supervised Settlement Programme (DHCSSP), which commenced operation on 4 June 2012. On 22 January 2021, the United States District Court for the Eastern District of Louisiana issued an order determining the completion of all claims processing operations of the DHCSSP. The Court also concluded that future issues concerning EPD Settlement Agreement claims would be time barred under the DHCSSP and the claim administrator would proceed to complete post-closure administrative wind down activities. Amounts payable for settled economic and property damage claims are reported within payables - see Note 22 for further information. A separate claims administrator was appointed to pay medical claims and to implement other aspects of the Medical Benefits Class Action Settlement. For further information on the PSC settlements, see Legal proceedings on page 226. The litigation and claims provision reflects the latest estimate for the remaining costs associated with the Gulf of Mexico oil spill. The amounts payable may differ from the amount provided and the timing of payments is uncertain. 24. Pensions and other post-retirement benefits Most group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned. Pension benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and other types of schemes with committed pension benefit payments). For defined contribution plans, retirement benefits are determined by the value of funds arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such factors as an employee’s pensionable salary and length of service. Defined benefit plans may be funded or unfunded. The assets of funded plans are generally held in separately administered trusts. For information on significant estimates and judgements made in relation to accounting for these plans see Pensions and other post-retirement benefits in Note 1. The primary pension arrangement in the UK is a funded final salary pension plan under which retired employees draw the majority of their benefit as an annuity. This pension plan is governed by a corporate trustee whose board is composed of four member-nominated directors, four company-nominated directors, one independent director and one independent chairman nominated by the company. The trustee board is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as investment policies of the plan. The UK plan is closed to new joiners and is currently under consultation for closure to future accrual. As at 31 December 2020, it remained open to ongoing accrual for current members. New joiners in the UK are eligible for membership of a defined contribution plan. In the US, all pension benefits now accrue under a cash balance formula. Benefits previously accrued under final salary formulas are legally protected. Retiring US employees typically take their pension benefit in the form of a lump sum payment upon retirement. The plan is funded and its assets are overseen by a fiduciary Investment Committee. During 2020 the committee was composed of seven bp employees appointed by the president of bp Corporation North America Inc. (the appointing officer). The Investment Committee is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as the investment policies of the plan. US employees are also eligible to participate in a defined contribution (401k) plan in which employee contributions are matched with company contributions. In the US, group companies also provide post- retirement healthcare to most retired employees and their dependants (and, in certain cases, life insurance coverage); the entitlement to these benefits is usually based on the employee remaining in service until a specified age and completion of a minimum period of service. bp Annual Report and Form 20-F 2020 197 24. Pensions and other post-retirement benefits – continued In the Eurozone, there are defined benefit pension plans in Germany, France, the Netherlands and other countries. In Germany and France, the majority of the pensions are unfunded, in line with market practice. In Germany, the group’s largest Eurozone plan, employees receive a pension and also have a choice to supplement their core pension through salary sacrifice. For employees who joined since 2002, the core pension benefit is a career average plan with retirement benefits based on such factors as an employee’s pensionable salary and length of service. The returns on the notional contributions made by both the company and employees are based on the interest rate which is set out in German tax law. Retired German employees take their pension benefit typically in the form of an annuity. The German plans are governed by legal agreements between bp and the works council or between bp and the trade union. The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall due. During 2020 the aggregate level of contributions was $325 million (2019 $349 million and 2018 $610 million). The aggregate level of contributions in 2021 is expected to be approximately $400 million, and includes contributions in all countries that we expect to be required to make contributions by law or under contractual agreements, as well as an allowance for discretionary funding. For the primary UK plan there is a funding agreement between the group and the trustee. On an annual basis a schedule of contributions is agreed covering the next five years. Contractually committed funding amounted to $1,014 million at 31 December 2020, all of which relates to future service. This amount is included in the group’s committed cash flows relating to pensions and other post-retirement benefit plans as set out in the table of contractual obligations on page 307. The surplus relating to the primary UK pension plan is recognized on the balance sheet on the basis that the company is entitled to a refund of any remaining assets once all members have left the plan. Minimum pension funding in the US is determined by legislation and is supplemented by discretionary contributions. No contributions were made into the primary US pension plan in 2020 and no statutory funding requirement is expected in the next 12 months. The surplus relating to the primary US fund is recognized on the balance sheet on the basis that economic benefit can be gained from the surplus through a reduction in future contributions. There was no minimum funding requirement for the US plan, and no significant minimum funding requirements in other countries at 31 December 2020. The obligation and cost of providing pensions and other post-retirement benefits is assessed annually using the projected unit credit method. The date of the most recent actuarial review was 31 December 2020. The UK plans are subject to a formal actuarial valuation every three years; valuations are required more frequently in many other countries.The most recent formal actuarial valuation of the UK pension plans was as at 31 December 2017, and a valuation as at 31 December 2020 is currently underway. A valuation of the US plan and largest Eurozone plans are carried out annually. The material financial assumptions used to estimate the benefit obligations of the various plans are set out below. The assumptions are reviewed by management at the end of each year and are used to evaluate the accrued benefit obligation at 31 December and pension expense for the following year. Financial assumptions used to determine benefit obligation Discount rate for plan liabilities Rate of increase in salaries Rate of increase for pensions in payment Rate of increase in deferred pensions Inflation for plan liabilities Financial assumptions used to determine benefit expense Discount rate for plan service cost Discount rate for plan other finance expense Inflation for plan service cost 2020 1.4 3.6 2.8 2.8 2.9 2020 2.1 2.1 2.6 2019 2.1 3.4 2.7 2.7 2.7 2019 3.0 2.9 3.1 UK 2018 2.9 3.8 3.0 3.0 3.1 UK 2018 2.6 2.5 3.1 2020 2.2 4.1 — — 1.7 2020 3.2 3.1 1.5 2019 3.1 3.9 — — 1.5 2019 4.2 4.1 1.5 US 2018 4.1 3.9 — — 1.5 US 2018 3.6 3.5 1.7 2020 1.0 2.9 1.3 0.5 1.5 2020 1.8 1.3 1.7 % Eurozone 2018 2.0 3.1 1.5 0.5 1.7 % Eurozone 2018 2.4 1.9 1.6 2019 1.3 3.1 1.5 0.5 1.7 2019 2.5 2.0 1.7 The discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and the Eurozone we use yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans are based on the difference between the yields on index-linked and fixed-interest long-term government bonds. In other countries, including the Eurozone, we use this approach, or advice from the local actuary depending on the information available. The inflation assumptions are used to determine the rate of increase for pensions in payment and the rate of increase in deferred pensions where there is such an increase. The assumptions for the rate of increase in salaries are based on the inflation assumption plus an allowance for expected long-term real salary growth. These include an allowance for promotion-related salary growth, of up to 0.8% depending on country. 198 bp Annual Report and Form 20-F 2020 Financial statements 24. Pensions and other post-retirement benefits – continued In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best practice in the countries in which we provide pensions and have been chosen with regard to applicable published tables adjusted where appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. bp’s most substantial pension liabilities are in the UK, the US and the Eurozone where our mortality assumptions are as follows: Mortality assumptions Life expectancy at age 60 for a male currently aged 60 Life expectancy at age 60 for a male currently aged 40 Life expectancy at age 60 for a female currently aged 60 Life expectancy at age 60 for a female currently aged 40 2020 2019 UK 2018 2020 2019 US 2018 Years Eurozone 2020 2019 2018 26.9 27.3 27.4 24.7 24.9 25.1 25.7 25.7 25.6 28.4 28.9 28.9 26.4 26.7 26.9 28.2 28.3 28.1 28.8 28.7 28.8 27.7 28.0 28.5 29.0 29.1 29.0 30.4 30.5 30.6 29.2 29.7 30.1 31.2 31.2 31.2 Pension plan assets are generally held in trusts, the primary objective of which is to accumulate assets sufficient to meet the obligations of the plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management. A significant proportion of the assets are held in equities, which are expected to generate a higher level of return over the long term, with an acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment portfolios are highly diversified. The trustee’s long-term investment objective for the primary UK plan as it matures is to invest in assets whose value changes in the same way as the plan liabilities, in order to reduce the level of funding risk. To move towards this objective, the UK plan uses a liability driven investment (LDI) approach for part of the portfolio, investing primarily in government bonds to achieve this matching effect for the most significant plan liability assumptions of interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements, whereby the plan borrows money using existing bonds as security and which will be bought back at a specified price at an agreed future date. The funds raised are used to invest in further bonds to increase the proportion of assets which match the plan liabilities. The borrowings are shown separately in the analysis of pension plan assets in the table below. For the primary UK pension plan there is an agreement with the trustee to increase the proportion of assets with liability matching characteristics over time primarily by reducing the proportion of plan assets held as equities and increasing the proportion held as bonds. During 2020, the UK plan switched 11% of plan assets from equities to bonds (2019 2%). There is a similar agreement in place for the primary US plan, although no switches have taken place in 2019 or 2020. The current asset allocation policy for the major plans at 31 December 2020 was as follows: Asset category Total equity (including private equity) Bonds/cash (including LDI) Property/real estate UK % 17 76 7 US % 40 60 — The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2020 were $4,217 million (2019 $4,804 million) of government-issued nominal bonds and $24,576 million (2019 $19,462 million) of index-linked bonds. Some of the group’s pension plans in the Eurozone and other countries use derivative financial instruments as part of their asset mix to manage the level of risk. The fair value of these instruments is included in other assets in the table below. The group’s main pension plans do not invest directly in either securities or property/real estate of the company or of any subsidiary. The fair values of the various categories of assets held by the defined benefit plans at 31 December are presented in the table below, including the effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on page 201. bp Annual Report and Form 20-F 2020 199 24. Pensions and other post-retirement benefits – continued Fair value of pension plan assets At 31 December 2020 Listed equities – developed markets    – emerging markets Private equityc Government issued nominal bondsd Government issued index-linked bondsd Corporate bondsd Propertye Cash Other Debt (repurchase agreements) used to fund liability driven investments At 31 December 2019 Listed equities – developed markets    – emerging markets Private equityc Government issued nominal bondsd Government issued index-linked bondsd Corporate bondsd Propertye Cash Other Debt (repurchase agreements) used to fund liability driven investments At 31 December 2018 Listed equities – developed markets    – emerging markets Private equityc Government issued nominal bondsd Government issued index-linked bondsd Corporate bondsd Propertye Cash Other Debt (repurchase agreements) used to fund liability driven investments UKa USb Eurozone Other 5,008 418 2,899 4,303 24,576 8,906 2,553 1,392 795 (9,387) 41,463 6,285 1,096 2,675 4,884 19,462 6,132 2,507 426 98 (7,436) 36,129 5,191 950 2,792 4,263 17,491 4,606 2,311 376 116 (6,011) 1,112 115 1,604 1,839 — 2,398 — 267 131 — 7,466 1,290 124 1,474 2,100 — 2,304 — 289 74 — 7,655 1,238 63 1,495 2,072 — 2,184 6 73 64 — 542 68 — 1,111 107 587 110 51 104 — 2,680 495 61 — 959 100 569 96 33 30 — 2,343 413 65 — 895 102 506 57 42 32 — 318 70 4 616 — 279 28 163 30 — 1,508 371 64 3 572 — 256 27 93 26 — 1,412 306 56 4 533 — 243 25 83 40 — $ million Total 6,980 671 4,507 7,869 24,683 12,170 2,691 1,873 1,060 (9,387) 53,117 8,441 1,345 4,152 8,515 19,562 9,261 2,630 841 228 (7,436) 47,539 7,148 1,134 4,291 7,763 17,593 7,539 2,399 574 252 (6,011) 32,085 a Bonds held by the UK pension plans are denominated in sterling. Property held by the UK pension plans is in the United Kingdom. b Bonds held by the US pension plans are denominated in US dollars. c Private equity is valued at fair value based on the most recent transaction price or third-party net asset, revenue or earnings based valuations that generally result in the use of significant unobservable 2,112 7,195 1,290 42,682 inputs. d Bonds held by pension plans are valued using quoted prices in active markets. e Properties are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party professional valuers that generally result in the use of significant unobservable inputs. 200 bp Annual Report and Form 20-F 2020 24. Pensions and other post-retirement benefits – continued Analysis of the amount charged to profit or loss Current service costa Past service costb Settlementb Operating charge relating to defined benefit plans Payments to defined contribution plans Total operating charge Interest income on plan assetsa Interest on plan liabilities Other finance (income) expense Analysis of the amount recognized in other comprehensive income Actual asset return less interest income on plan assets Change in financial assumptions underlying the present value of the plan liabilities Change in demographic assumptions underlying the present value of the plan liabilities Experience gains and losses arising on the plan liabilities Remeasurements recognized in other comprehensive income Movements in benefit obligation during the year Benefit obligation at 1 January Exchange adjustments Operating charge relating to defined benefit plans Interest cost Contributions by plan participantsc Benefit payments (funded plans)d Benefit payments (unfunded plans)d Reclassified as assets held for sale Disposals Remeasurements Benefit obligation at 31 Decembera e Movements in fair value of plan assets during the year Fair value of plan assets at 1 January Exchange adjustments Interest income on plan assetsa f Contributions by plan participantsc Contributions by employers (funded plans) Benefit payments (funded plans)d Reclassified as assets held for sale Remeasurementsf Fair value of plan assets at 31 Decemberg Surplus (deficit) at 31 December Represented by Asset recognized Liability recognized The surplus (deficit) may be analysed between funded and unfunded plans as follows Funded Unfunded The defined benefit obligation may be analysed between funded and unfunded plans as follows Funded Unfunded Financial statements UK US Eurozone Other $ million 2020 Total 250 (48) — 202 49 251 (725) 596 (129) 292 (66) (23) 203 183 386 (210) 289 79 4,108 1,041 (4,207) (1,178) 29 (101) (209) 585 54 540 103 12 10 125 2 127 (33) 97 64 104 (143) 56 (178) (161) 683 38 (122) (20) (14) (1) 547 17 272 38 55 819 (40) (1,008) 59 1,041 33 19 38 5,291 (42) (5,570) 666 (217) 170 (4) 8 — 29,780 10,119 7,353 1,826 49,078 64 2,087 1,303 — 17 202 547 203 59 1,041 596 289 34 11 21 — (86) (2,899) (1,291) (1,441) (504) (34) (197) (56) — (1) — (35) (35) 38 5,121 3,568 1,250 34,171 10,187 8,161 1,895 54,414 720 125 97 2 (81) (265) (55) — 265 (8) — — 36,129 7,655 2,343 1,412 47,539 64 1,881 1,582 — 40 1,008 725 210 34 11 21 — 29 325 189 8 (86) (2,899) (1,291) (1,441) (62) — (7) 4,108 1,041 38 5,291 41,463 7,466 2,680 1,508 53,117 (387) (1,297) 7,292 (2,721) (5,481) 235 33 2 99 (81) (55) 104 — 7,567 59 269 (275) (2,990) (5,540) 7,292 (2,721) (5,481) 62 7,957 (449) (9,254) (387) (1,297) 7,564 (109) 269 (272) (2,990) (5,372) 7,292 (2,721) (5,481) (58) 7,666 (329) (8,963) (387) (1,297) (33,899) (7,197) (2,789) (1,566) (45,451) (329) (8,963) (34,171) (10,187) (8,161) (1,895) (54,414) (272) (2,990) (5,372) a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation. b Past service credits represent curtailment gains arising from restructuring programmes in the UK, US and other countries, whilst past service costs and settlements in the Eurozone represent charges for special termination benefits reflecting the increased liability arising as a result of early retirements. Settlement costs in the US resulted from a pension risk transfer to an external carrier for a group of small benefit retirees. c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice. d The benefit payments amount shown above comprises $2,935 million benefits and $428 million settlements, plus $40 million of plan expenses incurred in the administration of the benefit. e The benefit obligation for the US is made up of $7,728 million for pension liabilities and $2,459 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical liabilities). The benefit obligation for the Eurozone includes $5,060 million for pension liabilities in Germany which is largely unfunded. f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above. g The fair value of plan assets includes borrowings related to the LDI programme as described on page 199. bp Annual Report and Form 20-F 2020 201 24. Pensions and other post-retirement benefits – continued Analysis of the amount charged to profit or loss Current service costa Past service costb Settlementb Operating charge relating to defined benefit plans Payments to defined contribution plans Total operating charge Interest income on plan assetsa Interest on plan liabilities Other finance (income) expense Analysis of the amount recognized in other comprehensive income Actual asset return less interest income on plan assets Change in financial assumptions underlying the present value of the plan liabilities Change in demographic assumptions underlying the present value of the plan liabilities Experience gains and losses arising on the plan liabilities Remeasurements recognized in other comprehensive income Movements in benefit obligation during the year Benefit obligation at 1 January Exchange adjustments Operating charge relating to defined benefit plans Interest cost Contributions by plan participantsc Benefit payments (funded plans)d Benefit payments (unfunded plans)d Reclassified as assets held for sale Disposals Remeasurements Benefit obligation at 31 Decembera e Movements in fair value of plan assets during the year Fair value of plan assets at 1 January Exchange adjustments Interest income on plan assetsa f Contributions by plan participantsc Contributions by employers (funded plans) Benefit payments (funded plans)d Reclassified as assets held for sale Remeasurementsf Fair value of plan assets at 31 Decemberg Surplus (deficit) at 31 December Represented by Asset recognized Liability recognized The surplus (deficit) may be analysed between funded and unfunded plans as follows Funded Unfunded The defined benefit obligation may be analysed between funded and unfunded plans as follows Funded Unfunded UK US Eurozone Other $ million 2019 Total 227 2 — 229 42 271 (909) 757 (152) 263 — (13) 250 188 438 (285) 387 102 2,945 1,079 (1,036) 91 (22) 112 (2,294) 136 (57) 730 81 5 8 94 7 101 (43) 133 90 220 (748) 3 6 (519) 609 38 6 (1) (5) — 610 37 275 38 885 75 (46) (1,283) 69 1,346 63 23 97 4,341 (4,170) (92) 226 (4) (69) 4 328 5 26,830 9,696 6,906 1,686 45,118 942 826 26 229 37 610 757 69 1,346 20 28 6 (1,207) (2,188) (75) (6) (499) (15) — (146) — — — (30) 92 4,013 2,215 29,780 10,119 7,353 1,826 49,078 — 250 387 — (830) (205) (146) — 967 (142) 94 133 2 (76) (273) — (30) 739 32,085 7,195 2,112 1,290 42,682 24 1,122 1,141 — 46 1,283 909 285 6 28 20 — 24 349 236 4 (75) (2,188) (1,207) (830) (78) — — (78) 2,945 1,079 97 4,341 36,129 7,655 2,343 1,412 47,539 (1,539) 6,349 (43) 43 2 85 (76) — 220 (5,010) (2,464) (414) 6,588 (239) 6,349 387 (2,851) (2,464) 27 (5,037) (5,010) 51 7,053 (8,592) (1,539) (465) (414) 6,588 (239) 6,349 387 (2,851) (2,464) (136) (4,874) (5,010) (87) 6,752 (8,291) (1,539) (327) (414) (29,541) (239) (7,268) (2,851) (29,780) (10,119) (2,479) (4,874) (7,353) (1,499) (40,787) (8,291) (1,826) (49,078) (327) a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of administering other post-retirement benefit plans are included in the benefit obligation. b Past service costs and settlements have arisen from restructuring programmes and represent charges for special termination benefits reflecting the increased liability arising as a result of early retirements. Settlements in the US are the result of a buy-out transaction for the pensions of a group of low value annuitants. c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice. d The benefit payments amount shown above comprises $2,304 million benefits and $346 million settlements, plus $37 million of plan expenses incurred in the administration of the benefit. e The benefit obligation for the US is made up of $7,789 million for pension liabilities and $2,330 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical liabilities). The benefit obligation for the Eurozone includes $4,567 million for pension liabilities in Germany which is largely unfunded. f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above. g The fair value of plan assets includes borrowings related to the LDI programme as described on page 199. 202 bp Annual Report and Form 20-F 2020 Financial statements UK US Eurozone Other $ million 2018 Total 24. Pensions and other post-retirement benefits – continued Analysis of the amount charged to profit or loss Current service costa Past service costb Settlement 295 15 — 310 38 348 (868) 774 (94) 299 — — 299 178 477 (262) 369 107 84 9 17 110 5 115 (44) 136 92 721 43 28 4 17 — 766 47 40 261 87 1,027 (45) (1,219) 67 1,346 127 22 Operating charge relating to defined benefit plans Payments to defined contribution plans Total operating charge Interest income on plan assetsa Interest on plan liabilities Other finance (income) expense Analysis of the amount recognized in other comprehensive income Actual asset return less interest income on plan assets Change in financial assumptions underlying the present value of the plan liabilities Change in demographic assumptions underlying the present value of the plan liabilities Experience gains and losses arising on the plan liabilities Remeasurements recognized in other comprehensive income a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of (722) 1,770 123 520 1,691 (69) 14 (42) (43) (140) (256) 945 (9) 41 721 (36) (1,083) 65 2,794 79 527 45 2,317 7 9 administering other post-retirement benefit plans are included in the benefit obligation. b Past service costs have arisen from restructuring programmes and represent charges for special termination benefits representing the increased liability arising as a result of early retirements mostly in the UK and Eurozone. Sensitivity analysis The discount rate, inflation, salary growth and the mortality assumptions all have a significant effect on the amounts reported. A one-percentage point change, in isolation, in certain assumptions as at 31 December 2020 for the group’s pensions and other post-retirement benefit expense would have had the effects shown in the tables below. The effects shown for the expense in 2021 comprise the total of current service cost and net finance income or expense. Discount ratea Effect on expense in 2021 Effect on obligation at 31 December 2020 Inflation rateb Effect on expense in 2021 Effect on obligation at 31 December 2020 Salary growth Effect on expense in 2021 Effect on obligation at 31 December 2020 UK US Eurozone Increase Decrease Increase Decrease Increase Decrease $ million One percentage point (274) 198 (5,658) 7,690 (51) 36 (1,272) 1,556 (2) (11) (1,149) 1,452 145 (116) 5,337 (4,482) 31 670 (27) (585) 10 66 12 82 (8) (55) 35 1,025 (28) (870) (10) (69) 7 91 (7) (89) a The amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation. b The amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions. Longevity Effect on expense in 2021 Effect on obligation at 31 December 2020 $ million One year increase UK US Eurozone 28 1,406 5 150 8 333 Estimated future benefit payments and the weighted average duration of defined benefit obligations The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2030 and the weighted average duration of the defined benefit obligations at 31 December 2020 are as follows: Estimated future benefit payments 2021 2022 2023 2024 2025 2026-2030 UK 1,072 1,086 1,120 1,141 1,135 5,939 US 1,568 612 593 575 583 2,696 Eurozone 357 346 339 332 328 1,521 Other 112 109 107 108 107 528 $ million Total 3,109 2,153 2,159 2,156 2,153 10,684 Years Weighted average duration 19.2 13.8 16.1 12.7 bp Annual Report and Form 20-F 2020 203     25. Cash and cash equivalents Cash Triparty repos and term bank deposits Cash equivalents (excluding triparty repos and term bank deposits) 2020 6,235 17,368 7,508 31,111 $ million 2019 6,462 10,296 5,714 22,472 Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; deposits of three months or less with banks and similar institutions; money market funds and commercial paper. The carrying amounts of cash, triparty repos and term bank deposits approximate their fair values. Substantially all of the other cash equivalents are categorized within level 1 of the fair value hierarchy. Cash and cash equivalents at 31 December 2020 includes $1,917 million (2019 $1,676 million) that is restricted. The restricted cash balances include amounts required to cover initial margin on trading exchanges and certain cash balances which are subject to exchange controls. The group holds $3,890 million (2019 $4,678 million) of cash and cash equivalents outside the UK and it is not expected that any significant tax will arise on repatriation. 26. Finance debt Borrowings Current 9,359 Non-current 63,305 2020 Total 72,664 Current 10,487 Non-current 57,237 $ million 2019 Total 67,724 The main elements of current borrowings are the current portion of long-term borrowings that is due to be repaid in the next 12 months of $8,122 million (2019 $8,166 million) and issued commercial paper of $1,004 million (2019 $2,279 million). Finance debt does not include accrued interest, which is reported within other payables. As part of actively managing its debt portfolio, during the year the group bought back $4.0 billion equivalent (2019 $nil) of euro and sterling bonds and terminated derivatives associated with the debt bought back. In addition on 18 December 2020 the group exercised its option to redeem finance debt with an outstanding aggregate principal amount of $2.0 billion on 22 January 2021. On 19 March 2021 the group bought back a further $1.9 billion equivalent of euro and sterling bonds and terminated associated derivatives. These transactions have no significant impact on net debt or gearing. The following table shows the weighted-average interest rates achieved through a combination of borrowings and derivative financial instruments entered into to manage interest rate and currency exposures. US dollar Other currencies US dollar Other currencies Fixed rate debt Floating rate debt Total Weighted average interest rate % Weighted average time for which rate is fixed Years 3 6 4 6 8 9 5 10 Weighted average interest rate % 2 5 3 7 Amount $ million 39,452 178 39,630 25,634 183 25,817 Amount $ million 32,891 143 33,034 41,871 36 41,907 Amount $ million 2020 72,343 321 72,664 2019 67,505 219 67,724 Fair values The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet. Long-term borrowings in the table below include the portion of debt that matures in the 12 months from 31 December 2020, whereas in the group balance sheet the amount is reported within current finance debt. The carrying amount of the group’s short-term borrowings, comprising mainly of commercial paper, approximates their fair value. The fair values of the significant majority of the group’s long-term borrowings are determined using quoted prices in active markets, and so fall within level 1 of the fair value hierarchy. Where quoted prices are not available, quoted prices for similar instruments in active markets are used and such measurements are therefore categorized in level 2 of the fair value hierarchy. Short-term borrowings Long-term borrowings Total finance debt 204 bp Annual Report and Form 20-F 2020 2020 Carrying amount 1,237 71,427 72,664 Fair value 2,321 67,055 69,376 Fair value 1,237 74,855 76,092 $ million 2019 Carrying amount 2,321 65,403 67,724 27. Capital disclosures and net debt The group defines capital as total equity plus net debt. We maintain our financial framework to support the pursuit of value growth for shareholders, while ensuring a secure financial base. The group monitors capital on basis of gearing, that is, the ratio of net debt to net debt plus equity. Net debt is calculated as finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt for which hedge accounting is applied, less cash and cash equivalents. Net debt and gearing are non-GAAP measures. bp believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing enables investors to see how significant net debt is relative to total equity. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. All components of equity are included in the denominator of the calculation. Financial statements At 31 December 2020, gearing was 31.3% (2019 31.1%). At 31 December Finance debt Less: fair value asset (liability) of hedges related to finance debta Less: cash and cash equivalents Net debt Total equityb Gearing 2020 $ million 2019 72,664 2,612 70,052 31,111 38,941 85,568 67,724 (190) 67,914 22,472 45,442 100,708 31.3 % 31.1 % a Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $236 million (2019 liability of $601 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments. b Total equity in 2020 includes perpetual hybrid bonds issued on 17 June 2020. See Note 32 for further information. An analysis of changes in liabilities arising from financing activities is provided below. At 1 January 2020 Exchange adjustments Net financing cash flow Fair value (gains) losses New and remeasured leases/joint operation payables Other movements At 31 December 2020 Finance debt 67,724 349 1,589 2,612 — 390 72,664 Currency swapsa Lease liabilities 918 — (226) (3,734) — 77 (2,965) 9,722 181 (2,442) — 1,579 222 9,262 Net partner payable for leases entered into on behalf of joint operations 290 4 (40) — 20 (7) 267 $ million Total liabilities arising from financing activities 78,654 534 (1,119) (1,122) 1,599 682 79,228 At 1 January 2019 Adjustment on adoption of IFRS16 Exchange adjustments Net financing cash flow Fair value (gains) losses New and remeasured leases/joint operations payables Other movements At 31 December 2019 a Previously reported in this column were hedge accounted derivatives related to finance debt. This has been updated in 2020 as described below and comparatives provided on a consistent basis. 65,132 — (62) 1,671 924 — 59 67,724 667 9,233 (4) (2,372) — 2,614 (416) 9,722 1,486 — — 2 (570) — — 918 — 217 8 (14) — 82 (3) 290 67,285 9,450 (58) (713) 354 2,696 (360) 78,654 Currency swaps include cross currency interest rate swaps. The balances above do not include accrued interest, which is reported within other receivables and other payables on the balance sheet and for which the associated cash flows are presented as operating cash flows in the group cash flow statement. The currency swaps are reported on the balance sheet within the headings 'Derivative financial instruments' and are subsets of both derivatives held for trading and derivatives designated in fair value hedge relationships as detailed in Note 30. When hedge accounting is applied to these derivatives they are included in the calculation of net debt shown above. bp Annual Report and Form 20-F 2020 205 28. Leases The group leases a number of assets as part of its activities. This primarily includes drilling rigs in the Upstream segment and retail service stations, oil depots and storage tanks in the Downstream segment as well as office accommodation and vessel charters across the group. The weighted-average remaining lease term for the total lease portfolio is around 8 years (2019 9 years). Some leases will have payments that vary with market interest or inflation rates. Certain leases contain residual value guarantees, which may be triggered in certain circumstances such as if market values have significantly declined at the conclusion of the lease. The table below shows the timing of the undiscounted cash outflows for the lease liabilities included on the balance sheet. Undiscounted lease liability cash flows due: Within 1 year 1 to 2 years 2 to 3 years 3 to 4 years 4 to 5 years 5 to 10 years Over 10 years Impact of discounting Lease liabilities at 31 December Of which – current – non-current 2020 2,262 1,672 1,340 1,025 878 2,192 1,515 10,884 (1,622) 9,262 1,933 7,329 $ million 2019 2,514 1,839 1,364 1,105 876 2,427 1,174 11,299 (1,577) 9,722 2,067 7,655 The group may enter into lease arrangements a number of years before taking control of the underlying asset due to construction lead times or to secure future operational requirements. The total undiscounted amount for future commitments for leases not yet commenced as at 31 December 2020 is $5,309 million (2019 $5,688 million). The majority of this future commitment relates to the floating LNG vessel to service the Greater Tortue Ahmeyim project from 2023. Total cash outflow for amounts included in lease liabilitiesa Expense for variable payments not included in the lease liability Short-term lease expense Additions to right-of-use assets in the period Gain on sale and leaseback transactions a The cash outflows for amounts not included in lease liabilities approximate the income statement expense disclosed above. An analysis of right-of-use assets and depreciation is provided in Note 12. An analysis of lease interest expense is provided in Note 7. 2020 2,779 41 621 1,714 187 29. Financial instruments and financial risk factors The accounting classification of each category of financial instruments and their carrying amounts are set out below. $ million 2019 2,709 67 331 2,542 — $ million Mandatorily measured at fair value through profit or loss Measured at amortized cost Derivative hedging instruments Total carrying amount — 929 20,252 — 24,905 (44,960) — (5,502) (9,262) (72,664) (86,302) 3,079 369 — 10,049 6,206 — (8,320) — — — 11,383 — — — 2,698 — — (82) — — — 2,616 3,079 1,298 20,252 12,747 31,111 (44,960) (8,402) (5,502) (9,262) (72,664) (72,303) Note 18 20 30 25 22 30 28 26 At 31 December 2020 Financial assets Other investments Loans Trade and other receivables Derivative financial instruments Cash and cash equivalents Financial liabilities Trade and other payables Derivative financial instruments Accruals Lease liabilities Finance debt 206 bp Annual Report and Form 20-F 2020 29. Financial instruments and financial risk factors – continued At 31 December 2019 Financial assets Other investments Loans Trade and other receivables Derivative financial instruments Cash and cash equivalents Financial liabilities Trade and other payables Derivative financial instruments Accruals Lease liabilities Finance debt Financial statements Measured at amortized cost Mandatorily measured at fair value through profit or loss Derivative hedging instruments Total carrying amount $ million — 906 24,271 — 18,183 (55,891) — (6,062) (9,722) (67,724) (96,039) 1,445 63 — 9,984 4,289 — (8,122) — — — 7,659 — — — 483 — — (676) — — — (193) 1,445 969 24,271 10,467 22,472 (55,891) (8,798) (6,062) (9,722) (67,724) (88,573) Note 18 20 30 25 22 30 28 26 The fair value of finance debt is shown in Note 26. For all other financial instruments within the scope of IFRS 9, the carrying amount is either the fair value, or approximates the fair value. Information on gains and losses on derivative financial assets and financial liabilities classified as measured at fair value through profit or loss is provided in the derivative gains and losses section of Note 30. Fair value gains and losses related to other assets and liabilities classified as measured at fair value through profit or loss totalled a net gain of $367 million (2019 net loss of $129 million). Dividend income of $17 million (2019 $20 million) from investments in equity instruments classified as measured at fair value through profit or loss is presented within other income - see Note 7. Interest income and expenses arising on financial instruments are disclosed in Note 7. Financial risk factors The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments including market risks relating to commodity prices; foreign currency exchange rates and interest rates; credit risk; and liquidity risk. The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The GFRC is chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the group finance, tax and the integrated supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk governance framework for the group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to the board, that the group’s financial risk-taking activity is governed by appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with group policies and group risk appetite. The group’s trading activities in the oil, natural gas, LNG and power markets are managed within the integrated supply and trading function. Treasury holds foreign exchange and interest-rate products in the financial markets to hedge group exposures related to debt and hybrid bond issuance; the compliance, control, and risk management processes for these activities are managed within the treasury function. All other foreign exchange and interest rate activities within financial markets are performed within the integrated supply and trading function and are also underpinned by the compliance, control and risk management infrastructure common to the activities of bp’s integrated supply and trading function. All derivative activity is carried out by specialist teams that have the appropriate skills, experience and supervision. These teams are subject to close financial and management control. The integrated supply and trading function maintains formal governance processes that provide oversight of market risk, credit risk and operational risk associated with trading activity. A policy and risk committee approves value-at-risk delegations, reviews incidents and validates risk-related policies, methodologies and procedures. A commitments committee approves the trading of new products, instruments and strategies and material commitments. In addition, the integrated supply and trading function undertakes derivative activity for risk management purposes under a control framework as described more fully below. (a) Market risk Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The primary commodity price risks that the group is exposed to include oil, natural gas and power prices that could adversely affect the value of the group’s financial assets, liabilities or expected future cash flows. The group enters into derivatives in a well-established entrepreneurial trading operation. In addition, the group has developed a control framework aimed at managing the volatility inherent in certain of its natural business exposures. In accordance with the control framework the group enters into various transactions using derivatives for risk management purposes. The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed below. (i) Commodity price risk The group’s integrated, supply and trading function is responsible for delivering value across the overall crude, oil products, gas and power supply chains. As such, it routinely enters into spot and term physical commodity contracts in addition to optimising physical storage, pipeline and transportation capacity. These activities expose the group to commodity price risk which is managed by entering into oil and natural gas swaps, options and futures. The group measures market risk exposure arising from its trading positions in liquid periods using value-at-risk techniques based on Variance/ Covariance or Monte Carlo simulation models. These techniques make a statistical assessment of the market risk arising from possible future changes in market prices over a one-day holding period within a 95% confidence level. The value-at-risk measure is supplemented by stress testing and scenario analysis through simulating the financial impact of certain physical, economic and geo-political scenarios. Trading activity occurring in liquid periods is bp Annual Report and Form 20-F 2020 207 29. Financial instruments and financial risk factors – continued subject to value-at-risk and other limits for each trading activity and the aggregate of all trading activity. The board has delegated a limit of $100 million (2019 $100 million) value at risk in support of this trading activity. Alternative measures are used to monitor exposures which are outside liquid periods and for which value-at-risk techniques are not appropriate. (ii) Foreign currency exchange risk Since bp has global operations, fluctuations in foreign currency exchange rates can have a significant effect on the group’s reported results and future expenditure commitments. The effects of most exchange rate fluctuations are absorbed in business operating results through changing cost competitiveness, lags in market adjustment to movements in rates and translation differences accounted for on specific transactions. For this reason, the total effect of exchange rate fluctuations is not identifiable separately in the group’s reported results. The main underlying economic currency of the group’s cash flows is the US dollar. This is because bp’s major product, oil, is priced internationally in US dollars. bp’s foreign currency exchange management policy is to limit economic and material transactional exposures arising from currency movements against the US dollar. The group co- ordinates the handling of foreign currency exchange risks centrally, by netting off naturally-occurring opposite exposures wherever possible and then managing any material residual foreign currency exchange risks. Most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2020, the total foreign currency borrowings not swapped into US dollars amounted to $321 million (2019 $219 million). During the year the group issued perpetual subordinated hybrid bonds in euro, sterling and US dollars. Whilst the contractual terms of these instruments allow the group to defer coupon payments and the repayment of principal indefinitely, the group has chosen to manage the foreign currency exposure relating to the non-US dollar hybrid bonds to their respective first call periods. The group manages the net residual foreign currency exposures by constantly reviewing the foreign currency economic value at risk and aims to manage such risk to keep the 12-month foreign currency value at risk below $400 million. At no point over the past three years did the value at risk exceed the maximum risk limit. A continuous assessment is made in respect to the group’s foreign currency exposures to capture hedging requirements. During the year, hedge accounting was applied to foreign currency exposure to highly probable forecast capital expenditure commitments. The group fixes the US dollar cost of non-US dollar supplies by using currency forwards for the highly probable forecast capital expenditure; the exposures are in sterling, euro, Australian dollar and Korean won. At 31 December 2020 the most significant open contracts in place were for $124 million sterling (2019 $106 million sterling). Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading value-at- risk techniques as explained in (i) commodity price risk above. (iii) Interest rate risk bp is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial instruments, principally finance debt. While the group issues debt and hybrid bonds in a variety of currencies based on market opportunities, it uses derivatives to swap the economic exposure to a floating rate basis, mainly to US dollar floating, but in certain defined circumstances maintains a US dollar fixed rate exposure for a proportion of debt. The proportion of floating rate debt net of interest rate swaps at 31 December 2020 was 45% of total finance debt outstanding (2019 62%). The weighted average interest rate on finance debt at 31 December 2020 was 3% (2019 3%) and the weighted average maturity of fixed rate debt was eight years (2019 five years). The group’s earnings are sensitive to changes in interest rates on the element of the group’s finance debt that has been swapped to floating rates. If the interest rates applicable to these floating rate instruments were to have changed by one percentage point on 1 January 2021, it is estimated that the group’s finance costs for 2021 would change by approximately $330 million (2019 $419 million). Financial authorities in the US, UK, EU and other territories are currently undertaking reviews of key interest rate benchmarks such as the London Inter- bank Offered Rate (LIBOR) with a view to replacing them with alternative benchmarks. bp is significantly exposed to benchmark interest rate components; predominantly USD LIBOR, GBP LIBOR, EURIBOR and CHF LIBOR. Following the completion of consultation processes, these financial authorities have begun to announce the timing of both benchmark transitions and continued publication of synthetic benchmarks. In October 2020 the International Swaps and Derivatives Association (ISDA) published its fallback protocol containing clauses to amend derivative contracts on the cessation of LIBOR should an entity and its counterparties adhere to the protocol. The protocol’s pricing mechanism is at fair market value and bp has signed up to the protocol as this removes transition uncertainty for any interest rate and cross-currency interest rate swap contracts of the Group without fall-back clauses. The ISDA fallback protocol is expected to increase market activity and certainty such that corporates can finalize their plans for implementation of the transition. bp continues to monitor regulatory and market developments over the course of the transition. In response to the cessation of the interbank offered rates (IBORs), bp has set up an internal working group to monitor market developments and manage the transition to alternative benchmark rates and is currently assessing the impact on contracts and arrangements that are linked to existing interest rate benchmarks, for example, borrowings, leases and derivative contracts. bp is also participating on external committees and task forces dedicated to interest rate benchmark reform. (b) Credit risk Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss to the group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally from credit exposures to customers relating to outstanding receivables. Credit exposure also exists in relation to guarantees issued by group companies under which the outstanding exposure incremental to that recognized on the balance sheet at 31 December 2020 was $1,405 million (2019 $692 million) in respect of liabilities of joint ventures and associates and $661 million (2019 $523 million) in respect of liabilities of other third parties. The group has a credit policy, approved by the CFO that is designed to ensure that consistent processes are in place throughout the group to measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business contract the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy include segregation of credit approval authorities from any sales, marketing or trading teams authorized to incur credit risk; the establishment of credit systems and processes to ensure that all counterparty exposure is rated and that all counterparty exposure and limits can be monitored and reported; and the timely identification and reporting of any non-approved credit exposures and credit losses. While each segment is responsible for its own credit risk management and reporting consistent with group policy, the treasury function holds group-wide credit risk authority and oversight responsibility for exposure to banks and financial institutions. Standing credit controls and processes were augmented intra-year given heightened uncertainty from increased oil price volatility and the evolving COVID-19 pandemic. Constraints on incoming credit risks were tightened, credit reporting and frequency was enhanced from the operational to board level, and key credit risk strategies were reviewed and vetted. 208 bp Annual Report and Form 20-F 2020 Financial statements 29. Financial instruments and financial risk factors – continued For the purposes of financial reporting the group calculates expected loss allowances based on the maximum contractual period over which the group is exposed to credit risk. Lifetime expected credit losses are recognized for trade receivables and the credit risk associated with the significant majority of financial assets measured at amortized cost is considered to be low. Since the tenor of substantially all of the group's in-scope financial assets is less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses. Expected loss allowances for financial guarantee contracts are typically lower than their initial fair value less, where appropriate, amortization. Financial assets are considered to be credit-impaired when there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset have occurred. This includes observable data concerning significant financial difficulty of the counterparty; a breach of contract; concession being granted to the counterparty for economic or contractual reasons relating to the counterparty’s financial difficulty, that would not otherwise be considered; it becoming probable that the counterparty will enter bankruptcy or other financial re- organization or an active market for the financial asset disappearing because of financial difficulties. The group also applies a rebuttable presumption that an asset is credit-impaired when contractual payments are more than 30 days past due. Where the group has no reasonable expectation of recovering a financial asset in its entirety or a portion thereof, for example where all legal avenues for collection of amounts due have been exhausted, the financial asset (or relevant portion) is written off. The measurement of expected credit losses is a function of the probability of default, loss given default (i.e. the magnitude of the loss after recovery if there is a default) and the exposure at default (i.e. the asset's carrying amount). The group allocates a credit risk rating to exposures based on data that is determined to be predictive of the risk of loss, including but not limited to external ratings. Probabilities of default derived from historical, current and future-looking market data are assigned by credit risk rating with a loss given default based on historical experience and relevant market and academic research applied by exposure type. Experienced credit judgement is applied to ensure probabilities of default are reflective of the credit risk associated with the group's exposures. Credit enhancements that would reduce the group's credit losses in the event of default are reflected in the calculation when they are considered integral to the related asset. The maximum credit exposure associated with financial assets is equal to the carrying amount. The group does not aim to remove credit risk entirely but expects to experience a certain level of credit losses. As at 31 December 2020, the group had in place credit enhancements designed to mitigate approximately $5.4 billion (2019 $7.0 billion) of credit risk, of which substantially all relates to assets in the scope of IFRS 9's impairment requirements. Credit enhancements include standby and documentary letters of credit, bank guarantees, insurance and liens which are typically taken out with financial institutions who have investment grade credit ratings, or are liens over assets held by the counterparty of the related receivables. Reports are regularly prepared and presented to the GFRC that cover the group’s overall credit exposure and expected loss trends, exposure by segment, and overall quality of the portfolio. Management information used to monitor credit risk, which reflects the impact of credit enhancements, indicates that the risk profile of financial assets which are subject to review for impairment under IFRS 9 is as set out below. As at 31 December AAA to AA- A+ to A- BBB+ to BBB- BB+ to BB- B+ to B- CCC+ and below 2020 11 % 59 % 8 % 6 % 13 % 3 % % 2019 16 % 51 % 13 % 7 % 11 % 2 % Movements in the impairment provision for trade and other receivables are shown in Note 21. Financial instruments subject to offsetting, enforceable master netting arrangements and similar agreements The following table shows the amounts recognized for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and the amounts offset in the balance sheet. Amounts which cannot be offset under IFRS, but which could be settled net under the terms of master netting agreements if certain conditions arise, and collateral received or pledged, are also presented in the table to show the total net exposure of the group. At 31 December 2020 Derivative assets Derivative liabilities Trade and other receivables Trade and other payables At 31 December 2019 Derivative assets Derivative liabilities Trade and other receivables Trade and other payables Gross amounts of recognized financial assets (liabilities) 14,765 (10,414) 7,667 (7,862) 13,191 (11,445) 10,661 (10,266) Related amounts not set off in the balance sheet Net amounts presented on the balance sheet 12,746 (8,395) 3,988 (4,183) Amounts set off (2,019) 2,019 (3,679) 3,679 (2,724) 2,724 (5,211) 5,211 10,467 (8,721) 5,450 (5,055) Master netting arrangements (2,075) 2,075 (693) 693 (1,971) 1,971 (961) 961 Cash collateral (received) pledged (386) — (122) — (206) — (190) — $ million Net amount 10,285 (6,320) 3,173 (3,490) 8,290 (6,750) 4,299 (4,094) bp Annual Report and Form 20-F 2020 209 29. Financial instruments and financial risk factors – continued (c) Liquidity risk Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is managed centrally with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local regulations, generally subsidiaries pool their cash surpluses to the treasury function, which will then arrange to fund other subsidiaries’ requirements, or invest any net surplus in the market or arrange for necessary external borrowings, while managing the group’s overall net currency positions. The group benefits from open credit provided by suppliers who generally sell on five to 60-day payment terms in accordance with industry norms. bp utilizes various arrangements in order to manage its working capital and reduce volatility in cash flow. This includes discounting of receivables and, in the supply and trading businesses, managing inventory, collateral and supplier payment terms within a maximum of 60 days. It is normal practice in the oil and gas supply and trading business for customers and suppliers to utilise letter of credit (LC) facilities to mitigate credit and non-performance risk. Consequently, LCs facilitate active trading in a global market where credit and performance risk can be significant. In common with the industry, bp routinely provides LCs to some of its suppliers. The group has committed LC facilities totalling $11,325 million (2019 $12,175 million), allowing LCs to be issued for a maximum 24-month duration. There were also uncommitted secured LC facilities in place at 31 December 2020 for $3,460 million (2019 $4,440 million), which are secured against inventories or receivables when utilized. The facilities are held with over 25 international banks. The uncommitted secured LC facilities can only be terminated by either party giving a stipulated termination notice to the other. In certain circumstances, the supplier has the option to request accelerated payment from the LC provider in order to further reduce their exposure. bp’s payments are made to the provider of the LC rather than the supplier according to the original contractual payment terms. At 31 December 2020, $5,250 million (2019 $4,755 million) of the group’s trade payables subject to these arrangements were payable to LC providers, with no material exposure to any individual provider. If these facilities were not available, this could result in renegotiation of payment terms with suppliers such that settlement periods were shorter. Standard & Poor’s Ratings long-term credit rating for bp is A- (negative outlook) and Moody’s Investors Service rating is A1 (negative outlook) and the Fitch Ratings' long-term credit rating is A (stable). During 2020, $14 billion (2019 $8 billion) of long-term taxable bonds were issued with terms ranging from two to thirty years. In addition the group issued perpetual hybrid bonds with a US dollar equivalent value of $11.9 billion. Commercial paper is issued at competitive rates to meet short-term borrowing requirements as and when needed. As a further liquidity measure, the group continues to maintain suitable levels of cash and cash equivalents, amounting to $31.1 billion at 31 December 2020 (2019 $22.5 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate and short notice. At 31 December 2020, the group had substantial amounts of undrawn borrowing facilities available, consisting of an undrawn committed $10.0 billion credit facility and $7.6 billion (2019 $7.6 billion) of standby facilities. On 1st March 2021, following an assessment of liquidity requirements, the group replaced these with new facility agreements, consisting of an undrawn committed $8.0 billion credit facility and $4.0 billion of standby facilities. The facilities are available for three and five years respectively at pre-agreed margins and are with 27 international banks, and borrowings under them would be at pre-agreed rates. For further information on the group's sources and uses of cash see Liquidity and capital resources on page 306. The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected maturities of both derivative assets and liabilities as indicated in Note 30. Management does not currently anticipate any cash flows, other than noted below, that could be of a significantly different amount or could occur earlier than the expected maturity analysis provided. The table below shows the timing of cash outflows relating to finance debt, trade and other payables and accruals. As part of actively managing the group’s debt portfolio it is possible that cash flows in relation to finance debt could be accelerated from the profile provided. As a result of the 19 March 2021 debt buy back (see Note 26 for further information) $1.9 billion equivalent of cash outflows relating to finance debt that are presented in the table with maturities of 2-8 years have occurred within one year of the balance sheet date. 2020 Within one year 1 to 2 years 2 to 3 years 3 to 4 years 4 to 5 years 5 to 10 years Over 10 years Accruals 4,650 157 184 87 217 108 99 5,502 a 2020 includes $14,569 million (2019 $16,129 million) in relation to the Gulf of Mexico oil spill, of which $13,160 million (2019 $14,501 million) matures in greater than one year. 1,778 1,477 1,305 1,110 919 2,408 1,037 10,034 Accruals 5,066 261 146 181 108 231 69 6,062 Finance debt 9,119 6,292 7,031 8,047 6,652 22,156 10,008 69,305 Trade and other payablesa 33,290 1,728 1,590 1,332 1,335 4,570 4,419 48,264 Trade and other payablesa 43,699 1,937 1,465 1,409 1,332 5,863 3,957 59,662 Interest on finance debt Finance debtb 10,065 6,726 7,949 7,022 7,554 23,540 2,497 65,353 $ million 2019 Interest on finance debt 2,037 1,641 1,409 1,172 942 1,970 249 9,420 210 bp Annual Report and Form 20-F 2020 29. Financial instruments and financial risk factors – continued The table below shows the timing of cash outflows for derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk, whether or not hedge accounting is applied, based upon contractual payment dates. As part of actively managing the group’s debt portfolio it is possible that cash flows in relation to associated derivatives could be accelerated from the profile provided. The amounts reflect the gross settlement amount where the pay leg of a derivative will be settled separately from the receive leg, as in the case of cross-currency swaps hedging non-US dollar finance debt or hybrid bonds. The swaps are with high investment-grade counterparties and therefore the settlement-day risk exposure is considered to be negligible. Not shown in the table are the gross settlement amounts (inflows) for the receive leg of derivatives that are settled separately from the pay leg, which amount to $33,704 million at 31 December 2020 (2019 $24,787 million) to be received on the same day as the related cash outflows. As a result of the termination of derivatives associated with the 19 March 2021 debt buy back (see Note 26 for further information) $1.8 billion of cash outflows that are presented in the table with maturities of 2-8 years and $1.9 billion equivalent of cash inflows on the receive legs have occurred within one year of the balance sheet date. Financial statements Cash outflows for derivative financial instruments at 31 December Within one year 1 to 2 years 2 to 3 years 3 to 4 years 4 to 5 years 5 to 10 years Over 10 years For further information on our derivative financial instruments, see Note 30. 2020 2,384 1,976 2,017 3,074 2,582 15,263 4,483 31,779 $ million 2019 1,678 2,384 2,838 2,906 3,321 10,633 2,224 25,984 30. Derivative financial instruments In the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate debt, consistent with risk management policies and objectives. An outline of the group’s financial risks and the objectives and policies pursued in relation to those risks is set out in Note 29. Additionally, the group has a well-established entrepreneurial trading operation that is undertaken in conjunction with these activities using a similar range of contracts. For information on significant estimates and judgements made in relation to the valuation of derivatives see Derivative financial instruments within Note 1. The fair values of derivative financial instruments at 31 December are set out below. Exchange traded derivatives are valued using closing prices provided by the exchange as at the balance sheet date. These derivatives are categorized within level 1 of the fair value hierarchy. Exchange traded derivatives are typically considered settled through the (normally daily) payment or receipt of variation margin. Over-the-counter (OTC) financial swaps and physical commodity sale and purchase contracts are generally valued using readily available information in the public markets and quotations provided by brokers and price index developers. These quotes are corroborated with market data and are categorized within level 2 of the fair value hierarchy. In certain less liquid markets, or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC financial swaps and physical commodity sale and purchase contracts are valued using internally developed methodologies that consider historical relationships between various commodities, and that result in management’s best estimate of fair value. These contracts are categorized within level 3 of the fair value hierarchy. bp Annual Report and Form 20-F 2020 211   30. Derivative financial instruments – continued Financial OTC and physical commodity options are valued using industry standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic factors. The degree to which these inputs are observable in the forward markets determines whether the option is categorized within level 2 or level 3 of the fair value hierarchy. Derivatives held for trading Currency derivatives Oil price derivatives Natural gas price derivatives Power price derivatives Other derivatives Embedded derivatives Other embedded derivatives Cash flow hedges Currency forwards Gas price futures Fair value hedges Currency swaps Interest rate swaps Of which – current – non-current Fair value asset 858 1,519 6,406 1,258 7 10,048 1 1 4 — 4 2020 Fair value liability Fair value asset (694) (1,093) (5,489) (1,037) — (8,313) (7) (7) — — — 81 1,918 6,569 1,306 110 9,984 — — 1 — 1 2,614 80 2,694 12,747 2,992 9,755 (82) — (82) (8,402) (2,998) (5,404) 344 138 482 10,467 4,153 6,314 $ million 2019 Fair value liability (744) (1,478) (4,871) (952) — (8,045) (77) (77) (4) — (4) (637) (35) (672) (8,798) (3,261) (5,537) Derivatives held for trading The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective, and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of contract types in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of these exposures is monitored using market value-at-risk techniques as described in Note 29. The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes. Derivative assets held for trading have the following fair values and maturities. Less than 1 year 153 1,159 1,210 425 — 2,947 Less than 1 year 48 1,619 1,889 556 33 4,145 1-2 years 2-3 years 3-4 years 4-5 years 9 197 731 223 — 1,160 3 90 596 161 7 857 2 63 525 107 — 697 2 7 476 76 — 561 1-2 years 2-3 years 3-4 years 4-5 years 23 114 824 269 — 1,230 9 76 615 146 — 846 1 53 489 94 77 714 — 45 433 67 — 545 $ million 2020 Total 858 1,519 6,406 1,258 7 10,048 $ million 2019 Total 81 1,918 6,569 1,306 110 9,984 Over 5 years 689 3 2,868 266 — 3,826 Over 5 years — 11 2,319 174 — 2,504 Currency derivatives Oil price derivatives Natural gas price derivatives Power price derivatives Other derivatives Currency derivatives Oil price derivatives Natural gas price derivatives Power price derivatives Other derivatives 212 bp Annual Report and Form 20-F 2020 30. Derivative financial instruments – continued Derivative liabilities held for trading have the following fair values and maturities. Currency derivatives Oil price derivatives Natural gas price derivatives Power price derivatives Currency derivatives Oil price derivatives Natural gas price derivatives Power price derivatives Less than 1 year (502) (1,000) (1,095) (345) (2,942) Less than 1 year (166) (1,405) (1,070) (395) (3,036) 1-2 years 2-3 years 3-4 years 4-5 years (117) (83) (595) (184) (979) (11) (9) (479) (126) (625) (1) (1) (422) (81) (505) — — (348) (68) (416) 1-2 years 2-3 years 3-4 years 4-5 years (283) (56) (522) (165) (1,026) (201) (14) (446) (104) (765) (1) (2) (399) (76) (478) (23) (1) (363) (51) (438) Financial statements $ million 2020 Total (694) (1,093) (5,489) (1,037) (8,313) $ million 2019 Total (744) (1,478) (4,871) (952) (8,045) Over 5 years (63) — (2,550) (233) (2,846) Over 5 years (70) — (2,071) (161) (2,302) The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by methodology of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty. Fair value of derivative assets Level 1 Level 2 Level 3 Less: netting by counterparty Fair value of derivative liabilities Level 1 Level 2 Level 3 Less: netting by counterparty Net fair value Fair value of derivative assets Level 1 Level 2 Level 3 Less: netting by counterparty Fair value of derivative liabilities Level 1 Level 2 Level 3 Less: netting by counterparty Net fair value Less than 1 year 48 3,342 739 4,129 (1,182) 2,947 (55) (3,577) (492) (4,124) 1,182 (2,942) 5 Less than 1 year 63 5,344 779 6,186 (2,041) 4,145 (49) (4,522) (506) (5,077) 2,041 (3,036) 1,109 1-2 years 2-3 years 3-4 years 4-5 years 9 858 546 1,413 (253) 1,160 (9) (809) (414) (1,232) 253 (979) 181 15 367 552 934 (77) 857 (13) (263) (426) (702) 77 (625) 232 3 212 520 735 (38) 697 (3) (136) (404) (543) 38 (505) 192 5 100 493 598 (37) 561 (5) (41) (407) (453) 37 (416) 145 1-2 years 2-3 years 3-4 years 4-5 years 6 1,014 501 1,521 (291) 1,230 (8) (932) (377) (1,317) 291 (1,026) 204 2 439 485 926 (80) 846 (4) (458) (383) (845) 80 (765) 81 — 210 540 750 (36) 714 (1) (146) (367) (514) 36 (478) 236 2 120 452 574 (29) 545 (2) (113) (352) (467) 29 (438) 107 $ million 2020 Total 81 5,588 6,398 12,067 (2,019) 10,048 (86) (4,905) (5,341) (10,332) 2,019 (8,313) 1,735 $ million 2019 Total 74 7,169 5,465 12,708 (2,724) 9,984 (65) (6,272) (4,432) (10,769) 2,724 (8,045) 1,939 Over 5 years 1 709 3,548 4,258 (432) 3,826 (1) (79) (3,198) (3,278) 432 (2,846) 980 Over 5 years 1 42 2,708 2,751 (247) 2,504 (1) (101) (2,447) (2,549) 247 (2,302) 202 bp Annual Report and Form 20-F 2020 213 30. Derivative financial instruments – continued Level 3 derivatives The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair value hierarchy. Fair value contracts at 1 January 2020 Gains (losses) recognized in the income statement Sales Settlements Transfers out of level 3 Net fair value of contracts at 31 December 2020 Deferred day-one gains (losses) Derivative asset (liability) Fair value contracts at 1 January 2019 Gains (losses) recognized in the income statement Gains (losses) recognized in other comprehensive income Settlements Transfers out of level 3 Net fair value of contracts at 31 December 2019 Deferred day-one gains (losses) Derivative asset (liability) Oil price 71 250 — (135) 5 191 Natural gas price 28 184 — (22) (43) 147 Power price (125) 162 — (189) (21) (173) Currency and other 110 (66) (32) — (1) 11 Oil price 23 128 — (79) (1) 71 Natural gas price (13) 82 — (21) (20) 28 Power price (148) 244 (18) (179) (24) (125) Other 107 2 — — 1 110 $ million Total 84 530 (32) (346) (60) 176 881 1,057 $ million Total (31) 456 (18) (279) (44) 84 949 1,033 The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2020 was a $315- million gain (2019 $250-million gain related to derivatives still held at 31 December 2019). Derivative gains and losses The group enters into derivative contracts including futures, options, swaps and certain forward sales and forward purchases contracts, relating to both currency and commodity trading activities. Gains or losses arise on contracts entered into for risk management purposes, optimization activity and entrepreneurial trading. They also arise on certain contracts that are for normal procurement or sales activity for the group but that are required to be fair valued under accounting standards. These gains and losses are included within sales and other operating revenues in the income statement. Also included within this line item are gains and losses on inventory held for trading purposes. The total amount relating to all these items was a net gain of $2,808 million. This number does not include gains and losses on the change in value of contracts which are not recognized under IFRS such as transportation and storage contracts, but does include the associated financially settled contracts. The net amounts for actual gains and losses relating to these derivative contracts and all related items therefore differ significantly from the amounts disclosed above. The group also enters into derivative contracts relating to foreign currency risk management activities including contracts that the group has entered into to manage the foreign currency exposure relating to the non-US dollar hybrid bonds to their respective first call periods. Gains and losses on these contracts are included within production and manufacturing expenses in the income statement. The change in the unrealized value of these contracts was a net gain of $829 million (2019 $160 million net gain and 2018 $351 million net loss), however where these gains and losses arise on derivatives hedging finance debt they are largely offset by opposing net foreign exchange differences on retranslation of the associated non-US dollar debt. The net amounts for actual gains and losses relating to these derivative contracts and all related items therefore differ significantly from the amounts disclosed above. Cash flow hedges (i) Foreign currency risk of highly probable forecast capital expenditure At 31 December 2020, the group held currency forwards designated as hedging instruments in cash flow hedge relationships of highly probable forecast non-US dollar capital expenditure. Note 29 outlines the group’s approach to foreign currency exchange risk management. When the highly probable forecast capital expenditure designated as a hedged item occurs, a non-financial asset is recognized and is presented within the fixed asset section of the balance sheet. The group claims hedge accounting only for the spot value of the currency exposure in line with the strategy to fix the volatility in the spot exchange rate element. The fair value on the instrument attributable to forward points and foreign currency basis spreads is taken immediately to the income statement. The group applies hedge accounting where there is an economic relationship between the hedged item and hedging instrument. The existence of an economic relationship is determined at inception and prospectively by comparing the critical terms of the hedging instrument and those of the hedged item. The group enters into hedging derivatives that match the currency and notional of the hedged items on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional amount of the derivative with the notional designated on the forecast transaction. The group determines the extent to which it hedges highly probable forecast capital expenditures on a project by project basis. The group has identified the following sources of ineffectiveness, which are not expected to be material: • counterparty's credit risk, the group mitigates counterparty credit risk by entering into derivative transactions with high credit quality counterparties; and 214 bp Annual Report and Form 20-F 2020 Financial statements 30. Derivative financial instruments – continued • differences in settlement timing between the derivative and hedged items. The latter impacts the discount factor used in the calculation of the hedge ineffectiveness. The group mitigates differences in timing between the derivatives and hedged items by applying a rolling strategy and by hedging currency pairs from stable economies (i.e. sterling/US dollar, Korean won/US dollar). The group's cash flow hedge designations are highly effective as the sources of ineffectiveness identified are expected to result in minimal hedge ineffectiveness. The group has not designated any net positions as hedged items in cash flow hedges of foreign currency risk. (ii) Commodity price risk of highly probable forecast sales During the period the group held Henry Hub NYMEX futures designated as hedging instruments in cash flow hedge relationships of certain highly probable forecast future sales. Henry Hub NYMEX futures are subject to daily settlement, where their fair value at the end of each day is required to be cash settled, such that the carrying amount of these hedging instruments within continuing hedge relationships is always zero at the end of each day. The group is exposed to the variability in the gas price, but only applied hedge accounting to the risk of Henry Hub price movements for a percentage of future gas sales from its BPX Energy business. The group applied hedge accounting in relation to these highly probable future sales where there was an economic relationship between the hedged item and hedging instrument. The existence of an economic relationship was determined at inception and prospectively by comparing the critical terms of the hedging instrument and those of the hedged item. The group entered into hedging derivatives that matched the notional amounts of the hedged items on a 1:1 hedge ratio basis. The hedge ratio was determined by comparing the notional amount of the derivative with the notional amount designated on the forecast transaction. The hedge was highly effective due to the price index of the hedging instruments matching the price index of the hedged item. The group did not designate any net positions as hedged items in cash flow hedges of commodity price risk. The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the period. At 31 December 2020 Cash flow hedges Foreign exchange risk Highly probable forecast capital expenditure Commodity price risk Highly probable forecast sales At 31 December 2019 Cash flow hedges Foreign exchange risk Highly probable forecast capital expenditure Commodity price risk Highly probable forecast sales $ million Change in fair value of hedging instrument used to calculate ineffectiveness Change in fair value of hedged item used to calculate ineffectiveness Hedge ineffectiveness recognized in profit or (loss) 4 (4) 78 (78) (1) 1 (100) 100 — — — — The tables below summarize the carrying amount and nominal amount of the derivatives designated as hedging instruments in cash flow hedge relationships. At 31 December 2020 Cash flow hedges Foreign exchange risk Highly probable forecast capital expenditure Commodity price risk Highly probable forecast sales At 31 December 2019 Cash flow hedges Foreign exchange risk Carrying amount of hedging instrument Assets Liabilities Nominal amounts of hedging instruments $ million $ million $ million mmBtu 4 — — 162 — (175) Highly probable forecast capital expenditure 1 (4) 150 All hedging instruments are presented within derivative financial instruments on the group balance sheet. All of the nominal amount of hedging instruments at 31 December 2020 and 2019 relating to highly probably forecast capital expenditure matures within 12 months of the relevant balance sheet date. Of the nominal amount of hedging instruments at 31 December 2020 relating to highly probably forecast sales 135 mmBtu matures within 12 months and 40 mmBtu within one to two years. bp Annual Report and Form 20-F 2020 215 30. Derivative financial instruments – continued The table below summarizes the weighted average exchange rates and the weighted average sales price in relation to the derivatives designated as hedging instruments in cash flow hedge relationships at 31 December. At 31 December Sterling/US dollar Euro/US dollar Korean won/US dollar Henry Hub $/mmBtu Weighted average price/rate 2020 2019 Forecast capital expenditure 1.35 — 1,174.47 Forecast capital expenditure 1.35 1.11 1,115.66 Forecast sales 2.88 Fair value hedges At 31 December 2020, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk and foreign currency risk arising from group fixed rate debt issuances. Note 29 outlines the group’s approach to interest rate and foreign currency exchange risk management. The interest rate swaps are used to convert US dollar denominated fixed rate borrowings into floating rate debt. The cross-currency interest rate swaps are used to convert sterling, euro, Swiss franc, Canadian dollar and Norwegian krone denominated fixed rate borrowings into US dollar floating rate debt. The group manages all risks derived from debt issuance, such as credit risk, however, the group applies hedge accounting only to certain components of interest rate and foreign currency risk in order to minimize hedge ineffectiveness. The interest rate and foreign currency exposures are identified and hedged on an instrument-by-instrument basis. For interest rate exposures, the group designates as a fair value hedge the benchmark interest rate component only. This is an observable and reliably measurable component of interest rate risk. All of the fair value hedge accounting relationships currently in place are directly affected by the interest rate benchmark reform which will replace interbank offered rates (IBORs) with alternative benchmark rates as they all manage interest rate risk. The Group is significantly exposed to benchmark interest rate components; predominantly USD LIBOR, GBP LIBOR, EURIBOR and CHF LIBOR. The nominal amounts of the applicable hedging instruments represent the extent of the risk exposure bp manages for financial derivatives designated in fair value hedge relationships that is directly affected by the interest rate benchmark reform. These are disclosed in the table below. Uncertainty around the method and timing of transition from Inter-bank Offered Rates (IBORs) to alternative risk-free rates (RfRs) may impact the assessment of whether hedge accounting can be applied to certain hedging relationships. However, the temporary reliefs provided by IFRS 9 allow bp to assume that in the event that significant uncertainty around the reform arises: • the interest rate benchmark component of fair value hedges only needs to be assessed as separately identifiable at initial designation; and • the interest rate benchmark is not altered for the purposes of assessing the economic relationship between the hedged item and the hedging instrument for fair value hedges. Judgement will be required to determine when the uncertainty arising from interest rate benchmark reform is no longer present and when the temporary reliefs no longer apply. However, at 31 December 2020 the reliefs apply and bp continues to monitor regulatory and market developments as it manages the contractual transition. For foreign currency exposures, the group excludes from the designation the foreign currency basis spread component implicit in the cross-currency interest rate swaps. This is separately calculated at hedge designation, is recognized in other comprehensive income over the life of the hedge and amortized to the income statement on a straight-line basis, in accordance with the group’s policy on costs of hedging. The group applies hedge accounting where there is an economic relationship between the hedged item and the hedging instrument. The existence of an economic relationship is determined initially by comparing the critical terms of the hedging instrument and those of the hedged item and it is prospectively assessed using linear regression analysis. The group issues fixed rate debt and enters into interest rate and cross-currency interest rate swaps with critical terms that match those of the debt and on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional amount of the derivative with the notional amount of the debt. The hedge relationship is designated for the full term and notional value of the debt. Both the hedging instrument and the hedged item are expected to be held to maturity. The group has identified the following sources of ineffectiveness, which are not expected to be material: • derivative counterparty’s credit risk which is not offset by the hedged item. This risk is mitigated by entering into derivative transactions only with high credit quality counterparties; and • sensitivity to interest rate between the hedged item and the derivatives. This is driven by differences in payment frequencies between the instrument and the bond. The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the period. The signage convention for changes in fair value presented in this table is consistent with that presented in Note 27. At 31 December 2020 Fair value hedges Interest rate risk on finance debt Interest rate and foreign currency risk on finance debt At 31 December 2019 Fair value hedges Interest rate risk on finance debt Interest rate and foreign currency risk on finance debt 216 bp Annual Report and Form 20-F 2020 $ million Change in fair value of hedging instrument used to calculate ineffectiveness Change in fair value of hedged item used to calculate ineffectiveness Hedge ineffectiveness recognized in profit or (loss) (258) (2,743) 258 2,549 (764) (336) 737 286 — 194 27 50 30. Derivative financial instruments – continued The tables below summarize the carrying amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31 December. Financial statements At 31 December 2020 Fair value hedges Interest rate risk on finance debt Interest rate and foreign currency risk on finance debt At 31 December 2019 Fair value hedges Interest rate risk on finance debt Interest rate and foreign currency risk on finance debt Carrying amount of hedging instrument Assets Liabilities $ million Nominal amounts of hedging instruments 80 2,614 — (82) 4,104 23,313 138 344 (35) (637) 13,442 21,296 All hedging instruments are presented within derivative financial instruments on the group balance sheet. Ineffectiveness arising on fair value hedges is included within the production and manufacturing expenses section of the income statement. The tables below summarize the profile by tenor of the nominal amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31 December. At 31 December 2020 Fair value hedges Interest rate risk on finance debt Interest rate and foreign currency risk on finance debt At 31 December 2019 Fair value hedges Interest rate risk on finance debt Interest rate and foreign currency risk on finance debt Less than 1 year 1-2 years 2-3 years 3-4 years 4-5 years 5-10 years Over 10 years Total $ million 2,705 996 — 227 — 176 — 4,104 737 1,056 2,039 3,175 2,804 8,587 4,915 23,313 3,000 2,576 4,039 1,200 206 2,421 — 13,442 882 672 1,400 2,777 3,109 10,216 2,240 21,296 The table below summarizes the weighted average floating interest rate and the weighted average exchange rates in relation to the derivatives designated as hedging instruments in fair value hedge relationships at 31 December. At 31 December Interest rate Sterling/US dollar Euro/US dollar Canadian dollar/US dollar Interest rate swaps 0.58 % 2020 Cross-currency interest rate swaps 1.88 % 1.33 1.14 0.78 Interest rate swaps 2.36 % 2019 Cross-currency interest rate swaps 3.27 % 1.32 1.15 0.87 The tables below summarize the carrying amount, and the accumulated fair value adjustments included within the carrying amount, of the hedged items designated in fair value hedge relationships at 31 December. At 31 December 2020 Fair value hedges Carrying amount of hedged item Accumulated fair value adjustment included in the carrying amount of hedged items $ million Assets Liabilities Assets Liabilities Discontinued hedges Interest rate risk on finance debt Interest rate and foreign currency risk on finance debt — — (4,196) (23,253) — — (81) (938) (775) — At 31 December 2019 Fair value hedges Interest rate risk on finance debt Interest rate and foreign currency risk on finance debt — — (13,441) (21,240) — — (100) (525) (714) — The hedged item for all fair value hedges is presented within finance debt on the group balance sheet. bp Annual Report and Form 20-F 2020 217 30. Derivative financial instruments – continued Movement in reserves related to hedge accounting The table below provides a reconciliation of the cash flow hedge and costs of hedging reserves on a pre-tax basis by risk category. The signage convention of this table is consistent with that presented in Note 32. Cash flow hedge reserve Costs of hedging reserve At 1 January 2020 Recognized in other comprehensive income Cash flow hedges marked to market Cash flow hedges reclassified to the income statement - hedged item affected profit or loss Costs of hedging marked to market Costs of hedging reclassified to the income statement Cash flow hedges transferred to the balance sheet At 31 December 2020 Highly probable forecast capital expenditure Highly probable forecast sales (1) 7 — — — 7 6 12 — 78 (37) — — 41 — 41 Interest rate and foreign currency risk on finance debt Purchase of equitya (651) (170) — — 42 22 64 — — — — — — — $ million Total (822) 85 (37) 42 22 112 6 (651) (106) (704) $ million At 1 January 2019 Recognized in other comprehensive income Cash flow hedges marked to market Cash flow hedges reclassified to the income statement - hedged item affected profit or loss Costs of hedging marked to market Costs of hedging reclassified to the income statement Cash flow hedges transferred to the balance sheet Cash flow hedge reserve Costs of hedging reserve Highly probable forecast capital expenditure Highly probable forecast sales (21) (6) Interest rate and foreign currency risk on finance debt (223) Purchase of equitya (651) Total (901) (3) (100) — — — (3) 23 106 — — 6 — — — — — — — — (103) — (4) 57 53 — 106 (4) 57 56 23 At 31 December 2019 a See Note 32 for further information on the cash flow hedge reserve relating to the purchase of equity. Substantially all of the cash flow hedge reserve balances and all of the amounts reclassified from the cash flow hedge reserve into profit or loss during the year relate to continuing hedge relationships. Amounts deferred in the cash flow hedge reserve that have been reclassified to profit or loss are presented in sales and other operating revenues in the income statement. (651) (170) — (1) (822) Costs of hedging relates to the foreign currency basis spreads of hedging instruments used to hedge the group's interest rate and foreign currency risk on debt which is a time-period related item. 218 bp Annual Report and Form 20-F 2020 Financial statements 31. Called-up share capital The allotted, called up and fully paid share capital at 31 December was as follows: Issued 8% cumulative first preference shares of £1 eacha 9% cumulative second preference shares of £1 eacha Ordinary shares of 25 cents each At 1 January Issue of new shares for the scrip dividend programme Issue of new shares for employee share-based payment plans Issue of new shares – other Repurchase of ordinary share capital At 31 December Shares thousand 7,233 5,473 2020 $ million 12 9 21 Shares thousand 7,233 5,473 2019 $ million 12 9 21 Shares thousand 7,233 5,473 21,535,840 — 34,000 — (120,058) 21,449,782 — 9 — (30) 5,383 21,525,464 208,927 37,400 — (235,951) 5,362 21,535,840 5,383 52 9 — (59) 5,381 21,288,193 195,305 92,168 — (50,202) 5,383 21,525,464 5,404 2018 $ million 12 9 21 5,322 49 23 — (13) 5,381 5,402 a The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of preference shares. Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each. In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value. During 2020 the company repurchased 120 million ordinary shares for a total consideration of $776 million, including transaction costs of $4 million, as part of the share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The repurchased shares represented 0.6% of ordinary share capital. The number of shares in issue is reduced when shares are repurchased. Treasury sharesa 2020 2019 Shares thousand Nominal value $ million Shares thousand Nominal value $ million Shares thousand At 1 January Purchases for settlement of employee share plans Issue of new shares for employee share-based payment plans Shares re-issued for employee share-based payment plans At 31 December Of which – shares held in treasury by bp – shares held in ESOP trusts – shares held by bp’s US share plan administratorb 1,296,856 — 34,116 (143,322) 1,187,650 1,105,157 82,491 2 a See Note 32 for definition of treasury shares. b Held in the form of ADSs to meet the requirements of employee share-based payment plans in the US. 323 1,426,265 1,118 — 37,400 9 (36) (167,927) 296 1,296,856 275 1,163,077 133,707 72 21 — 356 1,482,072 757 — 92,168 9 (42) (148,732) 323 1,426,265 290 1,264,732 161,518 15 33 — 2018 Nominal value $ million 370 — 23 (37) 356 316 40 — For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by bp during the year, representing 5.4% (2019 5.9% and 2018 6.9%) of the called-up ordinary share capital of the company. During 2020, the movement in shares held in treasury by bp represented less than 0.3% (2019 less than 0.5% and 2018 less than 1.0%) of the ordinary share capital of the company. bp Annual Report and Form 20-F 2020 219 32. Capital and reserves At 1 January 2020 Profit (loss) for the year Items that may be reclassified subsequently to profit or loss Currency translation differences (including reclassifications) Cash flow hedges and costs of hedging (including reclassifications) Share of items relating to equity-accounted entities, net of taxa Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Cash flow hedges that will subsequently be transferred to the balance sheet Total comprehensive income Dividends Cash flow hedges transferred to the balance sheet, net of tax Repurchases of ordinary share capital Share-based payments, net of taxb Share of equity-accounted entities’ changes in equity, net of taxc Issue of perpetual hybrid bonds Payments on perpetual hybrid bonds Tax on issue of perpetual hybrid bonds Transactions involving non-controlling interests, net of taxd At 31 December 2020 At 31 December 2018 Adjustment on adoption of IFRS 16, net of tax At 1 January 2019 Profit (loss) for the year Items that may be reclassified subsequently to profit or loss Currency translation differences (including reclassifications) Cash flow hedges and costs of hedging (including reclassifications) Share of items relating to equity-accounted entities, net of taxa Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Cash flow hedges that will subsequently be transferred to the balance sheet Share capital Share premium account 5,404 12,417 — — Merger reserve Capital redemption reserve 1,498 27,206 — — Total share capital and capital reserves 46,525 — — — — — — — — — — — — — — — — — — — — (30) 167 9 — — — — — — — — — — 5,383 12,584 5,402 12,305 — — 5,402 12,305 — — — — — — — — — — — — — — — — — — — — — — — 30 — — — — — — — — — — — — — — — — — — 1,528 27,206 — 1,439 27,206 — 1,439 27,206 — — — — — — — — — — — — — — — — (52) 52 — — — (59) 164 9 — — — — 5,404 12,417 — — — — — 59 — — — — — — — — — — — — 1,498 27,206 — — — — — — — — — — 176 — — — — — 46,701 46,352 — 46,352 — — — — — — — — — — — 173 — — 46,525 Total comprehensive income Dividends Cash flow hedges transferred to the balance sheet, net of tax Repurchases of ordinary share capital Share-based payments, net of taxb Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests, net of taxe At 31 December 2019 a Principally foreign exchange effects relating to the Russian rouble. b Movements in treasury shares relate to employee share-based payment plans. c Principally relates to a non-controlling interest transaction entered into by Rosneft. d Principally relates to the sale of interests in our UK and New Zealand retail property portfolio, for which proceeds of $0.5 billion and $0.2 billion were received respectively. e Principally relates to the sale of a 49% interest in bp's retail property portfolio in Australia. 220 bp Annual Report and Form 20-F 2020 32. Capital and reserves – continued Financial statements Treasury shares (14,412) — Foreign currency translation reserve (6,495) — — — — — — — — — — — 1,188 — — — — — (13,224) (15,767) — (15,767) — — — — — — — — — — — 1,355 — — (14,412) (2,224) — — — — — (2,224) — — — — — — — — — (8,719) (8,902) — (8,902) — 2,407 — — — — — 2,407 — — — — — — (6,495) Available- for-sale investments — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — Cash flow hedges (752) — Costs of hedging (160) — Total fair value reserves (912) — Profit and loss account 73,706 (20,305) bp shareholders’ equity 98,412 (20,305) Hybrid bonds Other interest — 256 2,296 (680) Total equity 100,708 (20,729) Non-controlling interests $ million — 31 — — — 7 38 — 6 — — — — — — — (708) (777) — (777) — — 5 — — — (3) 2 — 23 — — — — (752) — 60 — — — — 60 — — — — — — — — — (100) (210) — (210) — — 50 — — — — 50 — — — — — — (160) — 91 — — — 7 98 — 6 — — — — — — — (808) (987) — (987) — — 55 — — — (3) 52 — 23 — — — — (912) — — 312 71 65 — (19,857) (6,367) — (776) (638) 1,341 (48) — 3 (64) 47,300 78,748 (329) 78,419 4,026 — — 82 (64) 171 — 4,215 (6,929) — (1,511) (809) 5 316 73,706 (2,224) 91 312 71 65 7 (21,983) (6,367) 6 (776) 726 1,341 (48) — 3 (64) 71,250 99,444 (329) 99,115 4,026 2,407 55 82 (64) 171 (3) 6,674 (6,929) 23 (1,511) 719 5 316 98,412 — — — — — — 256 — — — — — 11,909 (89) — — 12,076 — — — — — — — — — — — — — — — — — — 37 — — — — — (643) (238) — — — — — — — 827 2,242 2,104 (1) 2,103 164 9 — — — — — 173 (213) — — — — 233 2,296 (2,187) 91 312 71 65 7 (22,370) (6,605) 6 (776) 726 1,341 11,861 (89) 3 763 85,568 101,548 (330) 101,218 4,190 2,416 55 82 (64) 171 (3) 6,847 (7,142) 23 (1,511) 719 5 549 100,708 bp Annual Report and Form 20-F 2020 221 Merger reserve Capital redemption reserve 1,426 27,206 — 1,426 27,206 — — — Total share capital and capital reserves 46,122 — 46,122 — — — — — — — — — — — — — — 13 — — — — — — — — — — — — 1,439 27,206 — — — — — — — — — — 230 — — 46,352 32. Capital and reserves – continued At 31 December 2017 Adjustment on adoption of IFRS 9, net of tax At 1 January 2018 Profit (loss) for the year Items that may be reclassified subsequently to profit or loss Currency translation differences (including reclassifications) Cash flow hedges and costs of hedging (including reclassifications) Share of items relating to equity-accounted entities, net of taxa Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Cash flow hedges that will subsequently be transferred to the balance sheet Total comprehensive income Dividends Cash flow hedges transferred to the balance sheet, net of tax Repurchases of ordinary share capital Share-based payments, net of taxb Share of equity-accounted entities’ changes in equity, net of tax Transactions involving non-controlling interests, net of tax At 31 December 2018 a Principally foreign exchange effects relating to the Russian rouble. b Movements in treasury shares relate to employee share-based payment plans. Share capital Share premium account 5,343 12,147 — — 5,343 12,147 — — — — — — — — — — — — — — — — (49) 49 — — — (13) 207 23 — — — — 5,402 12,305 222 bp Annual Report and Form 20-F 2020 Financial statements 32. Capital and reserves – continued Treasury shares (16,958) — (16,958) — — — — — — — — — — — 1,191 — — (15,767) Foreign currency translation reserve (5,156) — (5,156) — (3,746) — — — — — (3,746) — — — — — — (8,902) Available- for-sale investments 17 (17) — — — — — — — — — — — — — — — — Cash flow hedges (760) — (760) — — (6) — — — (37) (43) — 26 — — — — (777) Costs of hedging Total fair value reserves — (37) (37) — — (173) — — — — (173) — — — — — — (210) (743) (54) (797) — — (179) — — — (37) (216) — 26 — — — — (987) Profit and loss account 75,226 (126) 75,100 9,383 bp shareholders’ equity 98,491 (180) 98,311 9,383 — — 417 7 1,599 — 11,406 (6,699) — (355) (718) 14 — 78,748 (3,746) (179) 417 7 1,599 (37) 7,444 (6,699) 26 (355) 703 14 — 99,444 Non-controlling interests Hybrid bonds Other interest — — — — — — — — — — — — — — — — — — 1,913 — 1,913 195 (41) — — — — — 154 (170) — — — — 207 2,104 $ million Total equity 100,404 (180) 100,224 9,578 (3,787) (179) 417 7 1,599 (37) 7,598 (6,869) 26 (355) 703 14 207 101,548 . bp Annual Report and Form 20-F 2020 223 32. Capital and reserves – continued Share capital The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury shares. Share premium account The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares. Capital redemption reserve The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled. Merger reserve The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in an acquisition made by the issue of shares. Treasury shares Treasury shares represent bp shares repurchased and available for specific and limited purposes. For accounting purposes shares held in Employee Share Ownership Plans (ESOPs) and bp’s US share plan administrator to meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are, therefore, included in the financial statements as treasury shares. The ESOPs are funded by the group and have waived their rights to dividends in respect of such shares held for future awards. Until such time as the shares held by the ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders’ equity. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group. Foreign currency translation reserve The foreign currency translation reserve records exchange differences arising from the translation of the financial statements of foreign operations. Upon disposal of foreign operations, the related accumulated exchange differences are reclassified to the income statement. Available-for-sale investments This reserve recorded the changes in fair value of investments classified as available-for-sale under IAS 39 except for impairment losses, foreign exchange gains or losses, or changes arising from revised estimates of future cash flows. On adoption of IFRS 9 the balance in this reserve was transferred to the profit and loss account reserve. Under the new standard the group recognizes fair value gains and losses on these investments in profit or loss. Cash flow hedges This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. It includes $651 million relating to the acquisition of an 18.5% interest in Rosneft in 2013 which will only be reclassified to the income statement if the investment in Rosneft is either sold or impaired. For further information on the accounting for cash flow hedges see Note 1 - Derivative financial instruments and hedging activities. Costs of hedging This reserve records the change in fair value of the foreign currency basis spread of financial instruments to which cost of hedge accounting has been applied. The accumulated amount relates to time-period related hedged items and is amortized to profit or loss over the term of the hedging relationship. Prior to the group’s adoption of IFRS 9 changes in the fair value of such foreign currency basis spreads were recognized in profit or loss. On adoption of the new standard a transfer from the profit and loss account reserve to the costs of hedging reserve was made in order to reflect the opening reserves position for relevant hedging instruments existing on transition. For further information on the accounting for costs of hedging see Note 1 - Derivative financial instruments and hedging activities. Profit and loss account The balance held on this reserve is the accumulated retained profits of the group. Non-controlling interests Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to bp shareholders. Included within non- controlling interests are perpetual subordinated hybrid bonds issued by BP Capital Markets PLC, a group subsidiary, on 17 June 2020 in euro, sterling and US dollars for a US dollar equivalent amount of $11.9 billion. The hybrid bonds include redemption options exercisable at the group’s discretion from June 2025 to March 2030 (the first ‘call date’), on specified dates thereafter, or in the event of specific circumstances (such as a change in IFRS or tax regime) as set out in the individual terms of each issue. Coupons are fixed for an initial period up to dates from September 2025 to June 2030 at rates of 3.25% to 4.875% and reset to rates determined by the contractual terms of each instrument on certain dates thereafter. The contractual terms of the hybrid bonds allow the group to defer coupon payments and the repayment of principal indefinitely, however their terms and conditions stipulate that any deferred payments must be made in the event of an announcement of an ordinary share or parity equity dividend distribution or certain share repurchases or redemptions. As the group has the unconditional right to avoid transferring cash or another financial asset in relation to these hybrid bonds, they are classified as equity instruments and reported within non-controlling interests in the consolidated financial statements. 224 bp Annual Report and Form 20-F 2020 32. Capital and reserves – continued The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below. Financial statements Items that may be reclassified subsequently to profit or loss Currency translation differences (including reclassifications) Cash flow hedges (including reclassifications) Costs of hedging (including reclassifications) Share of items relating to equity-accounted entities, net of tax Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Cash flow hedges that will subsequently be transferred to the balance sheet Other comprehensive income Items that may be reclassified subsequently to profit or loss Currency translation differences (including reclassifications) Cash flow hedges (including reclassifications) Costs of hedging (including reclassifications) Share of items relating to equity-accounted entities, net of tax Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Cash flow hedges that will subsequently be transferred to the balance sheet Other comprehensive income Items that may be reclassified subsequently to profit or loss Currency translation differences (including reclassifications) Cash flow hedges (including reclassifications) Costs of hedging (including reclassifications) Share of items relating to equity-accounted entities, net of tax Other Items that will not be reclassified to profit or loss Remeasurements of the net pension and other post-retirement benefit liability or asset Cash flow hedges that will subsequently be transferred to the balance sheet Other comprehensive income 33. Contingent liabilities and legal proceedings Pre-tax Tax Net of tax $ million 2020 (2,196) 41 64 312 — 170 7 (1,602) 9 (10) (4) — 71 (105) — (39) (2,187) 31 60 312 71 65 7 (1,641) $ million 2019 Pre-tax Tax Net of tax 2,418 6 53 82 — 328 (3) 2,884 (2) (1) (3) — (64) (157) — (227) 2,416 5 50 82 (64) 171 (3) 2,657 $ million 2018 Pre-tax Tax Net of tax (3,771) (6) (186) 417 — 2,317 (37) (1,266) (16) — 13 — 7 (718) — (714) (3,787) (6) (173) 417 7 1,599 (37) (1,980) Contingent liabilities There were contingent liabilities at 31 December 2020 in respect of guarantees and indemnities entered into as part of the ordinary course of the group’s business. No material losses are likely to arise from such contingent liabilities. Further information on financial guarantees is included in Note 29. In the normal course of the group’s business, bp group entities are subject to legal and regulatory proceedings arising out of current and past operations, including matters related to commercial disputes, product liability, antitrust, commodities trading, premises-liability claims, consumer protection, general health, safety, climate change and environmental claims and allegations of exposures of third parties to toxic substances, such as lead pigment in paint, asbestos and other chemicals. The amounts claimed could be significant and could be material to the group’s results of operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, bp expects that the impact of current legal and regulatory proceedings on the group‘s results of operations, liquidity or financial position will not be material. The group files tax returns in many jurisdictions across the world. Various tax authorities are currently examining these returns, which contain matters that could be subject to differing interpretations of applicable tax laws and regulations. The resolution of tax positions through negotiations with relevant tax authorities, or through litigation, can take several years to complete and the amounts could be significant and could, in aggregate, be material to the group’s results of operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, bp does not expect there to be any material impact upon the group‘s results of operations, financial position or liquidity. bp Annual Report and Form 20-F 2020 225 33. Contingent liabilities and legal proceedings – continued The group is subject to numerous national and local health, safety and environmental laws and regulations concerning its products, operations and other activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of prior disposal or release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites including refineries, chemical plants, oil fields, commodities extraction sites, service stations, terminals and waste disposal sites. In addition, the group may have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its costs are inherently difficult to estimate. However, the estimated cost of environmental obligations has been provided in these accounts in accordance with the group‘s accounting policies. While the amounts of future possible costs that are not provided for could be significant and material to the group‘s results of operations in the period in which they are recognized, it is not possible to estimate the amounts involved. bp does not expect these costs to have a material impact on the group’s results of operations, financial position or liquidity. If oil and natural gas production facilities and pipelines are sold to third parties and the subsequent owner is unable to meet their decommissioning obligations it is possible that, in certain circumstances, bp could be partially or wholly responsible for decommissioning. While the amounts associated with decommissioning provisions reverting to the group could be significant and could be material, bp is not currently aware of any such material cases that have a greater than remote chance of reverting to the group. In one current case in the US, the owner of facilities has filed for bankruptcy and submitted a proposed restructuring plan. It is considered possible that certain decommissioning costs associated with some of these facilities may in the future revert to bp in relation to assets previously disposed. No provision has been recognised and no reliable estimate of this potential exposure is available, however any amount which may revert is not expected to have a material impact on the group’s financial position. Furthermore, as described in Provisions and contingencies within Note 1, decommissioning provisions associated with downstream facilities are not generally recognized as the potential obligations cannot be measured given their indeterminate settlement dates. Contingent liabilities related to the Gulf of Mexico oil spill For information on legal proceedings relating to the Deepwater Horizon oil spill, see Legal proceedings below. Any further outstanding Deepwater Horizon related claims are not expected to have a material impact on the group's financial performance. Legal proceedings Proceedings relating to the Deepwater Horizon oil spill Introduction BP Exploration & Production Inc. (BPXP) was lease operator of Mississippi Canyon, Block 252 in the Gulf of Mexico, where the semi-submersible rig Deepwater Horizon was deployed at the time of the 20 April 2010 explosion and fire and resulting oil spill (the Incident). Lawsuits and claims arising from the Incident were brought principally in US federal and state courts. The remaining proceedings arising from the Incident are discussed below. Economic and Property Damages Settlement On 22 January 2021, the United States District Court for the Eastern District of Louisiana issued an order determining the completion of all claims processing operations of the court supervised settlement programme. That settlement programme had been established to administer claims pursuant to the Economic and Property Damages Settlement (EPD Settlement) which was entered into with the plaintiffs’ steering committee (PSC) acting on behalf of individual and business plaintiffs in the multi-district litigation proceedings in 2012 to resolve certain economic and property damage claims. The Court also ordered that all future issues concerning EPD Settlement claims would be considered time barred under the settlement programme and that the claims administrator should proceed to complete post-closure administrative wind down activities. Medical Benefits Class Action Settlement In 2012 the Medical Benefits Class Action Settlement (Medical Settlement) was entered into with the PSC. It involves payments to qualifying class members based on a matrix for certain Specified Physical Conditions (SPCs), as well as a 21-year Periodic Medical Consultation Program (PMCP) for qualifying class members. As of 31 December 2020, 1 claim remained pending determination. In total, 27,603 claims (comprising 22,833 SPC claims and 4,770 PMCP claims) have been approved for compensation totalling approximately $67 million and 9,623 claims have been denied. The Medical Settlement also includes provisions regarding class members pursuing claims for later-manifested physical conditions (LMPCs). In order to seek compensation from bp for an LMPC, class members must file a notice with the Medical Claims Administrator within 4 years after the date of first diagnosis of the LMPC. As of 31 December 2020, there were 612 pending lawsuits brought by class members claiming LMPCs. Other civil complaints – economic loss Nearly all economic loss and property damage claims from individuals and businesses that either opted out of the EPD Settlement and/or were excluded from that settlement have been settled or dismissed. The claims of 10 US-resident private plaintiffs remain in the multi-district litigation proceedings in federal district court in New Orleans. Those claims have been scheduled for a process of discovery and dispositive motions which is expected to conclude around mid-2021. Other civil complaints – personal injury The vast majority of post-explosion clean-up, medical monitoring and personal injury claims from individuals that either opted out of the Medical Settlement and/or were excluded from that settlement have been dismissed. In 2019, the federal district court in New Orleans determined in a series of proceedings that 923 plaintiffs had post-explosion clean-up, medical monitoring and personal injury claims that complied with the court’s prior order to show cause why their claims should not be dismissed. As a result of several subsequent dismissals, approximately 881 plaintiffs’ claims remained as of 31 December 2020. On 23 February 2021, the district court issued a Case Management Order announcing its intent to sever the personal injury cases from the multi- district litigation proceedings and staying the litigation of any punitive damages claims until plaintiffs can establish a right to compensatory damages. The district court also stated that the order severing and re-allotting these cases is forthcoming. Most cases will remain in the federal district court in New Orleans and be re-allotted among the judges of that court. Individual securities litigation In October 2020, bp engaged with the plaintiffs in a mediation of all remaining multi-district litigation proceedings in federal district court in Houston. 28 such actions on behalf of 115 plaintiffs remained pending on 31 December 2020. The mediation resulted in settlements of all these cases and settlement agreements have now been executed with all plaintiffs. 226 bp Annual Report and Form 20-F 2020 Financial statements 33. Contingent liabilities and legal proceedings – continued Canadian class actions Following various legal proceedings, a plaintiff seeking to assert claims under Canadian law against bp on behalf of a class of Canadian residents who allegedly suffered losses because of their purchase of bp ordinary shares and ADSs appealed the motion to dismiss the case in its entirety granted on 8 November 2019. On 20 January 2021, the Court of Appeal affirmed that dismissal. Non-US government lawsuits On 18 October 2012, before a Mexican Federal District Court located in Mexico City, a class action complaint was filed against BP America Production Company (BPAPC) and other bp subsidiaries. On 27 June 2018, bp answered the complaint by seeking dismissal on various grounds including that no oil reached Mexican waters or land and there was no economic or environmental harm in Mexico. There has been no material development in these proceedings during 2020 and up to the date of publication of this BP Annual Report and Form 20-F 2020 in 2021. On 3 December 2015 and 29 March 2016, Acciones Colectivas de Sinaloa (ACS) filed two class actions (which have since been consolidated) in a Mexican Federal District Court on behalf of several Mexican states against BPXP, BPAPC, and other purported bp subsidiaries. In these class actions, plaintiffs seek an order requiring the bp defendants to repair the damage to the Gulf of Mexico, to pay penalties, and to compensate plaintiffs for damage to property, to health and for economic loss. BPXP and BPAPC opposed class certification and sought dismissal, principally on the basis that no oil reached Mexican waters or land and there was no economic or environmental harm in Mexico. The court certified the class on 25 September 2019 and bp appealed that decision including by way of constitutional challenge (amparo). The amparo action was denied on 8 October 2020 and on 18 January 2021, bp’s appeal of that ruling was also denied. Class notification procedures have not yet been finally determined. These legal actions remain at a relatively early stage and while it is not possible to predict the outcome, bp believes that it has valid defences, and it intends to defend such actions vigorously. Other legal proceedings FERC and CFTC matters Following an investigation by the US Federal Energy Regulatory Commission (FERC) and the US Commodity Futures Trading Commission (CFTC) of several bp entities, the Administrative Law Judge of the FERC ruled on 13 August 2015 that bp manipulated the market by selling next-day, fixed price natural gas at Houston Ship Channel in 2008 in order to suppress the Gas Daily index and benefit its financial position. On 11 July 2016 the FERC issued an Order affirming the initial decision and directing bp to pay a civil penalty of $20.16 million and to disgorge $207,169 in unjust profits. On 10 August 2016, bp filed a request for rehearing with the FERC. On 17 December 2020, the FERC denied the rehearing request, sustaining the prior decision and ordering payment of the penalty and disgorgement amounts. bp has complied with the order but strongly disagrees with the FERC’s decision and is pursuing an appeal to the US Court of Appeals. Lead paint matters Since 1987, Atlantic Richfield Company (Atlantic Richfield), a subsidiary« of bp, has been named as a co-defendant in numerous lawsuits brought in the US alleging injury to persons and property caused by lead pigment in paint. The majority of the lawsuits have been abandoned or dismissed against Atlantic Richfield. Atlantic Richfield is named in these lawsuits as alleged successor to International Smelting and Refining and another company that manufactured lead pigment during the period 1920-1946. The plaintiffs include individuals and governmental entities. Several of the lawsuits purport to be class actions. The lawsuits seek various remedies including compensation to lead-poisoned children, cost to find and remove lead paint from buildings, medical monitoring and screening programmes, public warning and education of lead hazards, reimbursement of government healthcare costs and special education for lead-poisoned citizens and punitive damages. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgment in any proceeding. The amounts claimed and, if such suits were successful, the costs of implementing the remedies sought in the various cases could be substantial. While it is not possible to predict the outcome of these legal actions, Atlantic Richfield believes that it has valid defences. It intends to defend such actions vigorously and believes that the incurrence of liability is remote. Consequently, bp believes that the impact of these lawsuits on the group’s results, financial position or liquidity will not be material. Climate change BP p.l.c., BP America Inc. and BP Products North America Inc. are co-defendants with other oil and gas companies in multiple lawsuits brought in various state and federal courts on behalf of various governmental and private parties. The lawsuits generally assert claims under a variety of legal theories seeking to hold the defendant companies responsible for impacts allegedly caused by and/or relating to climate change and seek remedies including payment of money and other forms of equitable relief. If such suits were successful, the cost of the remedies sought in the various cases could be substantial. All of these lawsuits remain at relatively early stages and while it is not possible to predict the outcome of these legal actions, BP believes that it has valid defences, and it intends to defend such actions vigorously. Louisiana Coastal restoration  Six coastal parishes and the State of Louisiana have filed over 40 separate lawsuits in state courts in Louisiana against various oil and gas companies seeking damages for coastal erosion. bp entities are defendants in 17 of these cases. The lawsuits allege that the defendants' historical operations in oil fields within the Louisiana onshore coastal zone failed to comply with state permits and/or were conducted without the required coastal use permits. The plaintiffs seek unspecified statutory penalties and damages, including the costs of restoring coastal wetlands allegedly impacted by oil field operations. In addition, four private landowners have filed separate claims in the state courts in Jefferson and Plaquemines Parishes of Louisiana for restoration damages related to alleged impacts to their marshlands associated with historic oil field operations. bp entities are defendants in two of these private landowner cases. All of these lawsuits remain at relatively early stages and while it is not possible to predict the outcome of these legal actions, bp believes that it has valid defences, and it intends to defend such actions vigorously. bp Annual Report and Form 20-F 2020 227 34. Remuneration of senior management and non-executive directors Remuneration of directors Total for all directors Emoluments Amounts received under incentive schemesa Total a Excludes amounts relating to past directors. 2020 2019 6 14 20 9 20 29 $ million 2018 8 16 24 Emoluments These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits earned during the relevant financial year, plus cash bonuses awarded for the year. Pension contributions During 2020 one executive director participated in a UK final salary pension plan in respect of service prior to 1 April 2011. During 2020, one executive director participated in retirement savings plans established for US employees and in a US defined benefit pension plan in respect of service prior to 1 September 2016. Further information Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 103. See also Related-party transactions on page 326. Remuneration of directors and senior management Total for all senior management and non-executive directors Short-term employee benefits Pensions and other post-retirement benefits Share-based payments Termination benefits Total 2020 2019 $ million 2018 17 2 52 8 79 30 2 32 — 64 25 2 32 — 59 Senior management comprises members of the leadership team, see pages 78-79 for further information. Short-term employee benefits These amounts comprise fees and benefits paid to the non-executive chairman and non-executive directors, as well as salary, benefits and cash bonuses for senior management. Deferred annual bonus awards, to be settled in shares, are included in share-based payments. Pensions and other post-retirement benefits The amounts represent the estimated cost to the group of providing pensions and other post-retirement benefits to senior management in respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’. Share-based payments This is the cost to the group of senior management’s participation in share-based payment plans, as measured by the fair value of options and shares granted, accounted for in accordance with IFRS 2 ‘Share-based Payments’. Termination benefits Termination benefits include compensation to senior management for loss of office. 228 bp Annual Report and Form 20-F 2020 35. Employee costs and numbers Employee costs Wages and salariesa Social security costs Share-based paymentsb Pension and other post-retirement benefit costs Average number of employeesc Upstream Downstreamd Other businesses and corporatee  Financial statements 2020 7,600 729 728 852 9,909 2019 7,497 733 694 948 9,872 $ million 2018 7,931 743 669 1,154 10,497 2020 2019 2018 US Total Non-US Non-US Total 5,900 11,500 17,400 6,000 36,300 42,300 1,900 12,100 14,000 12,400 55,700 68,100 13,600 58,900 72,500 13,800 59,900 73,700 Non-US 5,800 11,000 16,800 5,700 37,300 43,000 2,100 10,600 12,700 4,800 10,600 15,400 5,800 37,800 43,600 9,100 7,300 1,800 Total US US a Includes termination costs of $1,237 million (2019 $182 million and 2018 $493 million). Reinvent bp restructuring accruals of $714 million and provisions of $428 million for employee termination payments were held at 31 December 2020. b The group provides certain employees with shares and share options as part of their remuneration packages. The majority of these share-based payment arrangements are equity-settled. c Reported to the nearest 100. d Includes 19,100 (2019 18,100 and 2018 17,100) service station staff. e Includes 0 (2019 2,500 and 2018 4,000) agricultural, operational and seasonal workers in Brazil. The reduction in the average number of employees in 2020 compared to 2019 is principally a result of the reinvent bp programme and divestment activity. 36. Auditor’s remuneration Fees The audit of the company annual accountsa The audit of accounts of subsidiaries of the company Total audit Audit-related assurance servicesb Total audit and audit-related assurance services Non-audit and other assurance services Services relating to bp pension plans 2020 30 11 41 11 52 1 1 54 2019 32 11 43 4 47 1 1 49 $ million 2018 25 10 35 4 39 2 1 42 a Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements. b Includes interim reviews and audit of internal control over financial reporting and non-statutory audit services. 2020 fees include audit fees relating to the Petrochemicals disposal. With effect from 2018, following a competitive tender process, Deloitte LLP (Deloitte) was appointed as auditor of the Company, replacing Ernst & Young LLP (EY). 2020 includes $0.5 million of additional fees for 2019. 2019 includes $3.6 million of additional fees for 2018. In addition to the amounts shown in the table above, in 2018 $0.75 million of additional fees were paid to EY in respect of their audit for 2017. Auditor's remuneration is included in the income statement within distribution and administration expenses. Tax services (in relation to income tax, indirect tax compliance, employee tax services and tax advisory services) were $nil in all periods presented. The audit committee has established pre-approval policies and procedures for the engagement of Deloitte to render audit and certain assurance and other services. The audit fees payable to Deloitte were considered as part of the audit tender process in 2016 and challenged by the audit committee through comparison with the audit pricing proposals of the other bidding firms. Changes in audit fees subsequent to the audit tender, including matters relevant to the 2020 audit, have been reviewed and challenged by the Audit Committee, before being approved. Deloitte performed further assurance services that were not prohibited by regulatory or other professional requirements and were pre-approved by the Committee. Deloitte is engaged for these services when its expertise and experience of bp are important. Most of this work is of an audit-related or assurance nature. Under SEC regulations, the remuneration of the auditor of $54 million (2019 $49 million and 2018 $42 million) is required to be presented as follows: audit $41 million (2019 $43 million and 2018 $35 million); other audit-related $11 million (2019 $4 million and 2018 $4 million); tax $nil (2019 $nil and 2018 $nil); and all other fees $2 million (2019 $2 million and 2018 $3 million). bp Annual Report and Form 20-F 2020 229 37. Subsidiaries, joint arrangements and associates The more important subsidiaries and associates of the group at 31 December 2020 and the group percentage of ordinary share capital (to nearest whole number) are set out below. There are no individually significant incorporated joint arrangements. The group's share of the assets and liabilities of the more important unincorporated joint arrangements are held by subsidiaries listed in the table below. Those subsidiaries held directly by the parent company are marked with an asterisk (*), the percentage owned being that of the group unless otherwise indicated. A complete list of undertakings of the group is included in Note 14 in the parent company financial statements of BP p.l.c. which are filed with the Registrar of Companies in the UK, along with the group’s annual report. Subsidiaries International BP Corporate Holdings BP Exploration Operating Company *BP Global Investments *BP International BP Oil International *Burmah Castrol Angola BP Exploration (Angola) Azerbaijan BP Exploration (Caspian Sea) BP Exploration (Azerbaijan) Canada *BP Holdings Canada Egypt BP Exploration (Delta) Germany BP Europa SE India BP Exploration (Alpha) Trinidad & Tobago BP Trinidad and Tobago UK BP Capital Markets US *BP Holdings North America Atlantic Richfield Company BP America BP America Production Company BP Company North America BP Corporation North America BP Products North America Standard Oil Company BP Capital Markets America Associates Russia Rosneft Oil Company Country of incorporation % Principal activities 100 England & Wales 100 England & Wales 100 England & Wales 100 England & Wales 100 England & Wales 100 Scotland Investment holding Exploration and production Investment holding Integrated oil operations Integrated oil operations Lubricants 100 England & Wales Exploration and production 100 England & Wales 100 England & Wales Exploration and production Exploration and production 100 England & Wales Investment holding 100 England & Wales Exploration and production 100 Germany Refining and marketing 100 England & Wales Exploration and production 70 US Exploration and production 100 England & Wales Finance 100 England & Wales 100 US 100 US 100 US 100 US 100 US 100 US 100 US 100 US Investment holding Exploration and production, refining and marketing Finance Country of incorporation % Principal activities 19.75 Russia Integrated oil operations 38. Condensed consolidating information on certain US subsidiaries On June 30, 2020, bp completed the sale of all its interest in BP Exploration (Alaska) Inc., to Hilcorp Energy, and BP Exploration (Alaska) Inc. is therefore no longer a subsidiary of BP p.l.c. Accordingly, bp is no longer presenting condensed consolidating information on BP Exploration (Alaska) Inc. as a subsidiary issuer of registered securities pursuant to Rule 3-10 of Regulation S-X. BP p.l.c. will continue to fully and unconditionally guarantee the payment obligations under the BP Prudhoe Bay Royalty Trust. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Capital Markets p.l.c. and BP Capital Markets America Inc., which are 100%-owned finance subsidiaries of BP p.l.c. 230 bp Annual Report and Form 20-F 2020 Financial statements Supplementary information on oil and natural gas (unaudited) The regional analysis presented below is on a continent basis, with separate disclosure for countries that contain 15% or more of the total proved reserves (for subsidiaries plus equity-accounted entities), in accordance with SEC and FASB requirements. Oil and gas reserves – certain definitions Unless the context indicates otherwise, the following terms have the meanings shown below: Proved oil and gas reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any; and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favourable than in the reservoir as a whole, the operation of an installed programme in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or programme was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Undeveloped oil and gas reserves Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. Developed oil and gas reserves Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) (ii) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. For details on bp’s proved reserves and production compliance and governance processes, see pages 312-317. bp Annual Report and Form 20-F 2020 231 Oil and natural gas exploration and production activities Subsidiaries Capitalized costs at 31 Decembera b Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs Europe Rest of Europe UK South America North America Rest of North America US Africa Asia Australasia Total Russia Rest of Asia $ million 2020 31,729 410 32,139 22,501 9,638 — 63,803 3,431 15,526 49,736 — 44,031 — 3,102 2,644 2,477 3,560 — 1,584 — 66,905 6,075 18,003 53,296 — 45,615 — 37,176 3,852 14,488 42,575 — 26,246 — 29,729 2,223 3,515 10,721 — 19,369 6,409 214,665 640 14,417 7,049 229,082 4,282 151,120 2,767 77,962 Costs incurred for the year ended 31 Decembera b Acquisition of properties Proved Unproved Exploration and appraisal costsc Development Total costs — — — 86 365 451 1 — 25 — 26 — 233 — — 2,966 — 3,225 — 2 2 127 9 138 — (1) (1) 69 — — — — — — 1 — 16 16 265 451 1,507 — 2,222 1 2,503 519 1,675 168 Results of operations for the year ended 31 Decembera Sales and other operating revenuesd Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income)e Depreciation, depletion and amortization Net impairments and (gains) losses on sale of businesses and fixed assets Profit (loss) before taxationf Allocable taxes Results of operations 36 1,759 1,795 93 636 (22) (130) 1,370 2,712 4,659 (2,864) (1,344) (1,520) 813 1,553 113 — 687 — — 6,274 — 6,961 866 3,194 113 — 2,724 2,579 2,185 2,289 102 — 2,058 — — 57 301 1 1,633 93 — 3,655 2 1,378 53 1,641 — 4,805 2 6,183 367 1 875 817 — 508 — — 97 44 2 1,994 421 140 117 157 678 2,459 5 1,716 6 11,843 3,941 6,234 7,764 (6) (4,882) (3,828) (5,368) (4,570) (308) — (1,125) (6) (3,757) (3,146) (3,566) (4,262) 866 2,693 2,042 — 1,839 47 5,680 503 (45) 1 1,923 (46) (1,420) (682) (1,802) Upstream and Rosneft segments replacement cost profit (loss) before interest and tax Exploration and production activities – — — — 43 1 42 43 992 130 7,650 173 8,685 610 5,192 277 14,809 887 20,001 42 10,280 114 5,023 695 113 2,333 335 10,586 12 — 11,873 616 40,790 271 (20,789) (3,246) 180 (17,543) 91 subsidiaries (as above) Midstream and other activities – subsidiariesg Equity-accounted entitiesh Total replacement cost profit (loss) before interest and tax (2,864) (356) — (6) (4,882) (3,828) (5,368) (4,570) (14) 185 44 (242) — 31 104 (211) (302) 17 (45) (8) (224) 503 (163) 224 271 (20,789) (502) (405) 8 — (3,220) 69 (5,167) (3,643) (5,475) (4,826) (277) 564 279 (21,696) a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are excluded. The most significant midstream pipeline interests include the South Caucasus Pipeline, the Baku-Tbilisi-Ceyhan pipeline, the Trans Adriatic Pipeline and the Trans Anatolian Pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia. b Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year. c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. d Presented net of transportation costs, purchases and sales taxes. e Includes property taxes and other government take. The UK region includes a $330-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance programme. f Excludes the unwinding of the discount on provisions and payables amounting to $369 million which is included in finance costs in the group income statement. g Midstream and other activities excludes inventory holding gains and losses. h The profits of equity-accounted entities are included after interest and tax. 232 bp Annual Report and Form 20-F 2020 Oil and natural gas exploration and production activities – continued Financial statements $ million 2020 Europe UK Rest of Europe South America North America Rest of North America US Africa Asia Australasia Total Russiaa Rest of Asia Equity-accounted entities (bp share) Capitalized costs at 31 Decemberb c Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs Costs incurred for the year ended 31 Decemberb d e Acquisition of propertiesc Proved Unproved Exploration and appraisal costsd Development Total costs Results of operations for the year ended 31 Decemberb Sales and other operating revenuesf Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income) Depreciation, depletion and amortization Net impairments and losses on sale of businesses and fixed assets Profit (loss) before taxation Allocable taxes Results of operations — 4,457 — 806 — 5,263 — 1,592 — 3,671 — — — — — — — — — — — — — — — — — — — — — 46 404 450 860 — 860 50 188 — 3 412 119 772 88 15 73 — — — — — — — — — — — — — — — — — — — — — — — — — 10,690 — 24,963 — 108 — 4,627 — 10,798 — 29,590 — 5,490 — 7,693 — 5,308 — 21,897 — — — — — — — — 82 — — 3,714 — — 3,796 315 15 — 393 — 2,594 408 — 6,705 — — 1,110 — — — — 9,344 — 1,110 — 9,344 109 — — — 486 — 1,387 — 216 — 4,418 — — 236 411 — 1,532 — 5 — — 294 108 — — 1,226 — 7,976 (116) — 1,368 — 226 — (41) — (75) — 1,142 — — — — — — — — — — — — — — — — — — — — — — — — — Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities Exploration and production activities – equity- accounted entities after tax (as above) Midstream and other activities after taxg Total replacement cost profit (loss) after (75) — 1,142 (242) (1,366) 73 (42) — 17 — — — — (136) — 224 — 40,110 — 5,541 — 45,651 — 14,775 — 30,876 — 82 — 3,714 — 3,796 376 — — 3,391 — 7,563 — 1,970 — 9,344 — 11,314 159 — — 2,061 — 4,634 — 244 — 2,355 — 521 — 9,974 — 1,340 200 — — 1,140 — 1,140 — (1,545) interest and tax — 31 17 — (211) (242) (224) 224 — (405) a Amounts reported for Russia in this table include bp’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded. c Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year. d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. e The amounts shown reflect bp’s share of equity-accounted entities’ costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities. f Presented net of sales tax. g Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses. bp Annual Report and Form 20-F 2020 233 Oil and natural gas exploration and production activities – continued Subsidiaries Capitalized costs at 31 Decembera b Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Total Russia Rest of Asia $ million 2019 31,655 425 32,080 18,481 13,599 — 67,319 3,421 15,194 48,150 — 42,629 — 3,106 2,547 3,262 3,495 — 1,865 — 70,425 5,968 18,456 51,645 — 44,494 — 35,379 409 9,922 35,572 — 22,481 — 35,046 5,559 8,534 16,073 — 22,013 6,300 214,668 606 15,306 6,906 229,974 3,924 126,168 2,982 103,806 Costs incurred for the year ended 31 Decembera b Acquisition of properties Proved Unproved Exploration and appraisal costsc Development Total costs 2 13 15 128 717 860 5 — 50 — 55 — 271 — — 4,047 — 4,373 Results of operations for the year ended 31 Decembera Sales and other operating revenuesd Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income)e Depreciation, depletion and amortization Net impairments and (gains) losses on sale of businesses and fixed assets Profit (loss) before taxationf Allocable taxes Results of operations 229 2,345 2,574 157 607 (75) (308) 1,383 483 2,247 327 (141) 468 — 1,780 — 10,785 — 12,565 233 — — 2,742 — 315 — 2,527 — 4,456 (10) 5,726 (10) 15,999 (3,434) 10 (776) — (2,658) 10 — 1 1 15 33 49 1,177 2,965 188 — — 220 188 220 171 220 737 2,530 — 2,614 2 2,973 — — 18 — 18 — 2 417 1 274 1,620 2,736 2 1,588 142 2,815 — 7,596 2 9,184 275 1,762 5,551 187 2 222 124 961 437 1,045 — 951 — — 293 (124) 42 33 92 2 2,384 118 1,056 3,806 13 118 — 67 — — — 61 195 302 497 1,285 137 10,815 198 12,597 1,142 9,371 554 24,238 1,696 33,609 964 26 6,041 131 1,547 63 153 2,482 297 13,502 151 — (1) 160 315 2,162 5,257 294 (400) (40) 593 (234) (76) (299) (166) 36 1 46 4,360 (44) 4,824 (8) 3,078 (36) 1,746 — 6,510 670 31,046 2,563 2,828 (265) 1,026 392 634 Upstream and Rosneft segments replacement cost profit (loss) before interest and tax Exploration and production activities – subsidiaries (as above) 327 10 (3,434) (40) (400) 294 (44) 4,824 1,026 2,563 Midstream and other activities – subsidiariesg Equity-accounted entitiesh Total replacement cost profit (loss) after interest and tax 749 (6) (26) 70 (363) 23 442 — 194 65 (19) 11 82 2,460 766 213 9 — 1,763 2,907 1,070 54 (3,774) 402 (141) 357 2,427 5,803 1,035 7,233 a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia. b Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year. c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. d Presented net of transportation costs, purchases and sales taxes. e Includes property taxes and other government take. The UK region includes a $361-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance programme. f Excludes the unwinding of the discount on provisions and payables amounting to $439 million which is included in finance costs in the group income statement. g Midstream and other activities excludes inventory holding gains and losses. h The profits of equity-accounted entities are included after interest and tax. 234 bp Annual Report and Form 20-F 2020 Oil and natural gas exploration and production activities – continued Financial statements $ million 2019 Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Total Russiaa Rest of Asia Equity-accounted entities (bp share) Capitalized costs at 31 Decemberb c Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs Costs incurred for the year ended 31 Decemberb d e Acquisition of propertiesc Proved Unproved Exploration and appraisal costsd Development Total costs — 4,078 — 768 — 4,846 — 1,046 — 3,800 — — — — — — — — — 120 640 760 Results of operations for the year ended 31 Decemberb Sales and other operating revenuesf Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income) Depreciation, depletion and amortization Net impairments and losses on sale of businesses and fixed assets Profit (loss) before taxation Allocable taxes Results of operations — 1,002 — — — 1,002 92 — 216 — — — 59 — 323 — — — — — — — 690 312 229 83 — — — — — — — — — — — — — — — — — — — — — — — — — 10,376 — 93 — 10,469 — 5,078 — 5,391 — 28,179 — 1,097 — 29,276 — 8,477 — 20,799 — — — — — — — — — 19 675 694 — — 58 — 58 — 177 — — 2,908 — 3,143 — 1,621 — — — 1,621 43 — 465 — 343 — 16 — 414 — — (42) — 1,239 382 — 245 — 137 — — — — 15,012 — 15,012 73 — — 1,386 — 7,413 — 346 — 1,657 — 46 — 10,921 — 4,091 811 — — 3,280 — — — — — — — — — — — — — — — — — — — — — — — — Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities Exploration and production activities – equity- accounted entities after tax (as above) — (6) 83 (13) — 23 — — 137 (72) — 3,280 (820) 82 — 213 Midstream and other activities after taxg Total replacement cost profit (loss) after interest and tax (6) 70 23 — 65 82 2,460 213 — 2,907 a Amounts reported for Russia in this table include bp’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. Amounts reported have been amended to exclude the corresponding amounts for their equity-accounted entities. b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded. c Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year. d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. e The amounts shown reflect bp’s share of equity-accounted entities’ costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities. f Presented net of sales tax. g Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses. bp Annual Report and Form 20-F 2020 235 — 42,633 — 1,958 — 44,591 — 14,601 — 29,990 — — 58 — 58 — 316 — — 4,223 — 4,597 — 2,623 — 15,012 — 17,635 208 — — 2,067 — 7,756 — 421 — 2,394 — 4 — 12,850 — 4,785 — 1,285 — 3,500 — 3,500 (593) — Oil and natural gas exploration and production activities – continued Subsidiaries Capitalized costs at 31 Decembera b Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Total Russia Rest of Asia $ million 2018 29,730 451 30,181 16,809 13,372 — 89,069 3,385 14,269 51,980 — 38,315 — 3,602 2,667 2,742 3,870 — 3,153 — 92,671 6,052 17,011 55,850 — 41,468 — 47,051 420 8,517 38,324 — 20,173 — 45,620 5,632 8,494 17,526 — 21,295 6,119 232,867 568 17,053 6,687 249,920 3,626 134,920 3,061 115,000 Costs incurred for the year ended 31 Decembera b Acquisition of properties Proved Unproved Exploration and appraisal costsc Development Total costs 1,933 — 1,933 238 817 2,988 — 10,650 — 35 — 10,685 216 — — 3,429 — 14,330 — — — 139 46 185 (1) — 50 — 49 — 5 36 — (5) 100 31 100 148 245 591 2,340 — 2,458 5 2,637 936 2,672 283 Results of operations for the year ended 31 Decembera Sales and other operating revenuesd Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income)e Depreciation, depletion and amortization Net impairments and (gains) losses on sale of businesses and fixed assets Profit (loss) before taxationf Allocable taxesg Results of operations 619 2,255 2,874 105 646 (269) (331) 1,199 (226) 1,124 1,750 446 1,304 — 1,306 — 11,656 — 12,962 509 — — 2,729 — 369 (2) 2,379 — 3,921 — 203 (2) 10,110 2 2,852 454 — 2 2,398 1 105 2,074 3,228 — 1,430 195 3,928 — 7,793 106 2,269 7,156 — 9,223 20 5 405 252 146 430 1,066 — 120 951 — — 1,010 357 — 94 42 165 43 133 101 1,023 3,635 — 2,165 (141) — 10 — 420 2,227 5,098 42 2,058 (314) 314 1,184 (95) 874 (272) (219) 21 47 4,261 (47) 4,962 13 3,509 (60) 1,453 Upstream and Rosneft segments replacement cost profit (loss) before interest and tax Exploration and production activities – 1,750 (20) (2) 2 2,852 188 28 265 130 (314) (111) — 42 2,058 (58) 5 207 2,346 (47) 4,962 463 245 135 209 subsidiaries (as above) Midstream and other activities – subsidiariesh Equity-accounted entitiesi j Total replacement cost profit (loss) after interest and tax — 12,618 — 180 — 12,798 1,298 24 236 9,917 260 24,013 1,410 10,172 665 26,493 2,075 36,665 1,445 3 6,080 138 1,536 69 223 2,746 298 12,342 136 3 867 24,152 1,208 12,513 6,333 6,180 508 700 1,208 12,513 873 3,163 6 — 1,728 397 3,068 (425) 386 2,207 2,304 5,670 1,214 16,549 a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production activities of joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia. b Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year. c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. d Presented net of transportation costs, purchases and sales taxes. e Includes property taxes, other government take and the fair value gain on embedded derivatives of $17 million. The UK region includes a $384-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance programme. f Excludes the unwinding of the discount on provisions and payables amounting to $208 million which is included in finance costs in the group income statement. g US region includes the deferred tax impact of the reduction in the US Federal corporate income tax rate from 35% to 21% enacted in December 2017. h Midstream and other activities excludes inventory holding gains and losses. i The profits of equity-accounted entities are included after interest and taxes. j From 16 December 2017, bp entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by bp and 40% by Bridas Corporation. 236 bp Annual Report and Form 20-F 2020 Oil and natural gas exploration and production activities – continued Financial statements $ million 2018 Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Total Russiaa Rest of Asia Equity-accounted entities (bp share) Capitalized costs at 31 Decemberb c Gross capitalized costs Proved properties Unproved properties Accumulated depreciation Net capitalized costs Costs incurred for the year ended 31 Decemberb d e Acquisition of propertiesc Proved Unproved Exploration and appraisal costsd Development Total costs — 3,439 — 657 — 4,096 — 670 — 3,426 — — — — — — — 137 137 67 251 455 Results of operations for the year ended 31 Decemberb Sales and other operating revenuesf Third parties Sales between businesses Exploration expenditure Production costs Production taxes Other costs (income) Depreciation, depletion and amortization Net impairments and losses on sale of businesses and fixed assets Profit (loss) before taxation Allocable taxes Results of operationsg — 1,114 — — — 1,114 89 — 207 — — — 21 — 290 — — — — — — 6 613 501 350 151 — — — — — — — — — — — — — — — — — — — — — — — — — 9,643 — 86 — 9,729 — 4,665 — 5,064 — 22,561 3,646 — 26 811 — 23,372 3,672 — 6,050 3,672 — — 17,322 — 39,289 — 1,580 — 40,869 — 15,057 — 25,812 — — — — — — — — — 25 575 600 393 — 148 — 541 — 179 — — 3,085 — 3,805 — 1,792 — — — 1,792 7 — 438 — 361 — 55 — 416 — — — — 1,277 515 — 321 — 194 — — — — 14,839 — 14,839 109 — — 1,324 — 7,168 — 594 — 1,514 — 47 — 10,756 — 4,083 814 — — 3,269 — — — — 212 212 353 — 353 — 39 94 — 212 1 346 7 — 7 393 — 285 — 678 — 271 — — 4,123 — 5,072 — 3,259 — 14,839 — 18,098 205 — — 2,008 — 7,623 — 670 — 2,432 — 54 — 12,992 — 5,106 — 1,485 — 3,621 — 3,621 (458) — — 3,163 Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities Exploration and production activities – equity- accounted entities after tax (as above) Midstream and other activities after taxh Total replacement cost profit (loss) after — 3,269 (923) 194 15 151 (21) — 28 — (2) — — 207 7 238 (2) 130 28 — 209 207 2,346 245 interest and tax a Amounts reported for Russia in this table include bp’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. The amounts reported have been amended to exclude the corresponding amounts for their equity-accounted entities. b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded. c Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year. d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. e The amounts shown reflect bp’s share of equity-accounted entities’ costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities. f Presented net of sales taxes. g From 16 December 2017, bp entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by bp and 40% by Bridas Corporation. h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses. bp Annual Report and Form 20-F 2020 237     Movements in estimated net proved reserves Crude oila b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberd Developed Undeveloped Equity-accounted entities (bp share)e At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberf g Developed Undeveloped Europe UK Rest of Europe North America South America Rest of North America USc Africa Asia Australasia Total Russia Rest of Asiac million barrels 2020 206 200 406 (62) — — — (35) — (97) 162 148 309 — — — — — — — — — — — — — — 1,063 — 842 — 1,905 40 179 218 — — — — — — — (17) 24 — 2 (125) (351) (467) 22 — — — (8) — 14 697 — — 742 — 1,438 37 195 232 115 35 150 (5) 10 — — (18) — (14) 112 24 136 — — — — — — — — — — — — — — 20 20 6 — — — — — 6 5 21 26 40 198 238 42 215 258 7 5 12 — — — 5 — — 5 8 9 16 291 257 548 2 — 1 17 (21) (35) (36) 275 237 512 298 262 560 283 246 529 156 40 196 (17) 3 — — (44) — (58) 116 21 137 — 1,074 — 525 — 1,599 26 2,572 4 1,794 30 4,367 — — — — — — — 175 — — 11 (137) — 48 14 — — — (5) — 8 114 27 — 18 (355) (351) (547) — 1,100 — 547 — 1,647 34 2,154 5 1,666 38 3,819 2 3,159 — 2,535 2 5,695 1 — — — 1 31 — 643 238 (330) (662) (79) 2 3,123 — 2,493 3 5,615 — — — — — — — — — — — — 1 — 3,567 — 2,847 — 6,414 — — — — — — — 35 10 644 255 (369) (697) (122) — 3,517 — 2,776 — 6,293 158 3,159 1,074 525 198 5,695 1,599 40 2,535 26 6,140 4 4,642 30 10,781 119 3,123 1,100 548 140 5,615 1,648 22 2,493 34 5,671 5 4,441 38 10,112 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 206 200 406 115 1,063 842 150 1,905 35 At 31 December Developed Undeveloped 162 148 309 112 24 697 742 136 1,438 a Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes 37 million barrels of crude oil associated with Assets Held for Sale in Oman. d Includes 5 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Includes  393 million barrels of crude oil in respect of the 7.09% non-controlling interest in Rosneft, including 18.53 mmbbl held through bp's interests in Russia other than Rosneft. g Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,533 million barrels, comprising less than 1 million barrels each in Egypt, Vietnam, Iraq and Canada, 0 million barrels in Venezuela and 5,531 million barrels in Russia. 238 bp Annual Report and Form 20-F 2020 Movements in estimated net proved reserves – continued Natural gas liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiond Sales of reserves-in-place At 31 Decembere Developed Undeveloped Equity-accounted entities (bp share)f At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberg h Developed Undeveloped Financial statements million barrels 2020 Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Total Russia Rest of Asiac 8 5 13 (5) — — — (2) — (7) 7 — 7 — — — — — — — — — — — — — — — — — — — — — — — — — — 5 3 7 1 — — — (1) — — 6 1 7 5 3 7 6 1 7 229 250 479 (22) 1 — — (31) (94) (146) 115 218 333 — — — — — — — — — — — — — 229 250 479 115 218 333 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 2 21 23 — — — — (3) — (2) 2 19 21 2 — 2 — — — — — — — 2 — 2 4 21 25 4 19 23 12 4 16 1 — — — (3) — (2) 13 1 14 11 — 11 3 — — — (2) — 1 12 — 12 23 4 27 25 1 26 — — — — — — — — — — — — — 89 52 141 9 — 16 — (2) (14) 10 108 43 151 89 52 141 108 43 151 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 4 — 4 (1) — — — (1) — (2) 2 — 2 — — — — — — — — — — — — — 4 — 4 2 — 2 255 280 535 (26) 1 — — (39) (94) (159) 139 237 376 107 55 162 12 — 16 — (5) (14) 10 129 44 172 363 334 697 268 281 549 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 8 5 13 At 31 December Developed Undeveloped 7 — 7 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes 0 million barrels of NGL associated with Assets Held for Sale in Oman. d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. e Includes  6 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. g Includes 12 million barrels of NGLs in respect of the 7.99% non-controlling interest in Rosneft. h Total proved NGL reserves held as part of our equity interest in Rosneft is 151 million barrels, comprising less than 1 million barrels each in Egypt, Venezuela, Vietnam and Canada, and 151 million barrels in Russia. bp Annual Report and Form 20-F 2020 239 Movements in estimated net proved reserves – continued Total liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiond Sales of reserves-in-place At 31 Decembere Developed Undeveloped Equity-accounted entities (bp share)f At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberg h Developed Undeveloped Europe UK Rest of Europe North America South America Rest of North America USc Africa Asia Australasia Total Russia Rest of Asiac million barrels 2020 214 205 420 (67) — — — (37) — (104) 168 148 316 — — — — — — — — — — — — — — 1,292 — 1,092 — 2,384 40 179 218 — — — — — — — (40) 25 — 2 (155) (445) (613) 22 — — — (8) — 14 812 — — 959 — 1,771 37 195 232 120 37 157 (4) 10 — — (19) (1) (14) 118 25 143 — — — — — — — — — — — — — — 20 20 6 — — — — 6 5 21 26 40 198 238 42 215 258 9 26 35 1 — — 5 (3) — 2 10 27 37 293 257 550 2 — 1 17 (21) (35) (36) 277 237 514 302 283 585 287 265 552 168 43 211 (16) 3 — — (47) — (60) 129 22 151 — 1,074 — 525 — 1,599 30 2,828 4 2,074 34 4,902 — — — — — — — 175 — — 11 (137) — 48 13 — — — (6) — 6 87 28 — 18 (394) (445) (706) — 1,100 — 547 — 1,647 36 2,293 5 1,903 41 4,196 13 3,248 — 2,588 13 5,836 4 — — (2) 2 39 — 660 238 (331) (675) (70) 15 3,231 — 2,535 15 5,766 — — — — — — — — — — — — 1 — 3,675 — 2,902 — 6,576 — — — — — — — 47 10 661 255 (374) (711) (112) — 3,645 — 2,819 — 6,465 181 3,248 1,074 525 224 5,836 1,599 43 2,588 30 6,502 4 4,976 34 11,478 144 3,231 1,100 548 166 5,766 1,648 23 2,535 36 5,938 5 4,722 41 10,661 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 214 205 420 120 1,292 37 1,092 157 2,384 At 31 December Developed Undeveloped 168 148 316 118 25 812 959 143 1,771 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes 37 million barrels associated with Assets Held for Sale in Oman. d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. e Also includes 11 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. g Includes  405 million barrels of liquids in respect of the non-controlling interest in Rosneft, including 19mmboe held through bp’s interests in Russia other than Rosneft. h Total proved liquid reserves held as part of our equity interest in Rosneft is 5,683 million barrels, comprising 0 million barrels in Venezuela, less than 1 million barrels each in Iraq, Canada, Egypt and Vietnam and 5,682 million barrels in Russia. 240 bp Annual Report and Form 20-F 2020 Movements in estimated net proved reserves – continued Natural gasa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiond Sales of reserves-in-place At 31 Decembere Developed Undeveloped Equity-accounted entities (bp share)f At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiond Sales of reserves-in-place At 31 Decemberg h Developed Undeveloped Financial statements billion cubic feet 2020 Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Total Russia Rest of Asiac 493 207 700 (252) 1 — — (92) — (342) 306 51 358 — — — — — — — — — — — — — — 6,330 — 2,127 — 8,458 — 2,192 1,163 — 2,235 742 — 4,427 1,905 — 3,667 — 3,401 — 7,068 2,256 16,101 1,132 9,844 3,389 25,946 580 — 545 — — — 1 — — (603) — (3,636) — (3,114) 1 — — — (1) — — (362) — — 93 (627) — (896) (26) — — 28 (367) — (364) — — — — — — — 570 — — 263 (376) — 457 (9) — — — 503 546 — 386 (293) (2,358) — (3,636) (301) (4,561) — 1,921 — 3,423 — 5,344 — 1,567 1,382 — 1,964 158 — 3,531 1,541 — 3,883 — 3,641 — 7,524 2,058 11,118 1,029 10,267 3,087 21,385 108 56 164 29 8 — — (35) (3) (2) 141 21 162 — — — — — — — — — — — — — — 1,130 6 447 6 1,577 508 9,324 — 8,067 508 17,391 2 — — — — — 2 (86) — — 139 (124) (28) (99) 285 1,022 — — 18 1,681 422 — (470) (69) — (1,361) 234 1,294 2 965 513 6 8 1,478 600 11,373 142 7,312 741 18,685 10 — 10 — — 1 — (5) — (4) 7 — 7 — 11,080 — 8,576 — 19,656 — 1,251 — 8 — 1,701 561 — (703) — — (1,393) — 1,426 — 13,088 — 7,994 — 21,082 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 493 207 700 108 6,330 56 2,127 164 8,458 — 3,323 1,670 9,324 3,677 6 2,682 742 8,067 3,401 6 6,004 2,413 17,391 7,078 2,256 27,181 1,132 18,421 3,389 45,601 At 31 December Developed Undeveloped 306 51 358 141 1,921 21 3,423 162 5,344 2 2,532 1,982 11,373 3,890 300 7,312 3,641 6 2,477 8 5,009 2,282 18,685 7,531 2,058 24,206 1,029 18,260 3,087 42,467 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes  1316 billion cubic feet of natural gas associated with Assets Held for Sale in Oman. d Includes 158 billion cubic feet of natural gas consumed in operations, 103 billion cubic feet in subsidiaries, 55 billion cubic feet in equity-accounted entities. e Includes 1,059 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. g Includes 1,640 billion cubic feet of natural gas in respect of the 10.01% non-controlling interest in Rosneft including 614 billion cubic feet held through bp’s interests in Russia other than Rosneft. h Total proved gas reserves held as part of our equity interest in Rosneft is 16,324 billion cubic feet, comprising 0 billion cubic feet in Venezuela, 7 billion cubic feet in Vietnam, 420 billion cubic feet in Egypt and 15,897 billion cubic feet in Russia. bp Annual Report and Form 20-F 2020 241 Movements in estimated net proved reserves – continued Total hydrocarbonsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione f Sales of reserves-in-place At 31 Decemberh Developed Undeveloped Equity-accounted entities (bp share)h At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione Sales of reserves-in-place At 31 Decemberi j Developed Undeveloped Europe UK Rest of Europe North America South America Rest of North America USd million barrels of oil equivalentc 2020 Africa Asia Australasia Total Russia Rest of Asiad 300 241 540 (110) — — — (53) — (163) 221 157 378 — — — — — — — — — — — — — — 2,384 — 1,459 — 3,842 40 179 218 60 — 118 — — — 3 — — (259) — (1,072) — (1,150) 22 — — — (8) — 14 — 1,143 — 1,549 — 2,692 37 195 232 387 411 798 (62) — — 21 (111) — (152) 280 366 646 369 171 540 (21) 3 — 5 (110) — (123) 367 50 417 — 1,707 — 1,111 — 2,818 419 5,604 199 3,771 618 9,375 — — — — — — — 273 — — 56 (202) — 127 174 11 122 — — — 84 — (57) (800) — (1,072) (46) (1,492) — 1,770 — 1,175 — 2,945 391 4,210 182 3,673 573 7,883 139 47 186 1 11 — — (25) (1) (15) 142 29 171 — — — — — — — — — — — — — — 21 21 7 — — — — — 7 5 22 27 488 334 822 100 4,856 — 3,978 100 8,834 (13) — 1 41 (42) (40) (53) 53 — 3 — (14) — 42 216 — 949 311 (412) (910) 153 443 326 769 118 5,192 25 3,796 143 8,988 2 — 2 — — — — (1) — — 1 — 2 — 5,585 — 4,381 — 9,965 — — — — — — — 263 11 954 352 (495) (951) 134 — 5,902 — 4,198 — 10,100 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 300 241 540 139 2,384 47 1,459 186 3,842 875 40 199 746 239 1,621 469 4,856 1,708 171 3,978 1,112 640 8,834 2,820 419 11,189 199 8,152 618 19,341 At 31 December Developed Undeveloped 221 157 378 142 1,143 29 1,549 171 2,692 43 724 692 217 259 1,415 485 5,192 1,771 74 3,796 1,175 560 8,988 2,946 391 10,112 182 7,871 573 17,982 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent. d Includes 264 million barrels of oil equivalent associated with Assets Held for Sale in Oman. e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. f Includes  27 million barrels of oil equivalent of natural gas consumed in operations, 18 million barrels of oil equivalent in subsidiaries, 10 million barrels of oil equivalent in equity-accounted entities. g Includes 194 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. h Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. i Includes  687 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 124mmboe held through bp’s interests in Russia other than Rosneft. j Total proved reserves held as part of our equity interest in Rosneft is 8,498 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Iraq and Canada, 0 million barrels of oil equivalent in Venezuela, 1 million barrels of oil equivalent in Vietnam, 73 million barrels of oil equivalent in Egypt and 8,423 million barrels of oil equivalent in Russia. 242 bp Annual Report and Form 20-F 2020 Movements in estimated net proved reserves – continued Crude oila b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decembere Developed Undeveloped Equity-accounted entities (bp share)f At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberg h Developed Undeveloped Financial statements million barrels 2019 Europe North America South America Africa Asia Australasia Total UK Rest of Europe USc d Rest of North America Russia Rest of Asia 223 243 466 (23) — — — (36) — (59) 206 200 406 — — — — — — — — — — — — — 962 — — 802 — 1,764 43 190 234 — — — — — — — 72 189 — 34 (143) (12) 141 (8) 1 — — (9) — (16) — 1,063 — 842 — 1,905 40 179 218 57 100 157 2 4 — — (13) — (7) 115 35 150 — — — — — — — — — — — — — — 19 19 1 — — — — — 1 — 20 20 43 209 253 40 198 238 8 5 14 1 — — — (3) — (2) 7 5 12 293 259 552 (13) — — 33 (24) — (4) 291 257 548 302 264 566 298 262 560 223 36 259 39 — — — (57) (45) (63) 156 40 196 — 1,126 — 482 — 1,608 30 2,615 5 1,763 34 4,378 — — — — — — — 104 — 1 11 (125) — (9) 2 — — — (6) — (4) 187 191 1 45 (378) (57) (12) — 1,074 — 525 — 1,599 26 2,572 4 1,794 30 4,367 1 3,190 — 2,414 1 5,604 1 — — — — — 1 158 — 7 277 (345) (6) 91 2 3,159 — 2,535 2 5,695 — — — — — — — — — — — — — — 3,541 — 2,792 — 6,333 — — — — — — — 147 4 7 310 (382) (6) 81 — 3,567 — 2,847 — 6,415 224 3,190 1,126 482 260 5,604 1,608 36 2,414 30 6,156 5 4,555 34 10,711 158 3,159 1,074 525 198 5,695 1,599 40 2,535 26 6,140 4 4,642 30 10,781 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 223 243 466 962 57 100 802 157 1,764 At 31 December Developed Undeveloped 206 200 406 115 1,063 842 150 1,905 35 a Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Includes 362 million barrels of crude oil associated with Assets Held for Sale in the USA. e Includes 4 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. g Includes 346 million barrels of crude oil in respect of the 6.17% non-controlling interest in Rosneft, including 26 mmbbl held through bp’s interests in Russia other than Rosneft. h Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,604 million barrels, comprising less than 1 million barrels in Egypt, Vietnam, Iraq and Canada, 35 million barrels in Venezuela and 5,568 million barrels in Russia. bp Annual Report and Form 20-F 2020 243 Movements in estimated net proved reserves – continued Natural gas liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiond Sales of reserves-in-place At 31 Decembere Developed Undeveloped Equity-accounted entities (bp share)f At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberg h Developed Undeveloped Europe North America South America Africa Asia Australasia Total UK Rest of Europe USc Rest of North America Russia Rest of Asia million barrels 2019 8 6 14 — 1 — — (1) — (1) 8 5 13 — — — — — — — — — — — — — — — — — — — — — — — — — — 4 3 7 — 1 — — (1) — — 5 3 7 4 3 7 5 3 7 266 246 511 (46) 62 — 1 (33) (17) (32) 229 250 479 — — — — — — — — — — — — — 266 246 511 229 250 479 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 2 25 27 (1) — — — (3) — (4) 2 21 23 — — — 3 — — — — — 2 2 — 2 2 25 27 4 21 25 14 4 18 — — — — (3) — (3) 12 4 16 7 — 7 5 — — — (2) — 4 11 — 11 22 4 26 23 4 27 — — — — — — — — — — — — — 103 51 154 (11) — — — (2) — (13) 89 52 141 103 51 154 89 52 141 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 5 — 5 — — — — (1) — (1) 4 — 4 — — — — — — — — — — — — — 5 — 5 4 — 4 295 280 576 (47) 63 — 1 (41) (17) (41) 255 280 535 114 54 169 (3) 1 — — (4) — (7) 107 55 162 409 335 744 363 334 697 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 8 6 14 At 31 December Developed Undeveloped 8 5 13 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes 94 million barrels of NGL associated with Assets Held for Sale in the USA. d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. e Includes 7 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. g Includes 11 million barrels of NGLs in respect of the 7.90% non-controlling interest in Rosneft. h Total proved NGL reserves held as part of our equity interest in Rosneft is 141 million barrels, comprising less than 1 million barrels in Egypt, Venezuela, Vietnam and Canada, and 141 million barrels in Russia. 244 bp Annual Report and Form 20-F 2020 Movements in estimated net proved reserves – continued Total liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione Sales of reserves-in-place At 31 Decemberf Developed Undeveloped Equity-accounted entities (bp share)g At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberh i Developed Undeveloped Financial statements million barrels 2019 Europe North America South America Africa Asia Australasia Total UK Rest of Europe USc d Rest of North America Russia Rest of Asia 231 249 480 (24) 1 — — (38) — (60) 214 205 420 — — — — — — — — — — — — — — 1,228 — 1,048 — 2,276 43 190 234 — — — — — — — 26 252 — 35 (176) (28) 109 (8) 1 — — (9) — (16) — 1,292 — 1,092 — 2,384 40 179 218 60 104 164 2 5 — — (14) — (7) 120 37 157 — — — — — — — — — — — — — — 19 19 1 — — — — — 1 — 20 20 44 209 253 40 198 238 10 30 41 — — — — (6) — (6) 9 26 35 293 259 552 (11) — — 33 (24) — (1) 293 257 550 303 289 593 302 283 585 237 40 277 40 — — — (60) (45) (65) 168 43 212 — 1,126 — 482 — 1,608 35 2,910 5 2,044 39 4,954 — — — — — — — 104 — 1 11 (125) — (9) 2 — — — (7) — (5) 140 254 1 46 (420) (74) (52) — 1,074 — 525 — 1,599 30 2,828 4 2,074 34 4,902 8 3,293 — 2,465 8 5,758 7 — — — (2) — 5 146 — 7 277 (346) (6) 78 13 3,248 — 2,588 13 5,836 — — — — — — — — — — — — — — 3,655 — 2,846 — 6,502 — — — — — — — 145 5 7 310 (386) (6) 75 — 3,675 — 2,902 — 6,576 245 3,293 1,126 482 285 5,758 1,608 40 2,465 35 6,565 5 4,890 39 11,456 181 3,248 1,074 525 224 5,836 1,599 43 2,588 30 6,502 4 4,976 34 11,478 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 231 249 480 60 1,228 104 1,048 164 2,276 At 31 December Developed Undeveloped 214 205 420 120 1,292 37 1,092 157 2,384 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Includes 456 million barrels associated with Assets Held for Sale in the USA. e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. f Also includes 11 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. h Includes 357 million barrels in respect of the non-controlling interest in Rosneft, including 26 mmboe held through bp’s interests in Russia other than Rosneft. i Total proved liquid reserves held as part of our equity interest in Rosneft is 5,745 million barrels, comprising 35 million barrels in Venezuela, less than 1 million barrels in Iraq, Canada, Egypt and Vietnam and 5,709 million barrels in Russia. bp Annual Report and Form 20-F 2020 245 Movements in estimated net proved reserves – continued Natural gasa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiond Sales of reserves-in-place At 31 Decembere Developed Undeveloped Equity-accounted entities (bp share)f At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiond Sales of reserves-in-place At 31 Decemberg h Developed Undeveloped Europe North America South America Africa Asia Australasia Total UK Rest of Europe USc Rest of North America Russia Rest of Asia billion cubic feet 2019 439 343 782 (34) 9 — — (57) — (82) 493 207 700 — — — — — — — — — — — — — — 6,270 — 5,056 — 11,326 — 2,168 1,313 — 3,073 1,067 — 5,241 2,380 — 3,599 — 3,218 — 6,817 2,630 16,420 1,179 13,936 3,809 30,355 — — — — — — — (1,877) 307 — 11 (923) (386) (2,869) 1 — — — (1) — — (263) — — 178 (729) — (814) (4) — — — (450) (21) (475) — — — — — — — 285 — 50 299 (383) — 251 (129) — — — (291) — (420) (2,022) 315 50 488 (2,834) (406) (4,410) — 6,330 — 2,127 — 8,458 — 2,192 1,163 — 2,235 742 — 4,427 1,905 — 3,667 — 3,401 — 7,068 2,256 16,101 1,132 9,844 3,389 25,946 107 55 161 9 15 — — (22) — 2 108 56 164 — — — — — — — — — — — — — — 1,207 4 446 4 1,653 391 7,798 143 8,719 534 16,517 3 — — — — — 3 (120) — — 180 (135) — (75) 38 — — — (65) — (27) 789 — — 534 (448) — 874 — 1,130 447 6 6 1,577 507 9,324 — 8,067 507 17,391 12 4 15 — — — — (5) — (5) 10 — 10 — 9,515 — 9,369 — 18,884 — — — — — — — 718 15 — 714 (676) — 772 — 11,079 — 8,576 — 19,656 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 439 343 782 107 6,270 55 5,056 161 11,326 — 3,375 1,704 7,798 3,610 4 3,519 1,210 8,719 3,221 4 6,894 2,914 16,517 6,832 2,630 25,934 1,179 23,305 3,809 49,239 At 31 December Developed Undeveloped 493 207 700 108 6,330 56 2,127 164 8,458 — 3,323 1,670 9,324 3,677 742 8,067 3,401 6 2,682 6 6,004 2,412 17,391 7,078 2,256 27,181 1,132 18,421 3,389 45,601 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes 3,054 billion cubic feet of natural gas associated with Assets Held for Sale in the USA. d Includes 188 billion cubic feet of natural gas consumed in operations, 146 billion cubic feet in subsidiaries, 42 billion cubic feet in equity-accounted entities. e Includes 1,330 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. g Includes 1,433 billion cubic feet of natural gas in respect of the 9.72% non-controlling interest in Rosneft including 569 billion cubic feet held through bp’s interests in Russia other than Rosneft. h Total proved gas reserves held as part of our equity interest in Rosneft is 14,705 billion cubic feet, comprising 28 billion cubic feet in Venezuela, 10 billion cubic feet in Vietnam, 171 billion cubic feet in Egypt and 14,495 billion cubic feet in Russia. 246 bp Annual Report and Form 20-F 2020 Movements in estimated net proved reserves – continued Total hydrocarbonsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionf g Sales of reserves-in-place At 31 Decemberh Developed Undeveloped Equity-accounted entities (bp share)i At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionf Sales of reserves-in-place At 31 Decemberj k Developed Undeveloped Financial statements million barrels of oil equivalentc 2019 Europe North America South America Africa Asia Australasia Total UK Rest of Europe USd e Rest of North America Russia Rest of Asia 307 308 615 (29) 3 — — (48) — (74) 300 241 540 — — — — — — — — — — — — — — 2,309 — 1,919 — 4,228 43 190 234 — — — — — — — (297) 305 — 36 (335) (95) (386) (8) 1 — — (9) — (16) — 2,384 — 1,459 — 3,842 40 179 218 384 560 944 (45) — — 31 (131) — (146) 387 411 798 464 224 687 39 — — — (137) (49) (147) 369 171 540 — 1,746 — 1,037 — 2,783 488 5,741 208 4,447 696 10,188 — — — — — — — 153 — 10 63 (191) — 35 (21) — — — (57) — (78) (208) 309 10 130 (908) (144) (813) — 1,707 — 1,111 — 2,818 419 5,604 199 3,771 618 9,375 79 113 192 4 7 — — (17) — (6) 139 47 186 — — — — — — — — — — — — — — 20 20 1 — — — — — 1 — 21 21 501 336 837 76 4,638 25 3,968 101 8,605 (31) — — 64 (47) — (14) 13 — — — (13) — — 282 — 7 369 (424) (6) 229 488 334 822 100 4,856 — 3,978 100 8,834 2 1 3 — — — — (1) — (1) 2 — 2 — 5,296 — 4,462 — 9,757 — — — — — — — 269 7 7 434 (503) (6) 208 — 5,585 — 4,381 — 9,965 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 307 308 615 79 2,309 113 1,919 192 4,228 885 44 210 896 253 1,781 539 4,638 1,749 249 3,968 1,037 788 8,605 2,786 488 11,037 208 8,908 696 19,945 At 31 December Developed Undeveloped 300 241 540 139 2,384 47 1,459 186 3,842 40 875 746 199 239 1,621 469 4,856 1,708 171 3,978 1,112 640 8,834 2,820 419 11,189 199 8,152 618 19,341 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent. d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. e Includes 982 million barrels of oil equivalent associated with Assets Held for Sale in the USA. f Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. g Includes 32 million barrels of oil equivalent of natural gas consumed in operations, 25 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted entities. h Includes 240 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. i Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. j Includes 603 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 124 mmboe held through bp’s interests in Russia other than Rosneft. k Total proved reserves held as part of our equity interest in Rosneft is 8,281 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Iraq and Canada, 40 million barrels of oil equivalent in Venezuela, 2 million barrels of oil equivalent in Vietnam, 30 million barrels of oil equivalent in Egypt and 8,208 million barrels of oil equivalent in Russia. bp Annual Report and Form 20-F 2020 247 Movements in estimated net proved reserves – continued Crude oila b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberd e Developed Undeveloped Equity-accounted entities (bp share)f At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberg Developed Undeveloped Europe North America South America UK Rest of Europe USc Rest of North America Africa Asia Australasia Total Russia Rest of Asia million barrels 2018 245 164 409 22 — 93 15 (37) (37) 57 223 243 466 — — — — — — — — — — — — — 932 — — 492 — 1,423 54 195 248 — — — — — — — 116 51 412 17 (137) (118) 341 (6) — — — (9) — (15) 962 — — 802 — 1,764 43 190 234 56 89 145 11 13 — — (13) — 12 57 100 157 — — — — — — — — — — — — — — — — — — — 19 — — 19 — 19 19 54 195 249 43 209 253 10 6 16 1 — — — (3) — (2) 8 5 14 285 263 548 7 — — 21 (25) — 4 293 259 552 295 269 564 302 264 566 281 28 309 11 1 — 13 (75) — (50) 223 36 259 — 1,040 — 642 — 1,682 31 2,592 11 1,537 42 4,129 — — — — — — — 40 — — — (114) — (74) (2) — — — (6) — (8) 183 52 504 46 (381) (155) 249 — 1,126 — 482 — 1,608 30 2,615 5 1,763 34 4,378 1 3,124 — 2,251 1 5,374 — — — — — — (1) 150 — 89 326 (335) — 229 1 3,190 — 2,414 1 5,604 6 — 6 — — — — (6) — (6) — — — — 3,473 — 2,603 — 6,076 — — — — — — — 168 13 89 366 (379) — 257 — 3,541 — 2,792 — 6,333 282 3,124 1,047 642 310 5,374 1,688 28 2,251 31 6,064 11 4,140 42 10,205 224 3,190 1,126 482 260 5,604 1,608 36 2,414 30 6,156 5 4,555 34 10,711 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 245 164 409 56 89 932 492 145 1,423 At 31 December Developed Undeveloped 223 243 466 57 962 802 100 157 1,764 a Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Includes 4 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Includes 344 million barrels of crude oil in respect of the 6.28% non-controlling interest in Rosneft, including 24 mmbbl held through bp’s interests in Russia other than Rosneft. g Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,539 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 58 million barrels in Venezuela and 5,481 million barrels in Russia. 248 bp Annual Report and Form 20-F 2020                 Movements in estimated net proved reserves – continued Natural gas liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionc Sales of reserves-in-place At 31 Decemberd Developed Undeveloped Equity-accounted entities (bp share)e At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberf g Developed Undeveloped Financial statements million barrels 2018 Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Total Russia Rest of Asia 11 3 14 1 — — 3 (2) (3) — 8 6 14 — — — — — — — — — — — — — — — — — — — — — — — — — — 4 4 8 — — — — (1) — (1) 4 3 7 4 4 8 4 3 7 177 69 246 20 16 253 1 (25) — 265 266 246 511 — — — — — — — — — — — — — 177 69 246 266 246 511 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 2 28 30 — — — — (3) — (3) 2 25 27 — — — — — — — — — — — — — 2 28 30 2 25 27 21 — 21 (3) 2 — 3 (3) — (2) 14 4 18 10 — 10 (1) — — — (1) — (3) 7 — 7 31 — 31 22 4 26 — — — — — — — — — — — — — 82 49 131 25 — — — (2) — 23 103 51 154 82 49 131 103 51 154 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 5 1 6 — — — — (1) — (1) 5 — 5 — — — — — — — — — — — — — 5 1 6 5 — 5 216 102 318 17 18 253 7 (34) (3) 258 295 280 576 97 53 149 23 — — — (4) — 19 114 54 169 313 154 467 409 335 744 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 11 3 14 At 31 December Developed Undeveloped 8 6 14 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. d Includes 8 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Includes 12 million barrels of NGLs in respect of the 7.82% non-controlling interest in Rosneft. g Total proved NGL reserves held as part of our equity interest in Rosneft is 154 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 154 million barrels in Russia. bp Annual Report and Form 20-F 2020 249             Movements in estimated net proved reserves – continued Total liquidsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productiond Sales of reserves-in-place At 31 Decembere Developed Undeveloped Equity-accounted entities (bp share)f At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Production Sales of reserves-in-place At 31 Decemberg h Developed Undeveloped Europe North America South America Africa Asia Australasia Total UK Rest of Europe USc Rest of North America Russia Rest of Asia million barrels 2018 256 167 424 23 — 93 18 (39) (40) 56 231 249 480 — — — — — — — — — — — — — — 1,108 — 561 — 1,669 54 195 248 — — — — — — — 136 67 665 18 (162) (118) 606 (6) — — — (9) — (15) — 1,228 — 1,048 — 2,276 43 190 234 60 93 153 11 13 — — (13) — 11 60 104 164 — — — — — — — — — — — — — — — — — — — 19 — — 19 — 19 19 54 195 249 44 209 253 12 34 46 1 — — — (6) — (5) 10 30 41 285 263 548 7 — — 21 (25) — 4 293 259 552 297 297 594 303 289 593 301 28 329 8 3 — 16 (79) — (52) 237 40 277 — 1,040 — 642 — 1,682 36 2,808 12 1,639 48 4,447 — — — — — — — 40 — — — (114) — (74) (2) — — — (7) — (9) 200 70 758 52 (415) (158) 507 — 1,126 — 482 — 1,608 35 2,910 5 2,044 39 4,954 11 3,206 — 2,300 12 5,505 (2) — — — (2) — (3) 175 — 89 326 (337) — 253 8 3,293 — 2,465 8 5,758 6 — 6 — — — — (6) — (6) — — — — 3,569 — 2,656 — 6,225 — — — — — — — 191 13 89 366 (383) — 277 — 3,655 — 2,846 — 6,502 313 3,206 1,047 642 341 5,505 1,688 28 2,300 36 6,377 12 4,295 48 10,672 245 3,293 1,126 482 285 5,758 1,608 40 2,465 35 6,565 5 4,890 39 11,456 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 256 167 424 60 1,108 561 93 153 1,669 At 31 December Developed Undeveloped 231 249 480 60 1,228 104 1,048 164 2,276 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. e Also includes 12 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. g Includes 356 million barrels in respect of the non-controlling interest in Rosneft, including 24 mmboe held through bp’s interests in Russia other than Rosneft. h Total proved liquid reserves held as part of our equity interest in Rosneft is 5,693 million barrels, comprising less than 1 million barrels in Canada, 58 million barrels in Venezuela, less than 1 million barrels in Vietnam and 5,635 million barrels in Russia. 250 bp Annual Report and Form 20-F 2020       Movements in estimated net proved reserves – continued Natural gasa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionc Sales of reserves-in-place At 31 Decemberd Developed Undeveloped Equity-accounted entities (bp share)e At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productionc Sales of reserves-in-place At 31 Decemberf g Developed Undeveloped Financial statements billion cubic feet 2018 Europe UK Rest of Europe North America South America Rest of North America US Africa Asia Australasia Total Russia Rest of Asia 523 320 843 84 — 40 60 (66) (178) (61) 439 343 782 — — — — — — — — — — — — — — 5,238 — 3,086 — 8,323 (1) 2,862 1,159 — 3,330 1,510 (1) 6,193 2,670 — 2,755 — 4,245 — 7,000 2,730 15,266 1,505 13,997 4,235 29,263 — 10 — 1,315 — 2,655 11 — (751) — — (237) — 3,003 3 — — — (3) — 1 (195) — — 31 (788) — (951) (444) — — 578 (423) — (290) — — — — — — — 140 — — — (324) — (184) (123) (524) — 1,315 — 2,695 680 — (2,658) (303) (416) — (426) 1,092 — 6,270 — 5,056 — 11,326 — 2,168 1,313 — 3,073 1,067 — 5,241 2,380 — 3,599 — 3,218 — 6,817 2,630 16,420 1,179 13,936 3,809 30,355 112 69 180 2 — — — (22) — (19) 107 55 161 — — — — — — — — — — — — — — 1,274 — 450 — 1,724 476 6,077 146 7,173 622 13,250 — — — 4 — — 3 (50) 1 — 122 (145) — (71) 805 (39) — — — 2,413 512 — (464) (48) — — (87) 3,267 — 1,207 446 4 4 1,653 391 7,798 143 8,719 534 16,517 17 3 20 2 — — — (6) — (5) 12 4 15 — 7,955 — 7,841 — 15,796 719 — — 1 — 2,413 638 — (685) — — — — 3,087 — 9,515 — 9,369 — 18,884 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 523 320 843 112 5,238 69 3,086 180 8,323 — 4,136 1,635 6,077 2,771 — 3,781 1,656 7,173 4,249 — 7,917 3,291 13,250 7,020 2,730 23,221 1,505 21,838 4,235 45,060 At 31 December Developed Undeveloped 439 343 782 107 6,270 55 5,056 161 11,326 — 3,375 1,704 7,798 3,610 4 3,519 1,210 8,719 3,221 4 6,894 2,914 16,517 6,832 2,630 25,934 1,179 23,305 3,809 49,239 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes 181 billion cubic feet of natural gas consumed in operations, 139 billion cubic feet in subsidiaries, 42 billion cubic feet in equity-accounted entities. d Includes 1,573 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. f Includes 1,211 billion cubic feet of natural gas in respect of the 8.60% non-controlling interest in Rosneft including 480 billion cubic feet held through bp’s interests in Russia other than Rosneft. g Total proved gas reserves held as part of our equity interest in Rosneft is 14,325 billion cubic feet, comprising 0 billion cubic feet in Canada, 26 billion cubic feet in Venezuela, 15 billion cubic feet in Vietnam, 200 billion cubic feet in Egypt and 14,084 billion cubic feet in Russia. bp Annual Report and Form 20-F 2020 251     Movements in estimated net proved reserves – continued Total hydrocarbonsa b Subsidiaries At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione f Sales of reserves-in-place At 31 Decemberg Developed Undeveloped Equity-accounted entities (bp share)h At 1 January Developed Undeveloped Changes attributable to Revisions of previous estimates Improved recovery Purchases of reserves-in-place Discoveries and extensions Productione Sales of reserves-in-place At 31 Decemberi j Developed Undeveloped Europe North America South America Africa Asia Australasia Total UK Rest of Europe USd Rest of North America Russia Rest of Asia million barrels of oil equivalentc 2018 347 222 569 38 — 100 29 (50) (70) 46 307 308 615 — — — — — — — — — — — — — — 2,011 — 1,093 — 3,104 505 54 195 608 248 1,114 138 — — 294 — 1,123 — 20 (292) — — (159) — 1,124 (5) — — — (9) — (15) — 2,309 — 1,919 — 4,228 43 190 234 (33) — — 5 (142) — (169) 384 560 944 501 288 790 (69) 3 — 116 (152) — (102) 464 224 687 — 1,515 — 1,374 — 2,889 507 5,440 272 4,052 779 9,492 — — — — — — — 64 — — — (170) — (106) 110 (23) — 297 — 1,222 — 169 (874) (59) (229) — 696 (82) — 1,746 — 1,037 — 2,783 488 5,741 208 4,447 696 10,188 80 105 184 11 13 — — (17) — 8 79 113 192 — — — — — — — — — — — — — — — — — — — 20 — — 19 — 20 20 505 341 846 93 4,254 25 3,536 119 7,790 (1) — — 42 (50) — (9) (8) — — — (10) — (18) 313 — 505 414 (417) — 816 501 336 837 76 4,638 25 3,968 101 8,605 9 1 10 — — — — (7) — (7) 2 1 3 — 4,941 — 4,008 — 8,949 — — — — — — — 315 14 505 476 (501) — 809 — 5,296 — 4,462 — 9,757 Total subsidiaries and equity-accounted entities (bp share) At 1 January Developed Undeveloped 347 222 569 80 2,011 105 1,093 184 3,104 54 1,010 195 949 249 1,959 595 4,254 1,524 314 3,536 1,374 908 7,790 2,899 507 10,381 272 8,060 779 18,441 At 31 December Developed Undeveloped 307 308 615 79 2,309 113 1,919 192 4,228 44 885 896 210 253 1,781 539 4,638 1,749 249 3,968 1,037 788 8,605 2,786 488 11,037 208 8,908 696 19,945 a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent. d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities. f Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 24 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted entities. g Includes 283 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. h Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. i Includes 565 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 107 mmboe held through bp’s interests in Russia other than Rosneft. j Total proved reserves held as part of our equity interest in Rosneft is 8,163 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 62 million barrels of oil equivalent in Venezuela, 3 million barrels of oil equivalent in Vietnam, 35 million barrels of oil equivalent in Egypt and 8,063 million barrels of oil equivalent in Russia. 252 bp Annual Report and Form 20-F 2020 Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves The following tables set out the standardized measure of discounted future net cash flows, and changes therein, relating to crude oil and natural gas production from the group’s estimated proved reserves. This information is prepared in compliance with FASB Oil and Gas Disclosures requirements. Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of future production, the estimation of crude oil and natural gas reserves and the application of average crude oil and natural gas prices and exchange rates from the previous 12 months. Furthermore, both proved reserves estimates and production forecasts are subject to revision as further technical information becomes available and economic conditions change. bp cautions against relying on the information presented because of the highly arbitrary nature of the assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial statements. Financial statements Europe North America South America Africa Asia Australasia UK Rest of Europe Rest of North America US Russia Rest of Asia $ million 2020 Total 13,900 10,000 800 1,200 1,900 500 — 64,400 4,100 6,700 12,600 — 28,200 3,400 3,600 4,200 — 12,700 1,200 1,700 1,100 500 1,800 — — 1,100 900 5,500 (500) — 22,400 200 1,100 (200) 9,200 — — 93,500 15,900 211,100 5,400 100,100 — 45,300 1,900 32,700 — 13,300 2,600 33,300 — 26,100 6,000 45,000 — 8,800 2,500 15,300 — 2,000 1,400 — 13,200 (300) 700 4,400 — 6,800 3,500 29,700 — 6,300 — 3,100 — 500 — 2,200 500 — 100 — — — — — — — — 25,100 — 13,000 — 3,300 — 1,700 — 7,100 — 4,400 — 214,800 — 145,700 — 20,800 — 8,000 — 40,300 — 23,500 — — — — — — — 246,200 — 161,800 — 24,600 — 11,900 — 47,900 — 28,000 — 400 — — 2,700 — 16,800 — — 19,900 At 31 December Subsidiaries Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd Standardized measure of discounted future net cash flowse f Equity-accounted entities (bp share)g Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd Standardized measure of discounted future net cash flowsh i Total subsidiaries and equity-accounted entities Standardized measure of discounted future net cash flowsj 1,400 400 13,200 (300) 3,400 4,400 16,800 6,800 3,500 49,600 The following are the principal sources of change in the standardized measure of discounted future net cash flows: $ million Subsidiaries Equity-accounted entities (bp share) Total subsidiaries and equity-accounted entities (27,200) 12,800 2,500 (70,800) 7,300 27,500 (2,600) (6,200) 9,700 (47,000) Sales and transfers of oil and gas produced, net of production costs Development costs for the current year as estimated in previous year Extensions, discoveries and improved recovery, less related costs Net changes in prices and production cost Revisions of previous reserves estimates Net change in taxation Future development costs Net change in purchase and sales of reserves-in-place Addition of 10% annual discount Total change in the standardized measure during the yeark a The marker prices used were Brent $41.31/bbl, Henry Hub $1.94/mmBtu. b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future (6,000) 4,100 1,400 (19,200) 400 4,600 (2,700) — 3,400 (14,000) (21,200) 8,700 1,100 (51,600) 6,900 22,900 100 (6,200) 6,300 (33,000) decommissioning costs are included. c Taxation is computed with reference to appropriate year-end statutory corporate income tax rates. d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. e In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and vice versa. This can result in the standardized measure of discounted future net cash flows being negative. f Non-controlling interests in BP Trinidad and Tobago LLC amounted to $200 million. g The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. h Non-controlling interests in Rosneft amounted to $1,600 million in Russia. i No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs. j Includes future net cash flows for assets held for sale at 31 December 2020. k Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes to US dollars are included within ‘Net changes in prices and production cost’. bp Annual Report and Form 20-F 2020 253 Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves – continued  Europe North America South America UK Rest of Europe Rest of North America US Africa Asia Australasia $ million 2019 Total Russia Rest of Asia 28,600 13,700 1,700 5,200 8,000 2,700 — 135,900 7,400 11,500 21,200 — 59,200 3,400 5,700 6,700 — 16,400 1,200 2,000 1,300 — 8,700 200 1,300 3,300 — 51,600 2,600 2,500 9,900 600 2,300 — 23,100 1,400 — 135,800 24,000 364,400 6,100 148,000 — 53,200 2,700 42,000 — 16,700 5,300 70,000 — 46,000 9,900 104,400 — 19,900 4,400 41,700 — 7,200 5,300 — 28,500 1,200 1,900 7,600 — 12,700 5,500 62,700 — 10,300 — 3,500 700 — — 4,700 — 1,400 400 — — — — — — — — 36,800 — 14,900 — 3,900 — 4,100 — 13,900 — 8,200 — 322,000 — 222,600 — 21,800 — 13,300 — 64,300 — 37,100 — — — — — — — 369,100 — 241,000 — 26,400 — 22,100 — 79,600 — 45,700 — 1,000 — — 5,700 — 27,200 — — 33,900 At 31 December Subsidiaries Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd Standardized measure of discounted future net cash flowse f Equity-accounted entities (bp share)g Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd Standardized measure of discounted future net cash flowsh i Total subsidiaries and equity-accounted entities Standardized measure of discounted future net cash flowsj 5,300 1,000 28,500 1,200 7,600 7,600 27,200 12,700 5,500 96,600 The following are the principal sources of change in the standardized measure of discounted future net cash flows: $ million Total subsidiaries and equity-accounted entities (35,800) 13,300 6,400 (36,300) 1,400 19,000 (5,800) (1,400) 12,400 (26,800) Subsidiaries Equity-accounted entities (bp share) Sales and transfers of oil and gas produced, net of production costs Development costs for the current year as estimated in previous year Extensions, discoveries and improved recovery, less related costs Net changes in prices and production cost Revisions of previous reserves estimates Net change in taxation Future development costs Net change in purchase and sales of reserves-in-place Addition of 10% annual discount Total change in the standardized measure during the yeark a The marker prices used were Brent $62.74/bbl, Henry Hub $2.58/mmBtu. b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future (27,400) 9,200 3,800 (28,100) 300 16,600 (1,500) (1,400) 8,300 (20,200) (8,400) 4,100 2,600 (8,200) 1,100 2,400 (4,300) — 4,100 (6,600) decommissioning costs are included. c Taxation is computed with reference to appropriate year-end statutory corporate income tax rates. d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. e In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and vice versa. This can result in the standardized measure of discounted future net cash flows being negative. f Non-controlling interests in BP Trinidad and Tobago LLC amounted to $600 million. g The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. h Non-controlling interests in Rosneft amounted to $2,100 million in Russia. i No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs. i Includes future net cash flows for assets held for sale at 31 December 2019. k Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes to US dollars are included within ‘Net changes in prices and production cost’. 254 bp Annual Report and Form 20-F 2020 Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves – continued Financial statements Europe North America South America UK Rest of Europe Rest of North America US Africa Asia  Australasia $ million 2018 Total Russia Rest of Asia At 31 December Subsidiaries Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd Standardized measure of discounted future net cash flowse f Equity-accounted entities (bp share)g Future cash inflowsa Future production costb Future development costb Future taxationc Future net cash flows 10% annual discountd Standardized measure of discounted future net cash flowsh i 39,700 15,000 2,100 8,900 13,700 5,000 — 160,000 4,100 17,500 30,400 — 57,600 3,400 7,200 8,500 — 17,800 1,100 2,800 2,600 — 16,600 — 3,200 5,300 (400) 4,300 14,000 — 68,000 700 3,300 (200) — 29,900 — 147,500 30,000 429,200 7,600 155,100 — 55,800 2,500 45,300 — 16,400 — 51,100 6,900 92,000 — 24,200 13,000 136,800 5,800 53,900 — 9,400 8,700 — 38,100 (200) 3,600 10,700 — 14,800 7,200 82,900 — 12,800 — 4,200 800 — — 5,900 — 1,900 600 — — — — — — — — 38,500 — 16,100 — 3,600 — 4,400 — 14,400 — 8,500 — 356,800 — 238,400 — 19,300 — 17,700 — 81,400 — 48,100 — — — — — — — 408,100 — 258,700 — 23,700 — 28,000 — 97,700 — 57,200 — 1,300 — — 5,900 — 33,300 — — 40,500 Total subsidiaries and equity-accounted entities Standardized measure of discounted future net cash flows 8,700 1,300 38,100 (200) 9,500 10,700 33,300 14,800 7,200 123,400 The following are the principal sources of change in the standardized measure of discounted future net cash flows: $ million Total subsidiaries and equity-accounted entities (26,800) 12,800 9,100 54,100 (100) (21,600) (2,500) 8,000 8,300 41,300 Subsidiaries Equity-accounted entities (bp share) Sales and transfers of oil and gas produced, net of production costs Development costs for the current year as estimated in previous year Extensions, discoveries and improved recovery, less related costs Net changes in prices and production cost Revisions of previous reserves estimates Net change in taxation Future development costs Net change in purchase and sales of reserves-in-place Addition of 10% annual discount Total change in the standardized measure during the yearj a The marker prices used were Brent $71.43/bbl, Henry Hub $3.10/mmBtu. b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included. 2018 comparative for Russia equity-accounted entity future production cost has been restated from $232,100 million to maintain consistency with 2019 presentation. (18,800) 8,500 5,800 41,000 (2,100) (17,000) 1,000 7,600 5,200 (8,000) 4,300 3,300 13,100 2,000 (4,600) (3,500) 400 3,100 10,100 31,200 c Taxation is computed with reference to appropriate year-end statutory corporate income tax rates. 2018 comparative for Russia equity-accounted entity future taxation has been restated from $24,000 million to maintain consistency with 2019 presentation. d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. e In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and vice versa. This can result in the standardized measure of discounted future net cash flows being negative. f Non-controlling interests in BP Trinidad and Tobago LLC amounted to $1,100 million. g The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. h Non-controlling interests in Rosneft amounted to $2,500 million in Russia. i No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs. j Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes to US dollars are included within ‘Net changes in prices and production cost’. bp Annual Report and Form 20-F 2020 255 Operational and statistical information The following tables present operational and statistical information related to production, drilling, productive wells and acreage. Figures include amounts attributable to assets held for sale. Crude oil and natural gas production The following table shows crude oil, natural gas liquids and natural gas production for the years ended 31 December 2020, 2019 and 2018. Production for the yeara b Subsidiariesd Crude oile 2020 2019 2018 Natural gas liquids 2020 2019 2018 Natural gasf 2020 2019 2018 Equity-accounted entities (bp share) Crude oile 2020 2019 2018 Natural gas liquids Europe UK Rest of Europe North America Rest of North America US South America Africa Asia Australasia Total Russiac Rest of Asia 96 100 101 5 3 5 221 129 152 — — — — — — — — — — — — 50 35 34 345 400 385 79 81 60 22 24 24 — — — 7 7 7 7 9 9 123 156 204 8 8 11 1,561 2,358 1,900 2 2 7 1,695 1,977 2,136 923 1,138 1,061 — — — — — — — — — — — — — — — 54 56 55 1 1 1 903 955 933 thousand barrels per day 983 1,046 1,051 15 17 17 thousand barrels per day 101 104 88 2 2 2 375 343 313 — — — million cubic feet per day 6,163 7,366 6,900 795 786 819 966 976 826 thousand barrels per day 1,009 1,047 1,040 — — — — — 16 — — — 2020 2019 2018 Natural gasf 2020 2019 2018 a Production excludes royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and million cubic feet per day 1,765 1,736 1,760 1,327 1,279 1,286 286 314 335 92 87 80 61 56 59 — — — — — — — — — — — — — — — — — — 1 1 — — — — — — — 7 8 6 3 3 4 3 2 2 thousand barrels per day 14 14 12 — — — sales arrangements independently. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Amounts reported for Russia include bp’s share of Rosneft worldwide activities, including insignificant amounts outside Russia. d All of the oil and liquid production from Canada is bitumen. e Crude oil includes condensate. f Natural gas production excludes gas consumed in operations. 256 bp Annual Report and Form 20-F 2020 Operational and statistical information – continued Productive oil and gas wells and acreage The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil and natural gas acreage in which the group and its equity-accounted entities had interests as at 31 December 2020. A ‘gross’ well or acre is one in which a whole or fractional working interest is owned, while the number of ‘net’ wells or acres is the sum of the whole or fractional working interests in gross wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is the acreage within the boundary of a field, on which development wells have been drilled, which could produce the reserves; while undeveloped acres are those on which wells have not been drilled or completed to a point that would permit the production of commercial quantities, whether or not such acres contain proved reserves. Financial statements Europe UK Rest of Europe North America Rest of North America US South America Africa Asia Australasia Totalb Russiaa Rest of Asia Number of productive wells at 31 December 2020 Oil wellsc Gas wellsd – gross – net – gross – net 125 73 39 8 90 27 2 1 1,326 741 6,405 3,898 175 47 238 118 5,551 2,557 1,118 403 291 68,286 62 13,594 455 93 241 102 Oil and natural gas acreage at 31 December 2020 86 Developed 50 1,892 1,010 – gross – net – gross – net Undevelopede 64 19 140 42 144 63 8,210 1,364 3,645 2,200 1,459 365 4,590 14,948 23,683 34,246 442,967 8,358 19,817 85,477 3,518 850 303 7,887 2,020 475 138 70 1,281 285 9,662 2,520 12 77,876 2 17,578 8,714 4,709 78 16 thousands of acres 181 15,824 4,788 7,571 539,699 3,299 131,928 44 a Based on information received from Rosneft as at 31 December 2020. b Because of rounding, some totals may not exactly agree with the sum of their component parts. c Includes approximately 6,978 gross (1,343 net) multiple completion wells (more than one formation producing into the same well bore). d Includes approximately 430 gross (203 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well. e Undeveloped acreage includes leases and concessions. Net oil and gas wells completed or abandoned The following table shows the number of net productive and dry exploratory and development oil and natural gas wells completed or abandoned in the years indicated by the group and its equity-accounted entities. Productive wells include wells in which hydrocarbons were encountered and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be incapable of producing hydrocarbons in sufficient quantities to justify completion. 2020 Exploratory Productive Dry Development Productive Dry 2019 Exploratory Productive Dry Development Productive Dry 2018 Exploratory Productive Dry Development Productive Dry Europe North America South America UK Rest of Europe Rest of North America US Africa Asia Australasia Totala Russia Rest of Asia — — 5.3 — — 1.0 1.7 — 0.3 — 1.4 — — — 1.1 1.8 3.1 — 114.6 3.0 0.8 — 0.4 — — — 0.6 — 14.3 — 0.4 0.2 — — 17.2 2.0 61.7 1.0 4.4 — 199.1 — 40.3 0.6 2.0 — 430.9 4.6 0.2 0.3 0.8 1.6 0.8 0.5 3.5 1.1 2.3 0.3 11.6 0.5 5.2 0.4 — 0.2 24.4 5.9 2.4 0.3 193.0 10.0 0.2 — 110.7 0.6 6.0 — 230.8 — 49.6 1.0 0.4 — 594.8 11.9 — — 1.7 — — 0.5 2.0 2.0 — 2.4 15.0 — 5.0 — — — 24.0 4.9 0.6 — 142.7 6.8 5.0 — 103.9 3.6 14.4 — 137.3 — 53.5 2.6 1.3 — 460.1 13.0 a Because of rounding, some totals may not exactly agree with the sum of their component parts. bp Annual Report and Form 20-F 2020 257 Operational and statistical information – continued Drilling and production activities in progress The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the group and its equity-accounted entities as of 31 December 2020. Suspended development wells and long-term suspended exploratory wells are also included in the table. At 31 December 2020 Exploratory Gross Net Development Gross Net Europe UK Rest of Europe North America Rest of North America US South America Africa Asia Australasia Totala Russia Rest of Asia — — 2.0 0.7 — — 5.0 3.1 0.7 0.2 166.0 104.8 1.0 0.4 6.0 3.0 2.0 0.1 7.0 3.2 — — 4.0 0.8 1.0 0.4 20.0 8.0 13.0 4.7 19.0 4.8 — — 198.0 25.0 2.0 0.8 406.7 144.0 a Because of rounding, some totals may not exactly agree with the sum of their component parts. 258 bp Annual Report and Form 20-F 2020 Parent company financial statements of BP p.l.c. Company balance sheet At 31 December Non-current assets Investments Receivables Defined benefit pension plan surpluses Current assets Receivables Cash and cash equivalents Total assets Current liabilities Payables Non-current liabilities Payables Deferred tax liabilities Defined benefit pension plan deficits Total liabilities Net assets Capital and reservesa Profit and loss account Brought forward Profit (loss) for the year Other movements Called-up share capital Share premium account Other capital and reserves Financial statements Note 2020 2 3 4 3 160,544 3,174 7,567 171,285 291 1 292 171,577 $ million 2019 166,256 2,771 6,588 175,615 135 — 135 175,750 5 28,011 18,007 5 6 4 28,084 2,631 236 30,951 58,962 112,615 31,927 2,293 202 34,422 52,429 123,321 92,071 (4,831) (7,519) 79,721 5,383 12,584 14,927 112,615 96,430 4,470 (8,829) 92,071 5,404 12,417 13,429 123,321 7 a See Statement of changes in equity on page 260 for further information. The financial statements on pages 259-300 were approved and signed by the chief executive officer on 22 March 2021 having been duly authorized to do so by the board of directors: Bernard Looney Chief executive officer The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 259           Company statement of changes in equitya At 1 January 2020 Profit (loss) for the year Other comprehensive income Total comprehensive income Dividends Repurchases of ordinary share capital Share-based payments, net of tax At 31 December 2020 At 1 January 2019 Profit (loss) for the year Other comprehensive income Total comprehensive income Dividends Repurchases of ordinary share capital Share-based payments, net of tax At 31 December 2019 a See Note 8 for further information. Share capital 5,404 — — — — (30) 9 5,383 5,402 — — — 52 (59) 9 5,404 Share premium account 12,417 — — — — — 167 12,584 Capital redemption reserve 1,498 — — — — 30 — 1,528 12,305 — — — (52) — 164 12,417 1,439 — — — — 59 — 1,498 Merger reserve 26,509 — — — — — — 26,509 26,509 — — — — — — 26,509 Treasury shares (14,412) — — — — — 1,188 (13,224) (15,767) — — — — — 1,355 (14,412) $ million Profit and loss account Total equity 92,071 123,321 (4,831) (4,831) 528 248 (4,303) (4,583) (6,367) (6,367) (776) (776) 740 (624) 79,721 112,615 96,430 125,952 4,470 601 5,071 (6,929) (1,511) 738 92,071 123,321 4,470 401 4,871 (6,929) (1,511) (790) Foreign currency translation reserve (166) — 280 280 — — — 114 (366) — 200 200 — — — (166) The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 260 bp Annual Report and Form 20-F 2020   Financial statements Notes on financial statements 1. Significant accounting policies, judgements, estimates and assumptions Authorization of financial statements and statement of compliance with Financial Reporting Standard 101 ‘Reduced Disclosure Framework’ (FRS 101) The financial statements of BP p.l.c. for the year ended 31 December 2020 were approved and signed by the chief executive officer on 22 March 2021 having been duly authorized to do so by the board of directors. The company meets the definition of a qualifying entity under Financial Reporting Standard 100 ‘Application of Financial Reporting Requirements’ (FRS 100) issued by the Financial Reporting Council. Accordingly, these financial statements have been prepared in accordance with FRS 101 and in accordance with the provisions of the UK Companies Act 2006. Basis of preparation The financial statements have been prepared on a going concern basis and in accordance with the Companies Act 2006 and applicable UK accounting standards. The financial statements have been prepared under the historical cost convention. Historical cost is generally based on the fair value of the consideration given in exchange for the assets. As permitted by FRS 101, the company has taken advantage of the disclosure exemptions available in relation to: (a) the requirements of IFRS 7 ‘Financial Instruments: Disclosures’; (b) (c) the requirements of paragraphs 10(d), 10(f), 16, 38A, 38B, 38C, 38D, 40A, 40B, 40C, 40D, 111 and 134 to 136 of IAS 1 ‘Presentation of Financial Statements’; the requirements in paragraph 38 of IAS 1 'Presentation of Financial Statements' to present comparative information in respect of paragraph 79(a)(iv) of IAS 1. (d) the requirements of IAS 7 ‘Statement of Cash Flows’; (e) the requirements of paragraphs 30 and 31 of IAS 8 ‘Accounting Policies, Changes in Accounting Estimates and Errors’ in relation to standards not yet effective; (f) the requirements of paragraphs 17 and 18A of IAS 24 ‘Related Party Disclosures’; (g) the requirements of IAS 24 ‘Related Party Disclosures’ to disclose related party transactions entered into between two or more members of a group, provided that any subsidiary which is a party to the transaction is wholly owned by such a member; (h) the requirements of paragraphs 130(f)(ii), 130(f)(iii), 134(d) to 134(f) and 135(c)-135(e) of IAS 36, Impairment of Assets; and (i) the requirement of the second sentence of paragraph 110 and paragraphs 113(a), 114,115, 118, 119(a) to (c), 120 to 127 and 129 of IFRS 15 'Revenue from Contracts with Customers'. Where required, equivalent disclosures are given in the consolidated financial statements of BP p.l.c. As permitted by Section 408 of the Companies Act 2006, the income statement of the company is not presented as part of these financial statements. The financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where otherwise indicated. Comparative employee cost information in note 13 has been restated due the correction of an accounting error. There is no impact on the company balance sheet or the statement of changes in equity as a result of this error. Significant accounting policies: use of judgements, estimates and assumptions Inherent in the application of many of the accounting policies used in preparing the financial statements is the need for management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and assumptions used. The accounting judgements and estimates that have a significant impact on the results of the company are set out in boxed text below, and should be read in conjunction with the information provided in the Notes to the financial statements. The areas requiring the most significant judgement and estimation in the preparation of the financial statements are the recoverability of investment carrying values and pensions. Judgements and estimates, not all of which are significant, made in assessing the impact of the COVID-19 pandemic, and climate change and the transition to a lower carbon economy on the financial statements are also set out in boxed text below. Where an estimate has a significant risk of resulting in a material adjustment to the carrying amounts of assets and liabilities within the next financial year this is specifically noted within the boxed text. Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy Climate change and the transition to a lower carbon economy were considered in preparing the financial statements. These may have significant impacts on the currently reported amounts of the company’s assets and liabilities discussed below. Impairment of investments The energy transition is likely to impact the future prices of commodities such as oil and natural gas which in turn may affect the recoverable amount of property, plant and equipment, and goodwill in the oil and gas industry. Management’s best estimate oil and natural gas price assumptions for value-in-use impairment testing were revised downwards during 2020 and the period covered extended to 2050. The revised assumptions sit within the range of external forecasts considered by management and are broadly in line with a range of transition paths consistent with the goals of the Paris climate change agreement. Impairments were recognized during 2020 on certain investments where the subsidiary company holds Upstream oil and gas properties, as a result of the lower price assumptions. See note 2 for further information. The energy transition may also affect the future development or viability of exploration prospects. The lower price assumptions and work to develop bp’s new strategy resulted in a review of the recoverability of exploration and intangible assets during 2020. Certain intangible assets were subsequently written-off, which has resulted in the company recognizing impairments against investments in subsidiary companies holding these assets. The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 261 1. Significant accounting policies, judgements, estimates and assumptions – continued Judgements and estimates made in assessing the impact of the COVID-19 pandemic and the economic environment In preparing the financial statements, the following areas involving judgement and estimates were identified as most relevant with regards to the impact of the COVID-19 pandemic and current economic environment. Going concern Liquidity and financing is managed within bp under pooled group-wide arrangements which include the company. As part of assuring the going concern basis of preparation for the company, the ability and intent of the bp group to support the company has been taken into consideration. The most recent bp group financial statements (see pages 129 to 230) continue to be prepared on a going concern basis. Forecast liquidity has been assessed at a group level under a number of scenarios and a reverse stress test performed to support the group’s going concern assertion. In addition, group management of bp have confirmed that the existing intra-group funding and liquidity arrangements as currently constituted are expected to continue for the foreseeable future, being no less than twelve months from the approval of these financial statements. No material uncertainties over going concern or significant judgements or estimates in the assessment were identified. Accordingly, the company will be able to draw on support from the bp group for the foreseeable future and these financial statements have therefore been prepared on the going concern basis. Pensions The volatility in the financial markets during 2020 impacted the assumptions used for determining the fair value of plan assets and the present value of defined benefit obligations in the company’s defined benefit pension plans. See significant estimate: pensions and Note 4 for further information. Investments Investments in subsidiaries are recorded at cost. The company assesses investments for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If any such indication of impairment exists, the company makes an estimate of its recoverable amount. Where the carrying amount of an investment exceeds its recoverable amount, the investment is considered impaired and is written down to its recoverable amount. Where these circumstances have reversed, the impairment previously made is reversed to the extent of the original cost of the investment. Significant judgements and estimates: recoverability of asset carrying values Determination as to whether, and by how much, an asset, CGU, or investment holding company chain (defined as each direct subsidiary and its own investments), is impaired involves management estimates on highly uncertain matters such as the effects of inflation and deflation on operating expenses, discount rates, capital expenditure, production profiles, reserves and resources, and future commodity prices, including the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas and refined products. Alternative groupings of assets or CGUs may result in a different outcome from impairment testing. The recoverable amount of an asset is the higher of its value in use and its fair value less costs of disposal. Fair value less costs of disposal may be determined based on expected sales proceeds or similar recent market transaction data. Details of impairment charges recognized in the profit and loss account and the carrying amounts of investments are shown in Note 2. The estimates for assumptions made in impairment tests in 2020 relating to discount rates and oil and gas properties are discussed below. Changes in the economic environment or other facts and circumstances may necessitate revisions to these assumptions and could result in a material change to the carrying values of the group's assets within the next financial year. Discount rates For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. Value-in-use calculations are typically discounted using a pre-tax discount rate based upon the cost of funding the group derived from an established model, adjusted to a pre-tax basis and incorporating a market participant capital structure and country risk premiums. Fair value less costs of disposal discounted cash flow calculations use the post-tax discount rate. The discount rates applied in impairment tests are reassessed each year and in 2020, the pre-tax discount rate typically ranged from 7% to 15% (2019 7% to 13%) depending on the risk premium and applicable tax rate in the geographic location of the CGU. Oil and natural gas properties For Upstream oil and natural gas properties in subsidiaries, expected future cash flows are estimated using management’s best estimate of future oil and natural gas prices, and production and reserves volumes. The estimated future level of production in all impairment tests is based on assumptions about future commodity prices, production and development costs, field decline rates, current fiscal regimes and other factors. A change in the discount rate, reserves, resources or the oil and gas price assumptions in the next financial year may result in a recoverable amount of one or more of these assets above or below the current carrying amount and therefore there is a risk of impairment reversals or charges in that period. Management consider that reasonably possible changes in the discount rate or forecast revenue, arising from a change in oil and natural gas prices and/or production could result in a material change in their carrying amounts within the next financial year. Oil and natural gas prices The price assumptions used for value in use impairment testing are based on those used for investment appraisal. The investment appraisal price assumptions are recommended by the senior vice president economic & energy insights after considering a range of external prices, and supply and demand forecasts under various energy transition scenarios. They are reviewed and approved by management. As a result of the current uncertainty over the pace of transition to lower-carbon supply and demand and the social, political and environmental actions that will be taken to meet the goals of the Paris climate change agreement, the forecasts and scenarios considered include those where those goals are met as well as those where they are not met. bp sees the prospect of an enduring impact on the global economy as a result of the COVID-19 pandemic, with the potential for weaker demand for energy for a sustained period. bp’s management also expects that the aftermath of the pandemic will accelerate the pace of transition to a lower carbon economy and energy system as countries seek to ‘build back better’ so that their economies will be more resilient in the future. As a result of all the above, bp revised its price assumptions for value-in-use impairment testing, lowering them compared to those used in 2019 and extending the period covered to 2050. A summary of the group’s revised price assumptions, in real 2020 terms, is provided below. The assumptions represent management’s best estimate of future prices, which sit within the range of external forecasts considered as appropriate for the purpose. They are considered by bp to be broadly in line with a range of transition paths consistent with the Paris climate goals. However, they do not correspond to any specific Paris-consistent scenario. An inflation rate of 2% (2019 2%) is applied to determine the price assumptions in nominal terms. The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 262 bp Annual Report and Form 20-F 2020 Financial statements 1. Significant accounting policies, judgements, estimates and assumptions – continued Brent oil ($/bbl) Henry Hub gas ($/mmBtu) 2021 50 3.00 2025 50 3.00 2030 60 3.00 2040 60 3.00 2050 50 2.75 Impairment charges were recognized in 2020 following the downward revision of the price assumptions. See Note 2 for further information. The majority of reserves and resources that support the carrying value of the company’s subsidiaries holding oil and gas properties are expected to be produced over the next 10 years. Oil and natural gas reserves In addition to oil and natural gas prices, significant technical and commercial assessments are required to estimate oil and natural gas reserves held by the company’s subsidiaries. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of estimates of oil and natural gas reserves. bp bases its reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements. Reserves assumptions used for value-in-use tests in the company’s subsidiaries reflect the reserves and resources that management currently intend to develop. The recoverable amount of oil and gas properties is determined using a combination of inputs including reserves, resources and production volumes. Risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved or probable. Foreign currency translation The functional and presentation currency of the financial statements is US dollars. Transactions in foreign currencies are initially recorded in the functional currency by applying the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included in the income statement. Non-monetary assets and liabilities, other than those measured at fair value, are not retranslated subsequent to initial recognition. Exchange adjustments arising when the opening net assets and the profits for the year retained by a non-US dollar functional currency branch are translated into US dollars are recognized in a separate component of equity and reported in other comprehensive income. Income statement transactions are translated into US dollars using the average exchange rate for the reporting period. Financial guarantees The company enters into financial guarantee contracts with its subsidiaries. At the inception of a financial guarantee contract, a liability is recognized initially at fair value and then subsequently measured at the higher of the contract’s estimated expected credit loss and the amount initially recognized less, where appropriate, cumulative amortization. Share-based payments Equity-settled transactions The cost of equity-settled transactions with employees of the company and other members of the group is measured by reference to the fair value of the equity instruments on the date on which they are granted and is recognized as an expense over the vesting period, which ends on the date on which the employees become fully entitled to the award. A corresponding credit is recognized within equity. Fair value is determined by using an appropriate, widely used, valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of the shares of the company (market conditions). Non-vesting conditions, such as the condition that employees contribute to a savings-related plan, are taken into account in the grant-date fair value, and failure to meet a non-vesting condition, where this is within the control of the employee, is treated as a cancellation and any remaining unrecognized cost is expensed. For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are measured at the fair value of the goods or services received, unless their fair value cannot be reliably estimated. If the fair value of the goods and services received cannot be reliably estimated, the transaction is measured by reference to the fair value of the equity instruments granted. Cash-settled transactions The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the corresponding liability which is recognized on the balance sheet. The liability is remeasured at fair value at each balance sheet date until settlement, with changes in fair value recognized in the income statement. Pensions The defined benefit pension plans are plans that share risks between entities under common control. In each instance BP p.l.c. is the principal employer and carries the whole plan surplus or deficit on its balance sheet. The cost of providing benefits under the company’s defined benefit plans is determined separately for each plan using the projected unit credit method, which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to determine the present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company becomes committed to a change. Net interest expense relating to pensions, which is recognized in the income statement, represents the net change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking into account expected changes in the obligation or plan assets during the year. The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 263 1. Significant accounting policies, judgements, estimates and assumptions – continued Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not subsequently reclassified to profit and loss. The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the present value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, typically by way of refund. Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable. Significant estimate: pensions Accounting for defined benefit pensions involves making significant estimates when measuring the company's pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties. Pension assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the company’s balance sheet, and pension expense for the following year. The assumptions used are provided in Note 4. The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate, salary growth and mortality levels. Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in material changes to the carrying amounts of the company’s pension obligations within the next financial year for the UK plan. Any differences between these assumptions and the actual outcome will also affect future net income and net assets. The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and obligation used are provided in Note 4. Income taxes Income tax expense represents the sum of current tax and deferred tax. Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity. Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are taxable or deductible in other periods as well as items that are never taxable or deductible. The company’s liability for current tax is calculated using tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for taxable temporary differences. Deferred tax assets are only recognized to the extent that it is probable that they will be realized in the future. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and liabilities are not discounted. See Note 6 for further details. Financial assets Financial assets are recognized initially at fair value, normally being the transaction price. In the case of financial assets not at fair value through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their classification, as set out below. The company derecognizes financial assets when the contractual rights to the cash flows expire or the rights to receive cash flows have been transferred to a third party along with substantially all of the risks and rewards or control of the asset.This includes the derecognition of receivables for which discounting arrangements are entered into. Financial assets measured at amortized cost Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets are derecognized or impaired and when interest is recognized using the effective interest method. This category of financial assets includes trade and other receivables. Cash equivalents Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets measured at amortized cost. Financial liabilities All financial liabilities held by the company are classified as financial liabilities measured at amortized cost. Financial liabilities include other payables, accruals, and finance debt. The company determines the classification of its financial liabilities at initial recognition. Financial liabilities measured at amortized cost All financial liabilities are initially recognized at fair value, net of directly attributable transaction costs. For interest-bearing loans and borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing. After initial recognition, financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively. The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 264 bp Annual Report and Form 20-F 2020 1. Significant accounting policies, judgements, estimates and assumptions – continued Impact of new International Financial Reporting Standards The company adopted ‘Interest Rate Benchmark Reform – Phase I – Amendments to IFRS 9 ‘Financial instruments’ and IFRS 7 ‘Financial instruments: Disclosures'’ with effect from 1 January 2020. The adoption of ‘Interest Rate Benchmark Reform – Phase I – Amendments to IFRS 9 ‘Financial instruments’ and IFRS 7 ‘Financial instruments: Disclosures’ has had no material impact on the company's financial statements. There are no other new or amended standards or interpretations adopted during the year that have a significant impact on the financial statements. Financial statements 2. Investments Cost At 1 January 2020 Additions Disposals At 31 December 2020 Amounts provided At 1 January 2020 Additions At 31 December 2020 Cost At 1 January 2019 Additions Disposals At 31 December 2019 Amounts provided At 1 January 2019 At 31 December 2019 At 31 December 2020 At 31 December 2019 Subsidiaries Associates Shares Shares Total $ million 166,287 — (2) 166,285 33 5,710 5,743 166,302 — (15) 166,287 33 33 160,542 166,254 2 — — 2 — — — 2 — — 2 — — 2 2 166,289 — (2) 166,287 33 5,710 5,743 166,304 — (15) 166,289 33 33 160,544 166,256 At 31 December 2020, the carrying amount of the company’s net assets of $112.6 billion exceeded the group’s market capitalisation of $70.5 billion. This is identified by IAS 36 Impairment of Assets as an indicator that assets may be impaired. Management’s best estimate oil and natural gas price assumptions for value-in-use impairment testing were revised downwards during 2020 and the period covered extended to 2050. Management also undertook a re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan. As a result, management performed a review of the carrying value of the company’s major investments to identify potential impairment triggers, in line with the requirements of IAS 36 Impairment of Assets. Potential indicators of impairment were identified in those subsidiaries which hold, or whose own investments hold, significant Upstream assets, requiring further tests to be performed. The cash generating units assessed were considered to be each investment holding company chain (defined as each direct subsidiary and its own investments), as this is judged to be the smallest identifiable group of assets from the company’s perspective that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Further tests were performed on BP International Ltd (BPI), BP Holdings North America Ltd (BPHNA) and BP Holdings Canada Ltd. A recoverable amount for each investment company holding chain was calculated based on the value in use cash flows from Upstream and Downstream goodwill impairment calculations, combined with additional sources of uplift in value identified. The value in use tests used the present value of pre-tax cash flows discounted using a pre-tax rate which varies depending on the country of operation of the underlying assets. Upstream For Upstream assets held by the company’s subsidiaries, the value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates of cessation of production of each producing field, based on current estimates of reserves and resources, appropriately risked. As the production profile and related cash flows can be estimated from bp’s past experience, management believes that the cash flows generated over the estimated life of field is the appropriate basis upon which to assess assets for impairment. The estimated date of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons, production costs, the contractual duration of the production concession and the selling price of the hydrocarbons produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of each field is computed using appropriate individual economic models and key assumptions agreed by bp management. Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis, including operating and capital expenditure, are derived from the business segment plan. The production profiles used are consistent with the reserve and resource volumes approved as part of bp’s centrally controlled process for the estimation of proved and probable reserves and total resources. The key assumptions used in the value-in-use calculation are oil and natural gas prices, production volumes and the discount rate. Oil and gas price assumptions and discount rate assumptions used were as disclosed in Note 1. Due to economic developments, regulatory change and emissions reduction activity arising from climate concern and other factors, future commodity prices and other assumptions may differ from the forecasts used in the calculations. The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 265 2. Investments – continued The Upstream impairment review on BPHNA assets calculated that a 10% price increase would add $1,780 million to the value of the assets, while a 10% price reduction would result in a $2,728 million reduction. A 1% increase in discount rate would likely generate a reduction in the value of assets of $796 million, while a 1% reduction in the rate would have increased the value by $1,151 million. The Upstream impairment review on BPI assets calculated that a 10% price increase would add $2,032 million to the value of the assets, while a 10% price reduction would result in a $3,741 million reduction. A 1% increase in discount rate would likely generate a reduction in the value of assets of $1,467 million, while a 1% reduction in the rate would have increased the value by $1,365 million. The Upstream impairment review on BP Holdings Canada assets calculated that a 10% price increase would add $574 million to the value of the assets, while a 10% price reduction would result in a $574 million reduction. A 1% increase in discount rate would likely generate a reduction in the value of assets of $178 million, while a 1% reduction in the rate would have increased the value by $204 million. These price sensitivity analyses do not, however, represent management’s best estimate of any impairment charges or reversals that might be recognized as they do not fully incorporate consequential changes that may arise, such as changes in costs and business plans and phasing of development. For example, costs across the industry are more likely to decrease as oil and natural gas prices fall. The above sensitivity analyses therefore do not reflect a linear relationship between revenue and value that can be extrapolated. The interdependency of these inputs and risk factors plus the diverse characteristics of Upstream oil and gas properties limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to the price assumptions or production volumes. Downstream Recoverable amounts for BPHNA also included the value of key Downstream assets held by the refinery, midstream and retail businesses. For the Downstream, cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of up to five years. To determine the value in use for each of the cash-generating units, cash flows for a period of 10 years are discounted at an 8% pre-tax rate and aggregated with a terminal value. Discount rates are a key assumption in the value-in-use calculations for the downstream businesses. A 1% increase in discount rate would likely generate a reduction in the value of assets of $2,200 million, while a 1% reduction in the rate would have increased the value by $2,200 million. Other The valuation of BPI also included the Upstream activity of the company’s equity-accounted investment in Rosneft. The BPI and BPHNA investment holding chains include the bp group’s Oil and Gas trading function. These have been included in the valuation based on a multiple of underlying replacement cost profit. Conclusions for Investment holding company chains As a result of this review, the company has recognized total impairment charges of $5,710 million (2019 $nil) against its investments. Impairments were calculated on a value in use basis, applying discount rates of 8% to investments in North America and a weighted average rate of 11% overall. Charges of $2,565 million related to Upstream investments in Canada held through BP Holdings Canada Ltd. Impairments of $2,638 million were recognized against the BPHNA investment holding chain and $507 million against the BPI investment holding chain. The residual value of the investment holding chains which have recognized impairment charges during the year was $138,688 million. The more important subsidiaries of the company at 31 December 2020 and the percentage holding of ordinary share capital (to the nearest whole number) are set out below. For a full list of related undertakings see Note 14. Subsidiaries International BP Global Investments BP International Burmah Castrol Canada BP Holdings Canada US % Country of incorporation Principal activities 100 England & Wales 100 England & Wales 100 Scotland Investment holding Integrated oil operations Lubricants 100 England & Wales Investment holding BP Holdings North America 100 England & Wales Investment holding The carrying value of the investment in BP International Limited at 31 December 2020 was $75,645 million (2019 $76,152 million). 3. Receivables Amounts receivable from subsidiariesa Amounts receivable from associates Current 284 7 291 2020 Non-current 3,174 — 3,174 $ million 2019 Non-current 2,771 — 2,771 Current 134 1 135 a Non-current receivables includes a promissory note issued by BP (Abu Dhabi) Limited in 2016 in consideration for the issue of BP p.l.c. ordinary shares to the government of Abu Dhabi. The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 266 bp Annual Report and Form 20-F 2020 Financial statements 4. Pensions The primary pension arrangement is a funded final salary pension plan in the UK under which retired employees draw the majority of their benefit as an annuity. This pension plan is governed by a corporate trustee whose board is composed of four member-nominated directors, four company-nominated directors, an independent director, and an independent chairman nominated by the company. The trustee board is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as investment policies of the plan. The plan is closed to new joiners and is currently under consultation for closure to future accrual. As at 31 December 2020, it remains open to ongoing accrual for current members. New joiners are eligible for membership of a defined contribution plan. The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall due. During 2020 the aggregate level of contributions was $189 million (2019 $236 million). The aggregate level of contributions in 2021 is expected to be approximately $180 million, and includes contributions we expect to be required to make by law or under contractual agreements, as well as an allowance for discretionary funding. For the primary UK plan there is a funding agreement between the company and the trustee. On an annual basis a schedule of contributions is agreed covering the next five years. Contractually committed funding amounted to $1,014 million at 31 December 2020, all of which relates to future service. The surplus relating to the primary UK pension plan is recognized on the balance sheet on the basis that the company is entitled to a refund of any remaining assets once all members have left the plan. The obligation and cost of providing the pension benefits is assessed annually using the projected unit credit method. The date of the most recent actuarial review was 31 December 2020. The principal plans are subject to a formal actuarial valuation every three years in the UK. The most recent formal actuarial valuation of the main pension plan was as at 31 December 2017 and a valuation as at 31 December 2020 is currently under way. The material financial assumptions used for estimating the benefit obligations of the plans are set out below. The assumptions are reviewed by management at the end of each year and are used to evaluate accrued pension benefits at 31 December and pension expense for the following year. Financial assumptions used to determine benefit obligation Discount rate for pension plan liabilities Rate of increase in salaries Rate of increase for pensions in payment Rate of increase in deferred pensions Inflation for pension plan liabilities Financial assumptions used to determine benefit expense Discount rate for pension plan service costs Discount rate for pension plan other finance expense Inflation for pension plan service costs 2020 1.4 3.6 2.8 2.8 2.9 2020 2.1 2.1 2.6 % 2019 2.1 3.4 2.7 2.7 2.7 % 2019 3.0 2.9 3.1 The discount rate assumption is based on third-party AA corporate bond indices and we use yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumption is based on the difference between the yields on index-linked and fixed-interest long-term government bonds. The inflation assumption is used to determine the rate of increase for pensions in payment and the rate of increase in deferred pensions. The assumption for the rate of increase in salaries is based on our inflation assumption plus an allowance for expected long-term real salary growth. This comprises of an allowance for promotion-related salary growth of 0.7%. In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best practice in the UK and have been chosen with regard to the latest available published tables adjusted to reflect the experience of the plans and an extrapolation of past longevity improvements into the future. For the main pension plan the mortality assumptions are as follows: Mortality assumptions Life expectancy at age 60 for a male currently aged 60 Life expectancy at age 60 for a male currently aged 40 Life expectancy at age 60 for a female currently aged 60 Life expectancy at age 60 for a female currently aged 40 2020 26.9 28.4 28.8 30.4 Years 2019 27.3 28.9 28.7 30.5 The assets of the primary plan are held in a trust, the primary objective of which is to accumulate pools of assets sufficient to meet the obligations of the plan. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management. A proportion of the assets are held in equities, owing to a higher expected level of return over the long term of such assets with an acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment portfolios are highly diversified. The trustee’s long-term investment objective for the primary UK plan as it matures is to invest in assets whose value changes in the same way as the plan liabilities, in order to reduce the level of funding risk. To move towards this objective, the UK plan uses a liability driven investment (LDI) approach for part of the portfolio, investing primarily in government bonds to achieve this matching effect for the most significant plan liability assumptions of interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements, whereby the plan borrows money using existing bonds as security and which will be bought back at a specified price at an agreed future date. The funds raised are used to invest in further bonds to increase the proportion of assets which match the plan liabilities. The borrowings are shown separately in the analysis of pension plan assets in the table below. The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 267             4. Pensions – continued For the primary UK pension plan there is an agreement with the trustee to increase the proportion of assets with liability matching characteristics over time primarily by reducing the proportion of plan assets held as equities and increasing the proportion held as bonds. During 2020, the plan switched 11% from equities to bonds (2019 2%). The company’s asset allocation policy for the primary plan is as follows: Asset category Total equity (including private equity) Bonds/cash (including LDI) Property/real estate % 17 76 7 The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2020 were $4,217 million (2019 $4,804 million) of government-issued nominal bonds and $24,576 million (2019 $19,462 million) of index-linked bonds. The primary plan does not invest directly in either securities or property/real estate of the company or of any subsidiary. The fair values of the various categories of assets held by the defined benefit plans at 31 December are presented in the table below, including the effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on page 269. Fair value of pension plan assets Listed equities – developed markets – emerging markets Private equitya Government issued nominal bondsb Government issued index-linked bondsb Corporate bondsb Propertyc Cash Other Debt (repurchase agreements) used to fund liability driven investments 2020 5,008 418 2,899 4,303 24,576 8,906 2,553 1,392 795 (9,387) 41,463 a Private equity is valued at fair value based on the most recent third-party net asset, revenue or earnings based valuations that generally result in the use of significant unobservable inputs. b Bonds held are denominated in sterling and valued using quoted prices in active markets. c Property held is all located in the United Kingdom and is valued based on an analysis of recent market transactions supported by market knowledge derived from third-party valuers. Analysis of the amount charged to profit or loss Current service costa Past service incomeb Operating charge relating to defined benefit plans Payments to defined contribution plan Total operating charge Interest income on plan assetsc Interest on plan liabilities Other finance (income) Analysis of the amount recognized in other comprehensive income Actual asset return less interest income on pension plan assets Change in financial assumptions underlying the present value of the plan liabilities Change in demographic assumptions underlying the present value of plan liabilities Experience gains and losses arising on the plan liabilities Remeasurements recognized in other comprehensive income 2020 250 (48) 202 49 251 (724) 595 (129) 4,108 (4,205) 585 54 542 a The costs of managing the fund’s investments are treated as being part of the investment return, the costs of administering our pensions plan benefits are included in current service cost. b Past service income represents curtailment gains arising from restructuring programmes. c The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above. $ million 2019 6,285 1,096 2,675 4,884 19,462 6,132 2,507 426 98 (7,436) 36,129 $ million 2019 227 2 229 42 271 (909) 756 (153) 2,945 (2,292) 136 (57) 732 The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 268 bp Annual Report and Form 20-F 2020           4. Pensions – continued Movements in benefit obligation during the year Benefit obligation at 1 January Exchange adjustments Operating charge relating to defined benefit plans Interest cost Contributions by plan participantsa Benefit payments (funded plans)b Benefit payments (unfunded plans)b Remeasurements Benefit obligation at 31 December Movements in fair value of plan assets during the year Fair value of plan assets at 1 January Exchange adjustments Interest income on plan assetsc Contributions by plan participantsa Contributions by employers (funded plans) Benefit payments (funded plans)b Remeasurementsc Fair value of plan assets at 31 Decemberd e Surplus at 31 December Represented by Asset recognized Liability recognized The surplus may be analysed between funded and unfunded plans as follows Funded Unfunded The defined benefit obligation may be analysed between funded and unfunded plans as follows Funded Unfunded Financial statements 2020 29,743 1,302 202 595 21 (1,291) (6) 3,566 34,132 36,129 1,583 724 21 189 (1,291) 4,108 41,463 7,331 7,567 (236) 7,331 7,564 (233) 7,331 $ million 2019 26,796 941 229 756 20 (1,207) (5) 2,213 29,743 32,085 1,141 909 20 236 (1,207) 2,945 36,129 6,386 6,588 (202) 6,386 6,588 (202) 6,386 (33,899) (233) (34,132) (29,541) (202) (29,743) a Most of the contributions made by plan participants were made under salary sacrifice. b  The benefit payments amount shown above comprises $1,280 million benefits (2019 $1,194 million) plus $17 million (2019 $18 million) of plan expenses incurred in the administration of the benefit. c  The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above. d  Reflects $41,088 million of assets held in the BP Pension Fund (2019 $35,811 million) and $306 million held in the BP Global Pension Trust (2019 $251 million), as well as $53 million representing the company’s share of Merchant Navy Officers Pension Fund (2019 $53 million) and $16 million of Merchant Navy Ratings Pension Fund (2019 $14 million). e  The fair value of plan assets includes borrowings related to the LDI programme as described on page 268. Sensitivity analysis The discount rate, inflation, salary growth and the mortality assumptions all have a significant effect on the amounts reported. A one-percentage point change, in isolation, in certain assumptions as at 31 December 2020 for the company’s plans would have had the effects shown in the table below. The effects shown for the expense in 2021 comprise the total of current service cost and net finance income or expense. Discount ratea Effect on pension expense in 2021 Effect on pension obligation at 31 December 2020 Inflation rateb Effect on pension expense in 2021 Effect on pension obligation at 31 December 2020 Salary growth Effect on pension expense in 2021 Effect on pension obligation at 31 December 2020 $ million One percentage point Increase Decrease (275) (5,653) 198 7,685 145 5,337 (116) (4,482) 31 670 (27) (585) a The amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation. b The amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions. One additional year of longevity in the mortality assumptions would increase the 2021 pension expense by $28 million and the pension obligation at 31 December 2020 by $1,403 million. The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 269                             4. Pensions – continued Estimated future benefit payments and the weighted average duration of defined benefit obligations The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2030 and the weighted average duration of the defined benefit obligations at 31 December 2020 are as follows: Estimated future benefit payments 2021 2022 2023 2024 2025 2026-2030 Weighted average duration 5. Payables Amounts payable to subsidiaries Accruals Other payables $ million 1,070 1,084 1,118 1,139 1,133 5,929 Years 19.2 Current 27,933 2 76 28,011 2020 Non-current 28,060 — 24 28,084 $ million 2019 Non-current 31,894 — 33 31,927 Current 17,916 21 70 18,007 Included in current amounts payable to subsidiaries is an interest-bearing payable of $4,236 million (2019 $4,236 million) with BP International Limited, with interest being charged based on a 3-month USD LIBOR rate plus 55 basis points and a maturity date of December 2021. Also included in current amounts payable is an interest-bearing payable of $5,033 million (2019 $5,031 million) with BP Finance plc. On 30 April 2020 the facility was renewed for 10 years until 30 April 2030 with interest being charged based on a 3-month USD LIBOR rate minus 0.14%. Though due in 2030, the loan is repayable to BP Finance plc at one business days notice. Non-current amounts payable to subsidiaries includes an interest-bearing payable of $27,100 million (2019 $27,100 million) with BP International Limited, with interest being charged based on a 3-month USD LIBOR rate plus 65 basis points and a maturity date of May 2023. Current liabilities of $27,933m are payable to wholly owned subsidiaries of the company within the bp group. As such, the company has control over whether these balances can be called in by the counterparties. Though the $5,033 million loan from BP Finance plc can be called at one business days notice, this loan is recorded as a non-current receivable in the financial statements of BP Finance plc, since the counterparty has no intent to call the loan at short notice. The balance of $4,236 million payable to BP International Ltd is due in December 2021, though it is the intent of management to extend this amount into a longer term loan. The company also has current liabilities of $18,652 million on Internal Funding Accounts (IFAs) payable to BP International Ltd. Whilst IFA credit balances are legally repayable on demand, in practice they have no termination date. These balances form a key part of the bp group’s liquidity and funding arrangements under its centralised treasury funding model. The bp group regularly looks to optimize its funding position, as part of which management will consider whether any part of these IFA balances should be converted into longer term loans, or maintained as current payables. The maturity profile of the financial liabilities included in the balance sheet at 31 December is shown in the table below. These amounts are included within payables. Due within 1 to 2 years 2 to 5 years More than 5 years 2020 30 27,259 795 28,084 $ million 2019 48 31,499 380 31,927 The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 270 bp Annual Report and Form 20-F 2020       6. Taxation Tax charge included in total comprehensive income Deferred tax Origination and reversal of temporary differences in the current year This comprises: Taxable temporary differences relating to pensions Deferred tax Deferred tax liability Pensions Net deferred tax liability Analysis of movements during the year At 1 January Charge (credit) for the year in the income statement Charge (credit) for the year in other comprehensive income At 31 December Financial statements 2020 338 338 2,631 2,631 2,293 44 294 2,631 $ million 2019 389 389 2,293 2,293 1,907 55 331 2,293 At 31 December 2020, deferred tax assets of $375 million on other temporary differences; $12 million relating to pensions, $75 million relating to income losses and $288 million relating to other deductible temporary differences (2019 $391 million relating to other deductible temporary differences, $67 million relating to income losses and $9 million relating to pensions) were not recognised as it is not considered probable that suitable taxable profits will be available in the company from which the future reversal of the underlying temporary differences can be deducted. There is no fixed expiry date for the unrecognised temporary differences. 7. Called-up share capital The allotted, called-up and fully paid share capital at 31 December was as follows: Issued 8% cumulative first preference shares of £1 eacha 9% cumulative second preference shares of £1 eacha Ordinary shares of 25 cents each At 1 January Issue of new shares for the scrip dividend programme Issue of new shares for employee share-based payment plans Repurchase of ordinary share capital At 31 December Shares thousand 7,233 5,473 21,535,840 — 34,000 (120,058) 21,449,782 2020 $ million 12 9 21 Shares thousand 7,233 5,473 — 9 (30) 5,383 21,525,464 208,927 37,400 (235,951) 5,362 21,535,840 5,383 2019 $ million 12 9 21 5,381 52 9 (59) 5,383 5,404 a The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of preference shares. Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each. In the event of the winding-up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value. During 2020 the company repurchased 120 million ordinary shares at a cost of $776 million, including transaction costs of $4 million, as part of the share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The repurchased shares represented 0.6% of ordinary share capital. The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 271 7. Called-up share capital – continued Treasury sharesa At 1 January Purchases for settlement of employee share plans Issue of new shares for employee share-based payment plans Shares re-issued for employee share-based payment plans At 31 December Of which - shares held in treasury by bp                - shares held in ESOP trusts - shares held by bp’s US plan administratorb a See Note 8 for definition of treasury shares. b Held by the company in the form of ADSs to meet the requirements of employee share-based payment plans in the US. 2020 Shares thousand Nominal value $ million Shares thousand 1,296,856 — 34,116 (143,322) 1,187,650 1,105,157 82,491 2 323 1,426,265 1,118 — 37,400 9 (167,927) (36) 296 1,296,856 275 1,163,077 133,707 72 21 — 2019 Nominal value $ million 356 — 9 (42) 323 290 33 — For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by bp during the year, representing 5.4% (2019 5.9%) of the called-up ordinary share capital of the company. During 2020, the movement in shares held in treasury by bp represented less than 0.3% (2019 less than 0.5%) of the ordinary share capital of the company. 8. Capital and reserves See statement of changes in equity for details of all reserves balances. Share capital The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury shares. Share premium account The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares. Capital redemption reserve The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled. Merger reserve The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in an acquisition made by the issue of shares. Treasury shares Treasury shares represent bp shares repurchased and available for specific and limited purposes. For accounting purposes, shares held in Employee Share Ownership Plans (ESOPs) and by bp’s US share plan administrator to meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are, therefore, included in the financial statements as treasury shares. The ESOPs are funded by the company and have waived their rights to dividends in respect of such shares held for future awards. Until such time as the shares held by the ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders’ equity. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the company. Foreign currency translation reserve The foreign currency translation reserve records exchange differences arising from the translation of the financial information of the foreign currency branch. Upon disposal of foreign operations, the related accumulated exchange differences are recycled to the income statement. Profit and loss account The balance held on this reserve is the accumulated retained profits of the company. The profit and loss account reserve includes $23,600 million (2019 $24,107 million), the distribution of which is limited by statutory or other restrictions. The financial statements for the year ended 31 December 2020 do not reflect the dividend announced on 2 February 2021 which will be paid in March 2021; this will be treated as an appropriation of profit in the year ended 31 December 2021. 9. Financial guarantees The company has issued guarantees under which the maximum aggregate liabilities at 31 December 2020 were $80,891 million (2019 $78,586 million), the majority of which relate to finance debt of subsidiaries. Also included are guarantees of subsidiaries' liabilities under the Consent Decree between the United States, the Gulf states and bp and under the settlement agreement with the Gulf states in relation to the Gulf of Mexico oil spill. The company has also issued uncapped indemnities and guarantees, including a guarantee of subsidiaries’ liabilities under the Plaintiffs' Steering Committee  agreement relating to the Gulf of Mexico oil spill. See note 33 in the consolidated group financial statements of BP p.l.c. for further information. The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 272 bp Annual Report and Form 20-F 2020 10. Share-based payments Effect of share-based payment transactions on the company’s result and financial position Total expense recognized for equity-settled share-based payment transactions Total (credit) expense recognized for cash-settled share-based payment transactions Total expense recognized for share-based payment transactions Closing balance of liability for cash-settled share-based payment transactions Total intrinsic value for vested cash-settled share-based payments Financial statements 2020 491 (13) 478 1 — $ million 2019 433 (1) 432 17 16 Additional information on the company’s share-based payment plans is provided in Note 11 to the consolidated financial statements. 11. Auditor’s remuneration Note 36 to the consolidated financial statements provides details of the remuneration of the company’s auditor on a group basis. 12. Directors’ remuneration Remuneration of directors Total for all directors Emoluments Amounts awarded under incentive schemesa Total a Excludes amounts relating to past directors. 2020 6 14 20 $ million 2019 9 20 29 Emoluments These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits earned during the relevant financial year, plus cash bonuses awarded for the year. Further information is provided in the Directors’ remuneration report on page 103. 13. Employee costs and numbers Employee costsa Wages and salaries Social security costs Pension costs Average number of employees Upstream Downstream Other businesses and corporate 2020 814 119 90 1,023 2020 312 1,213 2,307 3,832 $ million 2019 597 107 80 784 2019 279 1,142 2,300 3,721 a Comparative information has been restated due the correction of an accounting error. The employee costs noted above relate to those employees with contracts of employment in the name of BP p.l.c.. These costs are borne by other undertakings within the group. The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 273 14. Related undertakings of the group In accordance with Section 409 of the Companies Act 2006, a full list of related undertakings, the registered office address and the percentage of equity owned as at 31 December 2020 is disclosed below. Unless otherwise stated, the share capital disclosed comprises ordinary shares or common stock (or local equivalent thereof) which are indirectly held by BP p.l.c. All subsidiary undertakings are controlled by the group and their results are fully consolidated in the group’s financial statements. The percentage of equity owned by the group is 100% unless otherwise noted below. The stated ownership percentages represent the effective equity owned by the group. Subsidiaries 200 PS Overseas Holdings Inc. 563916 Alberta Ltd. (99.90%)a ACP (Malaysia), Inc. Actomat B.V. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 240 - 4th Avenue SW, Calgary AB T2P 4H4, Canada Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Advance Petroleum Holdings Pty Ltd Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Advance Petroleum Pty Ltd AE Cedar Creek Holdings LLCb AE Goshen II Holdings LLCb AE Goshen II Wind Farm LLCb AE Power Services LLCb AE Wind PartsCo LLCb Air BP Albania SHA Air BP Brasil Ltda. Air BP Canada LLCb Air BP Croatia d.o.o. Air BP Finland Oy Air BP Iceland Air BP Limited Air BP Norway AS Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Air BP Albania Sh.A., Aeroporti Nderkombetar i Tiranes, “Nene Tereza”, Post Box 2933 in Tirana, Albania Avenida Rouxinol, 55 , Offices 501-514 , Moema Office Tower, São Paulo, 04516 - 000, Brazil Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Savska cesta 32, Zagreb, Croatia Öljytie 4, 01530 Vantaa, Finland Skogarhlid 12, 105, Reykjavik, Iceland Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Tjuvholmen allé, Oslo, 0252, Norway Air BP Sales Romania S.R.L. 59 Aurel Vlaicu Street, Otopeni, Ilfov County, Romania Air BP Sweden AB Air Refuel Pty Ltdc Allgreen Pty Ltd AM/PM International Inc. American Oil Company Amoco (Fiddich) Limited Amoco (U.K.) Exploration Company, LLCb Amoco Bolivia Services Company Inc. Box 8107, 10420, Stockholm, Sweden Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands Amoco Canada International Holdings B.V. d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Amoco Capline Pipeline Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Chemical (Europe) S.A. Amoco Chemicals (FSC) B.V. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Amoco Cypress Pipeline Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Destin Pipeline Company Amoco Environmental Services Companyd Amoco Exploration Holdings B.V. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Bank of America Center, 16th Floor, 1111 East Main Street, Richmond VA 23219, United States d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Amoco Guatemala Petroleum Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco International Finance Corporation Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco International Petroleum Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Louisiana Fractionator Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Main Pass Gathering Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Marketing Environmental Services Company 400 East Court Avenue, Des Moines ID 50309, United States Amoco MB Fractionation Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco MBF Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Netherlands Petroleum Company Amoco Nigeria Exploration Company Limitede Amoco Nigeria Oil Company Limited Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 188, Awolowo Road, S. W. Ikoyi, Lagos, Nigeria 188, Awolowo Road, S. W. Ikoyi, Lagos, Nigeria Amoco Nigeria Petroleum Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Nigeria Petroleum Company Limited 188, Awolowo Road, S. W. Ikoyi, Lagos, Nigeria The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 274 bp Annual Report and Form 20-F 2020 Financial statements 14. Related undertakings of the group – continued Amoco Norway Oil Company Amoco Oil Holding Company Amoco Olefins Corporation Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Overseas Exploration Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Pipeline Asset Company Amoco Pipeline Holding Company Amoco Properties Incorporated Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Remediation Management Services Corporation Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Research Operating Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Rio Grande Pipeline Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Somalia Petroleum Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Sulfur Recovery Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco Trinidad Gas B.V. d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Amoco Tri-States NGL Pipeline Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Amoco U.K. Petroleum Limited AmProp Finance Company Amprop Illinois I Limited Partnershipf Amprop, Inc. Anaconda Arizona, Inc. Arabian Production And Marketing Lubricants Company (50.00%) Aral Aktiengesellschaft Aral Luxembourg S.A. Aral Services Luxembourg Sarl Aral Tankstellen Services Sarl ARCO British International, Inc. ARCO British Limited, LLCb ARCO Coal Australia Inc. ARCO El-Djazair Holdings Inc. ARCO Environmental Remediation, L.L.C.b ARCO Gaviota Company ARCO International Investments Inc. ARCO Midcon LLCb ARCO Oil Company Nigeria Unlimitedb ARCO Resources Limited ARCO Trinidad Exploration and Production Company Limited ARCO Unimar Holdings LLCb Aspac Lubricants (Malaysia) Sdn. Bhd. (63.03%) Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States 801 Adlai Stevenson Drive, Springfield, IL, 62703, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Riyadh Airport Road, Business Gate, Building C2, 2nd Floor. , Saudi Arabia Wittener Straße 45, 44789 Bochum, Germany Bâtiment B, 36route de Longwy, L-8080 Bertrange, Luxembourg Autoroute A3/E25, L-3325 Berchem Ouest, Luxembourg Bâtiment B, 36route de Longwy, L-8080 Bertrange, Luxembourg Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 8/10, Broad Street, Lagos, Nigeria Level 17, 717 Bourke Street, Docklands VIC 3008, Australia 2 Bayside Executive Park, West Bay, Nassau, Bahamas Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 9, Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur, Malaysia Atlantic 2/3 UK Holdings Limited Atlantic Richfield Companyd Autino Holdings Limited (88.85%)g Autino Limited (88.85%) Auwahi Wind Energy Holdings LLCb B2Mobility GmbH Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Abbey Gardens, 7th Floor, 4 Abbey Street, Reading, RG1 3BA, United Kingdom Abbey Gardens, 7th Floor, 4 Abbey Street, Reading, RG1 3BA, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Wittener Straße 45, 44789 Bochum, Germany Bahia de Bizkaia Electridad, S.L. (75.00%) Atraque Punta Lucero, Explanada Punta Ceballos s/n, Ziérbena (Vizcaya), Spain Baltimore Ennis Land Company, Inc. 4400 Easton Commons Way , Suite 125, Columbus OH 43219, United States BASS Management Pty Ltd (51.00%) Level 17, 717 Bourke Street, Docklands VIC 3008, Australia BASS NZ Head Trust (51.00%) BASS NZ Management Pty Ltd Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Level 17, 717 Bourke Street, Docklands VIC 3008, Australia BASS NZ Sub Management Pty Ltd Level 17, 717 Bourke Street, Docklands VIC 3008, Australia BASS NZ Sub Trust (51.00%) BE LAMBDA-ENA GmbH Black Lake Pipe Line Company BP - Castrol (Thailand) Limited (59.81%)h BP (Abu Dhabi) Limited BP (Barbados) Holding SRL BP (Barbican) Limitedi BP (China) Holdings Limitedb Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Donau-City-Straße 7, 1220, Wien, Austria Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa South Sathon, Bangkok 10120, Thailand Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Erin Court, Bishop's Court Hill, St. Michael , Barbados Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Room 2101, 21F Youyou International Plaza, 76 Pujian Road, Pudong, Shanghai Pilot Free Trade Zone, PRC The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 275 14. Related undertakings of the group – continued BP (China) Industrial Lubricants Limitedb BP (Gibraltar) Limitedj BP (GTA Mauritania) Finance Limited BP (GTA Senegal) Finance Limited BP (Guangzhou) Advanced Mobility Limitedb BP (Hunan) Petroleum Company Limitedb BP (Indian Agencies) Limitedi BP (Shandong) Petroleum Co., Ltdb BP (Shanghai) Trading Limitedb No.9 Bin Jiang South Road, Petrochemical Industrial Park, Taicang Gangkou Development Zone, Jiangsu Province, China Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Room 1218, Building 3, No. 6 Hanxing San jie, Zhongcun Street, Panyu District, Guangzhou, Guangdong Province , China Room 1001, 10th Floor, Building A2, Xiangjiang Times Business Square, No.179 Xiandao Road, Yuelu District, Changsha, Hunan, China Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Room 1-2201, Sijian Meilin Mansion, No. 48-15 Wuyingshan Middle Road, Tianqiao District, Ji'nan, Shandong, China Room 2105, No. 28 Maji Road, Donghua Financial Building, China (Shanghai) Pilot Free Trade, Shanghai, 200131, China BP Absheron Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Advanced Mobility Limited BP Africa Limitedi BP Africa Oil Limited BP Akaryakit Ortakligi (70.00%)f BP Alternative Energy Holdings Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Degirmen Yolu Cad. No:28 Asia Ofis Park K:3 , Icerenky - Atasehir, Istanbul, 34752, Turkey Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Alternative Energy Investments Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Alternative Energy North America Inc. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Alternative Energy Trinidad and Tobago Limited 5-5A Queen's Park West, Port-of-Spain, Trinidad and Tobago BP America Chemicals Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP America Foreign Investments Inc. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP America Inc. BP America Limited Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP America Production Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP AMI Leasing, Inc. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Amoco Chemical Malaysia Holding Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Amoco Exploration (Faroes) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Amoco Exploration (In Amenas) Limited 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom BP Andaman II Ltd BP Angola (Block 18) B.V. BP Argentina Exploration Company BP Argentina Holdings LLCb BP Asia Pacific Holdings Limited BP Asia Pacific Pte Ltdi BP Australia Employee Share Plan Proprietary Limited BP Australia Group Pty Ltde BP Australia Investments Pty Ltd BP Australia Pty Ltd BP Australia Shipping Pty Ltdk BP Australia Swaps Management Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Aviation A/S c/o Danish Refuelling Services I/S, Hydrantvej 16, 2770 Kastrup, Denmark BP Aviation Infrastructure Pty Ltd BP Benevolent Fund Trustees Limitedi BP Berau Ltd. Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Biocombustíveis S.A. (96.53%) Avenida das Nações Unidas, 12399, 4fl, Sao Paulo, Brazil BP Biofuels Advanced Technology Inc. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Biofuels Brazil Investments Limited BP Biofuels North America LLCb BP Biofuels Trading Comércio, Importação e Exportação Ltda. (48.27%) Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Avenida das Nações Unidas, 12.399 , 4º andar, cj. 41B, sala 01, São Paulo, Brazil BP Bomberai Ltd. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Brasil Ltda. BP Brazil Tracking L.L.C.b BP Bulwer Island Pty Ltdl BP Business Service Centre Asia Sdn Bhd Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Level 9, Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur, Malaysia BP Business Service Centre KFTb BP Business Service Centre KFT, 32-34 Soroksári út, H-1095 Budapest, Hungary The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 276 bp Annual Report and Form 20-F 2020 Financial statements 14. Related undertakings of the group – continued BP Business Solutions India Private Limited 71 & 73, 7th Floor, Maker Maxity Bandra Kurla Complex, Bandra (East), Bandra Suburban, Mumbai, 400051, India BP Canada Energy Development Company Stewart McKelvey, Attention: Lawrence J. Stordy, 900, 1959 Upper Water Street, Halifax NS B3J 3N2, Canada BP Canada Energy Group ULC Stewart McKelvey, Attention: Lawrence J. Stordy, 900, 1959 Upper Water Street, Halifax NS B3J 3N2, Canada BP Canada Energy Marketing Corp. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Canada International Holdings B.V. d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands BP Canada Investments Inc. BP Capellen Sarl Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Aire de Capellen, L-8309 Capellen, Luxembourg BP Capital Markets America Inc. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Capital Markets p.l.c. BP Car Fleet Limitedi BP Caribbean Company BP Castrol KK (64.84%) Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States East Tower 20F, Gate City Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan BP Castrol Lubricants (Malaysia) Sdn. Bhd. (63.03%) Level 9, Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur, Malaysia BP CCUS UK LTD BP Central Pipelines LLCb BP Chemical Remediation Holdings LLCb BP Chemicals East China Investments Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Chemicals Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP China Exploration and Production Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Comercializadora de Energia Ltda. Avenida das Nações Unidas, 12399, rooms 62,63 and 64 size B, 6th floor, Landmark Building, São Paulo, 04578-000, Brazil BP Commodities Trading Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Commodity Supply B.V. BP Company North America Inc.m BP Containment Response Limited BP Containment Response System Holdings LLCb BP Continental Holdings Limited BP Corporate Holdings Limited BP Corporation North America Inc. BP D230 Limited BP Danmark A/S BP D-B Pipeline Company LLC (54.37%)f BP Developments Australia Pty. Ltd. BP Dogal Gaz Ticaret Anonim Sirketi BP East Kalimantan CBM Limited BP Eastern Mediterranean Limited BP Egypt Company BP Egypt East Delta Marine Corporationd BP Egypt East Tanka B.V. BP Egypt Production B.V. BP Egypt Ras El Barr B.V. d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 150 West Market Street, Suite 800, Indianapolis IN 46204, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Orestads Boulevard 73, 2300, Kobenhavn S, Denmark Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 15, 240 St Georges Terrace, Perth WA 6000, Australia Degirmen yolu cad. No:28 , Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands BP Egypt West Mediterranean (Block B) B.V. d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands BP Energía México, S. de R.L. de C.V. Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico BP Energy Asia Pte. Limited BP Energy Colombia Limited BP Energy Company BP Energy do Brasil Ltda. 7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil BP Energy Europe Limited BP Energy Retail LLCb BP Energy Solutions B.V. BP Espana, S.A. Unipersonaln BP Estaciones y Servicios Energéticos, Sociedad Anónima de Capital Variablec BP Europa SEo BP Exploracion de Venezuela S.A. 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Avenida de Barajas 30, Madrid, Madrid, Spain Avenida Santa Fe 505, Piso 10, Distrito Federal , MEXICO C.P. 0534, Mexico Überseeallee 1, 20457, Hamburg, Hamburg, Germany Av. Francisco de Miranda, con primera avenida de Los Palos , Grandes, Edif Cavendes, piso 9, ofi 903, Los Palos Grandes, Chacao / Caracas, Caracas / Miranda, 1060, Venezuela, Bolivarian Republic of BP Exploration & Production Inc.d BP Exploration (Absheron) Limited Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 277 14. Related undertakings of the group – continued BP Exploration (Algeria) Limited BP Exploration (Alpha) Limited BP Exploration (Angola) Limited BP Exploration (Azerbaijan) Limited BP Exploration (Canada) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration (Caspian Sea) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration (D230) Limited BP Exploration (Delta) Limited BP Exploration (El Djazair) Limited BP Exploration (Epsilon) Limited BP Exploration (Gambia) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom PricewaterhouseCoopers (Bahamas) Limited, Providence House, East Hill Street, P.O. Box N-3910, Nassau, Bahamas Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 3 Kairaba Avenue, 3rd Floor Centenary, Serekunda West, Kanifing Municipality, Gambia BP Exploration (Greenland) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration (Madagascar) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration (Morocco) Limited BP Exploration (Namibia) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration (Nigeria Finance) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration (Nigeria) Limited BP Exploration (Psi) Limited 1, Oyinka Abayomi Drive, Ikoyi, Lagos, Nigeria Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration (Shafag-Asiman) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration (Shah Deniz) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration (South Atlantic) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration (STP) Limited BP Exploration (Xazar) Pte. Ltd. Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore BP Exploration Angola (Kwanza Benguela) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration Argentina Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration Beta Limited BP Exploration China Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration Company (Middle East) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration Company Limited BP Exploration Indonesia Limited BP Exploration Libya Limited BP Exploration Mexico Limited BP Exploration Mexico, S.A. De C.V.c BP Exploration North Africa Limited 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. CuajimalpaC.P., 05349 México D.F., Mexico Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration Operating Company Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration Orinoco Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration Personnel Company Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Exploration Peru Limited BP Express Shopping Limited BP Finance Australia Pty Ltd BP Finance p.l.c. BP Foundation Incorporatedb BP France BP Fuels & Lubricants AS BP Fuels Deutschland GmbH Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe, Cergy Pontoise, France Tjuvholmen allé, Oslo, 0252, Norway Wittener Straße 45, 44789 Bochum, Germany BP Gas & Power Investments Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Gas Europe, S.A.U. BP Gas Marketing Limited BP Gas Supply (Angola) LLCb BP Ghana Limited BP Global Investments Limitedi BP Global Investments Salalah & Co LLC BP Global West Africa Limited BP GOM Logistics LLCb BP Greece Limited BP Guangdong Limited (90.00%)b Avenida de la Transición Española 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States PwC Tower, A4 Rangoon Lane, Cantonments City, PMB CT 42 Cantonments, Accra, Ghana Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom PO Box 2309, Salalah, 211, Oman Heritage Place, 13th Floor, 21 Lugard Avenue, Ikoyi, Lagos, Nigeria Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom No 833, South Guang Zhou Avenue, Haizhu District, Guangzhou Province , China The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 278 bp Annual Report and Form 20-F 2020 Financial statements 14. Related undertakings of the group – continued BP High Density Polyethylene - France BP Holdings (Thailand) Limited (81.18%)p BP Holdings B.V. BP Holdings Canada Limitedi BP Holdings Central Europe B.V. BP Holdings International B.V. BP Holdings North America Limitedi BP Hong Kong Limited BP India Private Limited (88.65%) BP Indonesia Investment Limited BP International Limitedi BP International Services Company Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe, Cergy Pontoise, France 39/77-78 Moo 2 Rama II Road, Tambon Bangkrachao, Amphur Muang, Samutsakorn 74000, Thailand d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Überseeallee 1, 20457 , Hamburg, Federal Republic of Germany, Germany d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Unit 25-150, 25/f, Two Harbour Square, 180 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400093, India Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States BP Investment Management Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Investments Asia Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Iran Limited BP Iraq N.V. BP Italia SpA BP Japan K.K. BP Korea Limited BP Kuwait Limited BP Latin America LLCb BP Latin America Upstream Services Inc. BP LNG Shipping Limited BP Lubricants KK (64.84%) BP Lubricants USA Inc. BP Luxembourg S.A. Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Langerbruggekaai 18, 9000 Gent, Belgium Via Verona 12, Cornaredo, 20010, Milan, Italy 15th Fl. Roppongi Hills Mori Tower, 10-1 Roppongi 6-chome, Minato-ku, Tokyo106-6115, Japan 19th Floor, 302, Teheran-ro, Gangnam-gu, Seoul, Korea, Republic of Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Washington House, 4th Floor, 16 Church Street, Hamilton HM 11 , Bermuda East Tower 20F, Gate City Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Aire de Capellen, L-8309 Capellen, Luxembourg BP Malaysia Holdings Sdn. Bhd. (70.00%) Level 9, Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur, Malaysia BP Management International B.V. BP Management Netherlands B.V. BP Marine Limited BP Mariner Holding Company LLCb BP Maritime Services (Singapore) Pte. Limited BP Marketing Egypt LLC BP Mauritania Investments Limited BP Mauritius Limited (in liquidation) BP Middle East Enterprises Corporation BP Middle East Limitedi BP Middle East LLC BP Midstream Partners GP LLCb BP Midstream Partners Holdings LLCb BP Midstream Partners LP (54.37%)q BP Midwest Product Pipelines Holdings LLCb BP Mocambique Limitada BP Mocambique Limited BP Muturi Holdings B.V. BP Nederland Holdings BV d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore Plot 28 , North 90 Road , Housing & Construction Bank Building, New Cairo, Cairo, 11835, Egypt Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 5th Floor, Ebene Esplanade, 24 Cybercity, Ebene, Mauritius Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom P.O.Box 1699, Dubai, 1699, United Arab Emirates Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Society and Geography Avenue, Plot No. 269 , Third floor, Maputo, Mozambique Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands BP Netherlands Upstream B.V. d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands BP New Ventures Middle East Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP New Zealand Holdings Limited Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand BP New Zealand Share Scheme Limited Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand BP Nutrition Inc. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Offshore Gathering Systems Inc. BP Offshore Pipelines Company LLCb BP Offshore Response Company LLCb BP Oil (Thailand) Limited (90.40%)r BP Oil Australia Pty Ltd Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 39/77-78 Moo 2 Rama II Road, Tambon Bangkrachao, Amphur Muang, Samutsakorn 74000, Thailand Level 17, 717 Bourke Street, Docklands VIC 3008, Australia BP Oil Espana, S.A. Unipersonal Polígono Industrial "El Serrallo", s/n 12100 Grao de Castellón, Castellón de la Plana, Spain BP Oil Hellenic S.A. 26A Apostolopoulou, Halandri, Athens, Attica, 152 31, Greece The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 279 14. Related undertakings of the group – continued BP Oil International Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Oil Kent Refinery Limited (in liquidation) Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Oil Llandarcy Refinery Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Oil Logistics UK Limited BP Oil New Zealand Limited BP Oil Pipeline Company BP Oil Senegal S.A. Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Route de Ouakam x Corniche Ouest, Immeuble Alphadio Barry, Dakar, Senegal BP Oil Shipping Company, USA Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Oil UK Limited BP Oil Venezuela Limited BP Oil Vietnam Limited BP Oil Yemen Limited BP Olex Fanal Mineralol GmbH BP One Pipeline Company LLCb BP Pacific Investments Ltd BP Pakistan (Badin) Inc. Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Überseeallee 1, 20457, Hamburg, Hamburg, Germany Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Pakistan Exploration and Production, Inc. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Pension Escrow Limited BP Pension Trustees Limitedi BP Pensions (Overseas) Limitedj BP Pensions Limitedi BP Petrochemicals India Investments Limited BP Petroleo y Gas, S.A. Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Albert House, South Esplanade, St. Peter Port, GY1 1AW, Guernsey Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Av. Francisco de Miranda, con primera avenida de Los Palos , Grandes, Edif Cavendes, piso 9, ofi 903, Los Palos Grandes, Chacao / Caracas, Caracas / Miranda, 1060, Venezuela, Bolivarian Republic of BP Petrolleri Anonim Sirketi BP Pipelines (Alaska) Inc. BP Pipelines (BTC) Limited Degirmen yolu cad. No:28 , Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Pipelines (North America) Inc. 45 Memorial Circle, Augusta ME 04330, United States BP Pipelines (SCP) Limited BP Pipelines (TANAP) Limited BP Pipelines TAP Limited BP Polska Services Sp. z o.o. BP Portugal -Comercio de Combustiveis e Lubrificantes SA BP Poseidon Limited BP Products North America Inc. BP Properties Limitedi BP Raffinaderij Rotterdam B.V. Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Ul. Jasnogórska 1, 31-358 Kraków, Malopolskie, Poland Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 2405 York Road, Ste 201, Lutherville Timonium MD 21093-2264, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands BP Refinery (Kwinana) Proprietary Limited Level 17, 717 Bourke Street, Docklands VIC 3008, Australia BP Regional Australasia Holdings Pty Ltd Level 17, 717 Bourke Street, Docklands VIC 3008, Australia BP Retail Properties Limited BP River Rouge Pipeline Company LLC (54.37%)f BP Russian Investments Limited BP Russian Ventures Limited BP SC Holdings LLCb BP Scale Up Factory Limited BP Senegal Investments Limited BP Services International Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Servicios de Combustibles S.A. de C.V. Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico BP Servicios territoriales, S.A. de C.V. Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico BP Shafag-Asiman Limited BP Shipping Limited BP Singapore Pte. Limited BP Solar Espana, S.A. Unipersonalc BP Solar International Inc. BP Solar Pty Ltd Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore Avenida de la Transición Española 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC 3008, Australia BP South America Holdings Ltd Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Southern Africa Proprietary Limited (75.00%) 199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa BP Southern Cone Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 280 bp Annual Report and Form 20-F 2020 Financial statements 14. Related undertakings of the group – continued BP Subsea Well Response (Brazil) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Subsea Well Response Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Taiwan Marketing Limited BP Technology Ventures Inc. 7FNo. 71Sec. 3Min Sheng East Road, Taipei, Taiwan Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Technology Ventures Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom BP Train 2/3 Holding SRL BP Trinidad and Tobago LLC (70.00%)b BP Trinidad Processing Limited BP Turkey Refining Limitedi BP Two Pipeline Company LLC (54.37%)f BP UK Fatima Limited BP UK Retained Holdings Limited BP Venezuela Investments B.V. BP West Aru I Limited BP West Aru II Limited BP West Papua I Limited BP West Papua III Limited BP Wind Energy Beacon Holding LLCb BP Wind Energy Empire Holding LLCb BP Wind Energy North America Inc. The Financial Services, Bishop's Court Hill, St. Michael, Barbados Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 5-5A Queen's Park West, Port-of-Spain, Trinidad and Tobago Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Wiriagar Ltd. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States BP Xiaoju New Energy (Shenzhen) Co., Ltd. (70.00%) Room 201, Complex A, Qianwan Road 1, Qianhai Shenzhen-Hong Kong Cooperation Zone, Shenzhen City, PRC BP+Amoco International Limitedi BP-AIOC Exploration (TISA) LLC (65.88%)b BPNE International B.V. BPRY Caribbean Ventures LLC (70.00%)b BPX (Eagle Ford) Gathering LLC (75.00%)b BPX (Karnes) Gathering LLCb BPX (KCS Resources) LLCb BPX (Permian) Gathering LLCb BPX (WSF Operating) Inc. BPX Energy Inc. BPX Gathering Holdings LLCb BPX Midstream LLCb BPX Operating Company BPX Production Company BPX Properties (GP) LLCb BPX Properties (LP) LLCb BPX Properties (NA) LPf Brian Jasper Nominees Pty Ltd Britannic Energy Trading Limited Britannic Investments Iraq Limited Britannic Marketing Limited Britannic Strategies Limited Britannic Trading Limited British Pipeline Agency Limited (50.00%)s Britoil Limited BTC Pipeline Holding Company Limited Burmah Castrol Australia Pty Ltdt Burmah Castrol Holdings Inc. Burmah Castrol PLCi Burmah Castrol South Africa (Pty) Limitedu Burmah Chile SpA BXL Plastics Limitedv Cadman DBP Limited Casitas Pipeline Company Castrol (China) Limited Castrol (Ireland) Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 153 Neftchilar Avenue, Baku, AZ1010, Azerbaijan d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States The Corporation Company, 1833 South Morgan Road, Oklahoma City OK 73128, United States 350 North St. Paul Street, Suite 2900, Dallas, Texas 75201, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States CT Corporation System, 1021 Main Street, Suite 1150, Houston, Texas 77002, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 1999 Bryan St., STE 900, Dallas TX 75201, United States Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 5-7 Alexandra Road, Hemel Hempstead, Herts., HP2 5BS, United Kingdom 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom 199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa Av. Américo Vespucio Sur No. 100, of. 1101, Las Condes, Santiago, Chile Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Unit 25-150, 25/f, Two Harbour Square, 180 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong One Spencer Dock, North Wall Quay, Dublin 1, Ireland The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 281 14. Related undertakings of the group – continued Castrol (Shanghai) Management Co., Ltdb Castrol (Shenzhen) Company Limitedb Castrol (Tianjin) Lubricants Co., Ltdb Castrol (U.K.) Limited Castrol Australia Pty. Limited CASTROL Austria GmbH Castrol B.V. Castrol Belgium B.V. Castrol BP Petco Limited Liability Company (65.00%)b Castrol Brasil Ltda. Floor 3, Building 5, 255 Guiqiao Road, Shanghai Pilot Free Trade Zone, China No.1120 Mawan Road, Nanshan District, Shenzhen, China South of NanGang Industrial Area, and East of Hai Gang Road, Tianjin Economic Development Area, Tianjin, China Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Straße 6, Objekt 17, Industriezentrum NÖ-Süd,, 2355 Wr. Neudorf, Austria d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Langerbruggekaai 18, 9000 Gent, Belgium 9th Floor, 22-36 Nguyen Hue Street, 57-69F Dong Khoi Street, District 1, Ho Chi Minh City, Vietnam Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil Castrol Caribbean & Central America Inc. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Castrol CEE spółka z ograniczoną odpowiedzialnością Castrol Colombia Ltda. ul. Grzybowska 62, 00-844, Warszawa, Poland Calle 81, No 11 - 42, Oficina 901, Torre Sur, Bogota, Colombia Castrol Del Peru S.A. Av. Camino Real, 111 Torre B Oficina, 603 San Isidro, Lima, Peru Castrol Egypt Lubricants S.A.E. (51.00%) First floor of building located at Plot 28- the first Sector, City Center, New Cairo, Cairo, Egypt Castrol Holdings Europe B.V. d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Castrol Holdings International Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Castrol India Limited (51.00%) Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400093, India Castrol Industrie und Service GmbH Erkelenzer Straße 20, 41179 Mönchengladbach, Germany Castrol KK (64.84%) Castrol Limited Castrol Lubricants RO S.R.L Castrol Mexico, S.A. de C.V.c Castrol Namibia (Pty) Limited Castrol Nederland B.V. Castrol Offshore Limited East Tower 20F, Gate City Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan Technology Centre, Whitchurch Hill, Pangbourne, Reading, RG8 7QR, United Kingdom Bucharest, District 3, Boulevard Comeliu Coposu, no 6-8, Unirii View Building, Office 101, floor 1, Romania Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. CuajimalpaC.P., 05349 México D.F., Mexico 24 Orban Street, Klein Windhoek, Windhoek, Namibia d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Castrol Pakistan (Private) Limited D-67/1, Block # 4, Scheme # 5, Clifton, Karachi, Pakistan Castrol Philippines, Inc. Castrol Servicos Ltda. Castrol Singapore PTE. Limited Castrol Switzerland GmbH Castrol Ukraine LLCb Castrol Zimbabwe (Private) Limited Centrel Pty Ltd Charge Your Car Limitedc Chargemaster (Europe) GmbH Chargemaster Limited Charging Solutions Limited CH-Twenty, Inc. Clarisse Holdings Pty Ltd 32/F LKG Tower, Ayala Avenue, Makati City, 6801, Philippines Avenida Tamboré, 448, Barueri, Sao Paulo, Brazil 7 Straits View #26-01, Marina-One East Tower, 018936, Singapore Baarerstrasse 139, 6300 Zug, Switzerland 2A Kostiantynivska Street, Kyiv, 04071, Ukraine Barking Road, Willowvale, Harare, Zimbabwe Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Breckland, Linford Wood, Milton Keynes, MK146GY, United Kingdom Wittener Straße 45, 44789 Bochum, Germany Breckland, Linford Wood, Milton Keynes, MK146GY, United Kingdom 55 Baker Street, London, W1U 7EU, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Coastwise Trading Company, Inc. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Consolidada de Energia y Lubricantes, (CENERLUB) C.A. Avenida Eugenio Mendoza / San Felipe Edificio Centro Letonia, Torre Ing-Bank, Piso 12, Oficina 124-B, La Castellana, Caracas, 1060, Venezuela, Bolivarian Republic of Coro Trading NZ Limited Cuyama Pipeline Company Dermody Petroleum Pty. Ltd. DHC Solvent Chemie GmbH Dome Beaufort Petroleum Limited Dome Wallis (1980) Limited Partnership (92.50%)f Dradnats, Inc. Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Timmerhellstsr. 28, 45478, Mülheim/Ruhr, Germany 240 - 4th Avenue SW, Calgary AB T2P 4H4, Canada 240 - 4th Avenue SW, Calgary AB T2P 4H4, Canada 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States ECM Markets SA (Pty) Ltd (75.00%) 199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa Elektromotive Limited Breckland, Linford Wood, Milton Keynes, MK146GY, United Kingdom Elite Customer Solutions Pty Ltd Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Elm Holdings Inc. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Energy Global Investments (USA) Inc. Enstar LLCb Estonian Aviation Fuelling Services (50.00%) Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Harju maakond, Lasnamäe linnaosa, Väike-Sõjamäe tn 12a, Tallinn, 11415, Estonia Europa Oil NZ Limited Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand Exmoor Nominee Limited (51.00%) Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 282 bp Annual Report and Form 20-F 2020 Financial statements 14. Related undertakings of the group – continued Exmoor Properties GP Limited (51.00%) Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Exmoor Properties PF LP (51.00%) Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Exomet, Inc. 4400 Easton Commons Way , Suite 125, Columbus OH 43219, United States Expandite Contract Services Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Exploration (Luderitz Basin) Limited Finite Carbon Corporation (80.50%) Finite Resources, Inc. (80.50%) Flat Ridge 2 Holdings LLCb Flat Ridge Wind Energy, LLCb Foseco Holding International B.V. Foseco Holding, Inc. Foseco, Inc. Fosroc Expandite Limited Fotech Group Limiteda Fotech Solutions (Canada) Ltd. Fotech USA, LLC Fowler I Holdings LLCb Fowler Ridge Holdings LLCb Fowler Ridge I Land Investments LLCb Fowler Ridge II Holdings LLCb Fowler Ridge III Wind Farm LLCb Fowler Ridge Wind Farm LLCb FreeBees B.V. Fuelplane- Sociedade Abastecedora De Aeronaves, Unipessoal, Lda Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 435 Devon Park Drive, Suite 700, Wayne, Pennsylvania, 19087, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 112 SW 7th Street, Suite 3C, Topeka, Kansas, 66603 d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 240-Fourth Avenue SW, Calgary AB T2P 4H4 Canada 1999 Bryan St., STE 900, Dallas TX 75201, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal FWK (2017) Limited (In Liquidation) 55 Baker Street, London, W1U 7EU, United Kingdom FWK Holdings (2017) Ltd (In Liquidation) 55 Baker Street, London, W1U 7EU, United Kingdom Gardena Holdings Inc. Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Gelsenkirchen Raffinerie Netz GmbH Alexander-von-Humboldt-Straße 1, Gelsenkirchen, 45896, Germany GOAM 1 C.I S. A .S Calle 80 No.11-42 Oficina 901, Bogota, 110111, Colombia Grampian Aviation Fuelling Services Limited (In Liquidation) Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Guangdong Investments Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Hangzhou BP Xiaoju New Energy Co., Ltd. (70.00%) Highlands Ethanol, LLCb Horizon 38 Management Company Limited (53.50%) Room 1536, Building 2, Taimei International Building, Qiantang New District, Hangzhou City, Zhejiang Province Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 10 Upper Berkeley Street, London, W1H 7PE, United Kingdom IGI Resources, Inc. 921 S. Orchard St. Ste G, Boise ID 83705, United States Insight Analytics Solutions Holdings Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Insight Analytics Solutions Limited Insight Analytics Solutions USA, Inc Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 2108 55th Street, Suite 105, Boulder CO 80301, United States International Bunker Supplies Pty Ltd Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Iraq Petroleum Company Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Jinhua BP Xiaoju New Energy Co., Ltd. (70.00%) Floor 1, No. 6, Panlong East Road, Fotang Town, Yiwu City, Zhejiang Province, China Jupiter Insurance Limited Ken-Chas Reserve Company Kenilworth Oil Company Limitedi Latin Energy Argentina S.A. Lebanese Aviation Technical Services S.A.L. Limited Liability Company BP Toplivnaya Kompaniab Limited liability company Setra Lubricantsb Low Carbon Friends Limited Lubricants UK Limited Lytt Limited Suite 1 North, First Floor, Albert House, South Esplanade, St Peter Port, GY1 1AJ, Guernsey Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Av. Cordoba 315 Piso 8, Buenos Aires, 1054, Argentina P O Box - 11 -5814c/o Coral Oil Building, 583Avenue de Gaulle, Raoucheh, Beirut, Lebanon Novinskiy blvd.8, 17th floor, premises 11, 121099, Moscow, Russian Federation 2 Paveletskaya sq, Building1, 115054 Moscow, Russia Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Manormaker (Nominee No. 1) Limited (99.90%) 11 Black Horse Lane, Ipswich, Suffolk, IP1 2EF, United Kingdom Manormaker (Nominee No. 2) Limited (99.90%) 11 Black Horse Lane, Ipswich, Suffolk, IP1 2EF, United Kingdom Manormaker GP Limited (99.90%) 11 Black Horse Lane, Ipswich, Suffolk, IP1 2EF, United Kingdom Mardi Gras Transportation System Company LLC (70.34%)b Markoil, S.A. Unipersonal Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Avenida de la Transición Española 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 283 14. Related undertakings of the group – continued Masana Petroleum Solutions (Pty) Ltd (37.88%) 199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa Mayaro Initiative for Private Enterprise Development (70.00%)b Mehoopany Holdings LLCb Mes Tecnologia En Servicios Y Energia, S.A. De C.V.c Mountain City Remediation, LLCb Net Zero North Sea Storage Limited 5-5A Queen's Park West, Port-of-Spain, Trinidad and Tobago Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. CuajimalpaC.P., 05349 México D.F., Mexico Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Net Zero Teesside Power Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom No. 1 Riverside Quay Proprietary Limited Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Nordic Lubricants A/S Nordic Lubricants AB Orestads Boulevard 73, 2300, Kobenhavn S, Denmark Hemvärnsgatan , 171 54, Solna, Sweden North America Funding Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States OMD87, Inc. 111 Eighth Avenue, New York, New York, 10011 OnSight Analytics Solutions India Private Ltd. Office No. 306, Regus Business Center , 3rd Floor, Abbusali St, Saligramam, Chennai, Tamil Nadu, 600093, India Onyx Insight Korea Co., Ltd. OOO BP STLb Orion Delaware Mountain Wind Farm LPb Orion Energy Holdings, LLCb Orion Energy L.L.C.b Orion Post Land Investments, LLCb Pacroy (Thailand) Co., Ltd. (39.50%) 504-ho, 213-3, Cheomdan-ro, Jeju-si, Jeju-do, Korea, Republic of Novinskiy blvd.8, 18th floor, office 14, 121099, Moscow, Russian Federation Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa Sathon, Bangkok 10120, Thailand Pearl River Delta Investments Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Phoenix Petroleum Services, Limited Liability Company Royal Tulip Al Rasheed Hotel, Baghdad Tower, PO Box 8070, Baghdad, Iraq PRODUITS METALLURGIE DOITTAU Prospect International, C.A. (In liquidation) PT Castrol Indonesia (68.30%) PT Castrol Manufacturing Indonesia (68.30%) PT Jasatama Petroindoc Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe, Cergy Pontoise, France Avenida Eugenio Mendoza / San Felipe Edificio Centro Letonia, Torre Ing-Bank, Piso 12, Oficina 124-B, La Castellana, Caracas, 1060, Venezuela, Bolivarian Republic of Perkantoran Hijau Arkadia, Tower B 9th Floor, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta12520, Indonesia JL. Raya, Merak KM 117, DS Gerem, Gerem Grogol, Cilegon, Banten, Indonesia Perkantoran Hijau Arkadia, Tower B 8th Floor, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta12520, Indonesia RAPI SA (62.51%) 1, Proteos & 51, Anapafseos str, 15235 Vrilissia, Attica, Greece Remediation Management Services Company Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Richfield Oil Corporation Rolling Thunder I Power Partners, LLCb Ropemaker Deansgate Limited Ropemaker Properties Limited Ruhr Oel GmbH (ROG) Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Alexander-von-Humboldt-Straße 1, Gelsenkirchen, 45896, Germany Rusdene GSS Limited (In Liquidation) Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Saturn Insurance Inc. 400 Cornerstone Drive, Suite 240, Williston VT 05495, United States Shanghai Quanzhi New Energy Co., Ltd. (70.00%) No. 399 Dongfeng highway, Dongping Town, Chongming District, Shanghai City, (Dongping Economic Development, China Sherbino I Holdings LLCb Sherbino Mesa I Land Investments LLCb Sociedade de Promocao Imobiliaria Quinta do Loureiro, SA Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal Société de Gestion de Dépots d'Hydrocarbures - GDHb Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe, Cergy Pontoise, France SOFAST Limited (63.09%)w South Texas Shale LLCb Southern Ridge Pipeline Holding Company Southern Ridge Pipeline LP LLCb SRHP (99.99%)b 23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa South Sathon, Bangkok 10120, Thailand Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe, Cergy Pontoise, France Standard Oil Company, Inc. Stryde Inc. 251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Stryde International Limited Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom Stryde Limited Sunrise Oil Sands Partnership (50.00%)f Suzhou BP Xiaoju New Energy Co., Ltd. (70.00%) Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom c/o Husky Oil Operations Limited, 707 - 8th Avenue SW, Calgary AB T2P 1H5, Canada Room 703, Building 32, No.258 Shengpu Road, Suzhou Industrial Park, China The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 284 bp Annual Report and Form 20-F 2020 Financial statements 14. Related undertakings of the group – continued Taradadis Pty. Ltd. Telcom General Corporation (99.96%)d Terre de Grace Partnership (75.00%)f The Anaconda Company The BP Share Plans Trustees Limitedi The Burmah Oil Company (Pakistan Trading) Limited The Standard Oil Company TISA Education Complex LLC (65.88%)b TJKK Toledo Refinery Holding Company LLCb Union Texas International Corporation Vastar Pipeline, LLCb Viceroy Investments Limited Warrenville Development Limited Partnershipb Water Way Trading and Petroleum Services LLC Level 17, 717 Bourke Street, Docklands VIC 3008, Australia 818 West Seventh Street, 2nd Floor, Los Angeles, CA, 90017 1100, 635 - 8th Avenue SW, Calgary AB T2P 3M3, Canada 814 Thayer Avenue, Bismarck, ND, 58501-4018 Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom 4400 Easton Commons Way , Suite 125, Columbus OH 43219, United States 153 Neftchilar Avenue, Baku, AZ1010, Azerbaijan 15th Fl. Roppongi Hills Mori Tower, 10-1 Roppongi 6-chome, Minato-ku, Tokyo106-6115, Japan Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom 33 North LaSalle Street, Chicago, Illinois 60602, United States Khur Al-Zubair, pear No 1, Basra, Iraq Welchem, Inc. 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States West Kimberley Fuels Pty Ltd Westlake Houston Development, LLCb Whiting Clean Energy, Inc. Windpark Energy Nederland B.V. Winwell Resources, L.L.C.b Wiriagar Overseas Ltd Level 17, 717 Bourke Street, Docklands VIC 3008, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands 5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States Estera Corporate Services (BVI) Limited, Jayla Place, Wickhams Cay 1, PO Box 3190, Road Town, Tortola, VG1110, Virgin Islands, British Zhuhai BP Xiaoju New Energy Co., Ltd. (70.00%) Room 105-72746 (Centralized office area), No.6 Baohua Road, Hengqin New District, Zhuhai City, China The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 285 14. Related undertakings of the group – continued Related undertakings other than subsidiaries A Flygbranslehantering AB (AFAB) (25.00%) Box 135, 190 46 Arlanda, Sweden 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Aashman Power Limited (49.97%) ABG Autobahn-Betriebe GmbH (32.58%)b Abu Dhabi Marine Areas Limited (33.33%)h Advanced Biocatalytics Corporation (24.50%)a AEP I HoldCo LLC (24.30%)b AGES International GmbH & Co. KG, Langenfeld (24.70%)f Berghausener Straße 96, 40764 Langenfeld, Germany Berghausener Straße 96, 40764 Langenfeld, Germany AGES Maut System GmbH & Co. KG, Langenfeld (24.70%)f Brucknerstraße 4, 1041 Wien, Austria 1 More London Place, London, SE1 2AF, United Kingdom 18010 Skypark Circle , #130 , Irvine CA 92614, United States Harvard Business Services, Inc., 16192 Coastal Hwy, Lewes, Delaware, 19958, United States Air BP Copec S.A. (51.00%) Air BP Italia Spa (50.00%) Patricio Raby Benavente, Moneda N° 920 Of 205, Santiago, Chile Via Sardegna 38, 00187, Roma, Italy Air BP PBF del Peru S.A.C. (50.00%) Avenida Ricardo Rivera Navarrete n.501 / room 1602, Lima, Peru, Peru Air BP Petrobahia Ltda. (50.00%) Av. Anita Garibaldi, n.252, 2o floor, Ala Sul, Federação, Salvador, Bahia, 40210-750, Brazil Aircraft Fuel Supply B.V. (28.57%) Aircraft Refuelling Company GmbH (33.33%)b Aker BP ASA (30.00%) Alyssum Group Ltd (26.23%)e Ambarli Depolama Hizmetleri Limited Sirketi (50.00%) Oude Vijfhuizerweg 6, 1118LV Luchthaven, Schiphol, Netherlands Trabrennstraße 6-8 3, A-1020, Wien, Austria Oksenoyveien 10, , 1366 Lysaker, Norway 522 Fulham Road, London, SW6 5NR, United Kingdom Yakuplu Mahallesi Genc, Osman Caddesi, No.7 Beylikdüzü, Istanbul, Turkey Ammenn GmbH (75.00%) Luisenstraße 5 a, 26382 Wilhelmshaven, Germany Apollo Geração de Energia Ltda. (49.97%) Sitio Canto, número S/N, bairro / distrito Zona Rural, município Russas - CE, CEP 62900-000, Brazil Aragonesa de Gestión de Energías Alternativas, SL (49.97%) ATAS Anadolu Tasfiyehanesi Anonim Sirketi (68.00%)x Atlantic 1 Holdings LLC (34.00%)b Atlantic 2/3 Holdings LLC (42.50%)b Atlantic 4 Holdings LLC (37.78%)b Atlantic LNG 2/3 Company of Trinidad and Tobago Unlimited (42.50%) Atlantic LNG 4 Company of Trinidad and Tobago Unlimited (37.78%) Calle Alcala numero 63, 28014, Madrid, Spain Degirmen yolu cad. No:28 , Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago Atlantic LNG Company of Trinidad and Tobago (34.00%) Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago Australasian Lubricants Manufacturing Company Pty Ltd (50.00%)h Australian Terminal Operations Management Pty Ltd (50.00%) Auwahi Holdings, LLC (50.00%)b Auwahi Wind Energy LLC (50.00%)b Aviation Fuel Services Limited (25.00%) Aviation Service (Iraq) Limited (40.00%)y Axion Comercializacion De Combustibles Y Lubricantes S.A. (50.00%) Axion Energy Argentina S.A. (50.00%) Axion Energy Holding S.L. (50.00%)b Axion Energy Paraguay S.R.L. (50.00%)b Axuy Energy Holdings S.R.L. (50.00%)b Axuy Energy Investments S.R.L. (50.00%)b Azerbaijan Gas Supply Company Limited (23.06%)h Building 1, 747 Lytton Road, Murarrie QLD 4172, Australia Level 3, Unit 3, 22 Albert Road, South Melbourne VIC 3205, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Calshot Way Central Area, Heathrow Airport, Hounslow, Middlesex, TW6 1PY, United Kingdom Mw1 Building 557 Shoreham Road, Heathrow Airport, London,TW6 3RT, United Kingdom Luis A de Herrera 1248, Torre II, Piso 22 (Edificio World Trade Center), Montevideo, Uruguay Carlos María Della Paolera 265, Piso 22, Ciudad Autónoma de Buenos Aires, Argentina Arbea Campus Empresarial, Edifico 1. Ctra de Fuencarral a Alcobendas, M603, KM 3,8 28108 Alcobendas, MADRID, SPAIN Av. España 1369 esquina San Rafael, Asunción, Paraguay Avenida Luis Alberto de Herrera 1248, Oficina 1901, Montevideo, Uruguay Avenida Luis Alberto de Herrera 1248, Oficina 1901, Montevideo, Uruguay Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands Azerbaijan International Operating Company (30.37%)z Baplor S.A. (50.00%) 190 Elgin Avenue, George Town, Grand Cayman , KY1-9005, Cayman Islands Colonia 810, Oficina 403, Montevideo, Uruguay Barranca Sur Minera S.A. (50.00%) Beer Energien GmbH & Co. KG (50.00%)f Beer GmbH (50.00%) Belenos s.r.l. (32.48%) Bellflower Solar 1, LLC (49.97%)b Belmont Technology Inc. (26.10%) Bighorn Solar 1, LLC (49.97%)b Bighorn Solar Class B, LLC (49.97%)b Bighorn Solar Construction, LLC (49.97%)b Calle 14, No 781, Piso 2, Oficina 3, Ciudad de La Plata, Provincia de Buenos Aires, Argentina Saganer Straße 31, 90475 Nürnberg, Germany Saganer Straße 31, 90475 Nürnberg, Germany Via Giacomo Leopardi 7, CAP 20123, Milan, Italy 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 286 bp Annual Report and Form 20-F 2020 Financial statements 14. Related undertakings of the group – continued Bighorn Solar Holdings 1, LLC (49.97%)b Bighorn Solar Holdings 2, LLC (49.97%)b Bighorn Solar Holdings, LLC (49.97%)b Billund Refuelling I/S (50.00%) Birch Solar 1, LLC (49.97%)b Blackbear Alabama Solar 1, LLC (49.97%)b Blackbear Alabama Solar Land Holdings, LLC (49.97%)b Blendcor (Pty) Limited (37.50%)y Blue Marble Holdings Limited (23.58%)⍺ Blue Ocean Seismic Services Limited (23.33%)a Bodmin Solar Limited (49.97%) BP AOC Pumpstation Maatschap (50.00%)f BP Bioenergia Campina Verde Ltda. (48.27%) 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States GA Centervej 1, DK-7190, Billund, Denmark 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 135 Honshu Road, Islandview, Durban, 4052, South Africa Northgate House, 2nd Floor, Upper Borough Walls, Bath, BA1 1RG, United Kingdom 12-14 Carlton Place, Southampton, SO15 2EA, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands Rua Principal, Fazenda Recanto, Zona Rural, Caixa Postal 01, Ituiutaba, Minas Gerais, 38.300-898, Brazil BP Bioenergia Ituiutaba Ltda. (48.27%) Fazenda Recanto, Zona Rural, CEP 38.300-898, Ituiutaba, Minas Gerais, Brazil BP Bioenergia Itumbiara S.A. (48.27%) Estrada Municipal Itumbiara / Chacoeira Dourada, Fazenda Jandaia, Gleba B, Itumbiara, Goiás, 75516-126, Brazil BP Bioenergia Tropical S.A. (48.27%) Rodovia GO 410, km 51 à esquerda, Fazenda Canadá, s/n, Zona Rural, Edéia, Goiás, 75940-000, Brazil BP Bunge Bioenergia S.A. (48.27%) Avenida das Nações Unidas, nº 12.399, 4º andar, Brooklin Paulista, São Paulo, CEP 04578-000, Brazil BP Dhofar LLC (49.00%) BP Esso AOC Maatschap (22.80%)f BP Esso Pipeline Maatschap (50.00%)f BP Guangzhou Development Oil Product Co., Ltd (40.00%)b BP Petro China Jiangmen Fuels Co., Ltd. (49.00%)b BP PetroChina Petroleum Co., Ltd (49.00%)b BP Sinopec (ZheJiang) Petroleum Co., Ltd (40.00%)b BP Sinopec Marine Fuels Pte. Ltd. (50.00%) BP SPG Energy Trading Co., Ltd. (49.00%) BP West Africa Supply Limited (50.00%) BP-Husky Refining LLC (50.00%)b BP-Japan Oil Development Company Limited (50.00%)h Braendstoflageret Kobenhavns Lufthavn I/S (20.83%)f Brechin Castle Solar Limited (49.97%) Briar Creek Solar 1, LLC (49.97%)b BTC International Investment Co. (30.10%)β Burnthouse Solar Limited (49.97%) Caesar Oil Pipeline Company, LLC (39.39%)b Cairns Airport Refuelling Service Pty Ltd (33.33%) Cantera K-3 Limited Partnership (39.00%)f Canton Renewables, LLC (50.00%)b Castrol Cuba S.A. (50.00%) Castrol DongFeng Lubricant Co., Ltd (50.00%)b P.O.Box 20302/211, 20302, Oman Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands Room X2072, 2/F, No.13 Longxue Road, Longxue Island, Nansha District, Guangzhou, Guangdong, 511450, China Room A, building B , 5th floor, no. 22 Gangkou road, Jiangmen, China Room B1, 11th Floor, No.22 Gang Kou Yi Road, Peng Jiang District, Jiangmen, Guangdong Province, China F12, Hua Zhe Square Tower 1, Hang Zhou City, Zhe Jiang Province, China 112 Robinson Road, #05-01, Robinson 112, 068902, Singapore Room 8309, Floor 3, Yufanghailian Office Building, No. 1 Indian Ocean Road, West Coast Comprehensive Bonded Area, Qingdao Division of the PRC (Shandong) , China Number 1, Rehoboth Place, Dade Street, North Labone Estates, Accra, Accra Metropolitan, Greater Accra, P. O. BOX CT3278, Ghana Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom Københavns, Lufthavn, 2770 Kastrup, Denmark 48-50 Sackville Street, Port of Spain, Trinidad and Tobago 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Company Matters Pty Ltd, Level 12, 680 George Street, Sydney NSW 2000, Australia 6400 Shafer Ct., Suite 400, Rosemont IL 60018-4927, United States 30600 Telegraph Road, Suite 2345, Bingham Farms MI 48025, United States Calle 6 No 319, esq 5ta. Ave., Miramar, Playa, La Habana, Cuba C1/C2-1, C1/C2-2, 1-6F, No. C1/C2 building, No.107 Huazhong Electronics Industry Park, Fangcao 2 Road, Wuhan Economic and Technological Development Zone, Wuhan, Hubei Province, China Cedar Creek II Holdings LLC (50.00%)b Cedar Creek II, LLC (50.00%)b Cefari RNG OKC, LLC (50.00%)b Cekisan Depolama Hizmetleri Limited Sirketi (35.00%) Central African Petroleum Refineries (Pvt) Ltd (20.75%) CERF Shelby, LLC (50.00%)b Chicap Pipe Line Company (56.17%) Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 1560 Broadway, Suite 2090, Denver, Colorado, 80202 Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Liman Mah. 60 Sk., Çekisan-İdari Bina sit. No:25 A/1, Konyaaltı, Antalya, Turkey Block 1Tendeseka Office Park, Samora Machel Av/Renfrew Road, Harare, Zimbabwe 800 S. Gay Street, Suite 2021, Knoxville TN 37929, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States China Aviation Oil (Singapore) Corporation Ltd (20.03%) 8 Temasek Boulevard #31-02, Suntec City Tower 3, Singapore 038988, Singapore Chittering Solar Limited (49.97%) Clean Eagle RNG, LLC (50.00%)b Cleopatra Gas Gathering Company, LLC (37.28%)b CNAF Air BP General Aviation Fuel Company Limited (49.00%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 11/F, Building No.2, No. 32 Lingang Road Section One, Xihang Port Street, Shuangliu District, Chengdu, Sichuan Province, China Coastal Oil Logistics Limited (25.00%) 10th Floor, The Bayleys Building, Cnr Brandon St and Lambton Quay, Wellington, 6011, New Zealand Compatibleglobe, Lda (49.97%) Rua Sousa Martins, no 10, 1050 218, Lisboa, Portugal The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 287 14. Related undertakings of the group – continued Concessionaria Stalvedro SA (50.00%) Continental Divide Solar 1, LLC (49.97%)b Continental Divide Solar II, LLC (49.97%)b Continental Divide Solar Land Holdings, LLC (49.97%)b Cottontail Solar 1, LLC (49.97%)b Cottontail Solar 2, LLC (49.97%)b Cottontail Solar 3, LLC (49.97%)b Cottontail Solar 4, LLC (49.97%)b Cottontail Solar 5, LLC (49.97%)b Cottontail Solar 6, LLC (49.97%)b Cottontail Solar 7, LLC (49.97%)b CSG Convenience Service GmbH (24.80%) Danish Refuelling Services I/S (50.00%)f Danish Tankage Services I/S (50.00%)f Dapsun - Investimentos e Consultoria, LDA. (24.99%) San Gottardo Sud, 6780, Airolo, Switzerland 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Wittener Straße 45, 44789 Bochum, Germany Kastrup Lufthavn, 2770 Kastrup, Denmark Kastrup Lufthavn, 2770 Kastrup, Denmark Rua Júlio Dinis, n.º 247, 6.º, E-1, Edifício Mota Galiza, Parish of Lordelo do Ouro and Massarelos, 4050-324, Porto, Portugal Dinarel S.A. (20.00%) La Cumparsita 1373, piso 4°, Montevideo, Uruguay Donoma Power Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom DOPARK GmbH (25.00%) Dusseldorf Fuelling Services GbR (33.00%)f El Temsah Petroleum Company "PETROTEMSAH" (25.00%) Elk Hill Solar 1, LLC (49.97%)b Elk Hill Solar 2, LLC (49.97%)b Elk Hill Solar 2 Holdings, LLC (49.97%)b Elm Branch Solar 1, LLC (49.97%)b EMDAD Aviation Fuel Storage FZCO (33.33%) Westfalendamm 166, 44141 Dortmund, Germany Sportallee 6, 22335 Hamburg, Germany 5 El Mokhayam El Daiem St, 6th Sector, Nasr City, Egypt 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States P.O.Box 261781, Dubai, United Arab Emirates Emoil Storage Company FZCO (20.00%) Plot No. B003R04, Box No. 9400, Dubai, United Arab Emirates, Dubai, United Arab Emirates EMSEP S.A. de C.V. (50.00%) Endymion Oil Pipeline Company, LLC (45.72%)b Energías Renovables de Ixion, SL (49.97%) Energy Emerging Investments, LLC (50.00%)b Entrepot petrolier de Chambery (32.00%) Av. Paseo de la Reforma 505 piso 32, Colonia Cuauhtémoc, Delegación Cuauhtémoc (06500), CDMX, Mexico Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Calle Alcala numero 63, 28014, Madrid, Spain 2711 Centerville Road, Suite 400, Wilmington DE 19808, United States 562 Avenue du Parc de l'Ile, 92000, NANTERRE, France Entrepôt Pétrolier de Puget sur Argens - EPPA (58.25%) Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe, Cergy Pontoise, France Erdol-Lagergesellschaft m.b.H. (23.00%)b Etzel-Kavernenbetriebsgesellschaft mbH & Co. KG (33.33%)f Etzel-Kavernenbetriebs-Verwaltungsgesellschaft mbH (33.33%) Eversource Capital Private Limited (24.99%) Radlpaßstraße 6, 8502 Lannach, Austria Bertrand-Russell-Straße 3, 22761 Hamburg, Germany Bertrand-Russell-Straße 3, 22761 Hamburg, Germany One Indiabulls Center, 16th Floor, Tower 2A, Senapati Bapat Marg, Mumbai City, Maharashtra, Mumbai, 400013, India EverSource Management Holdings (24.99%) 3rd Floor, Standard Chartered Tower, Bank Street, 19 Cybercity, Ebene, 72201, Mauritius Ffos Las Solar Developments Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Field Services Enterprise S.A. (50.00%) Av. Leandro N. Alem 1180, piso 11°, Buenos Aires, Argentina Fip Verwaltungs GmbH (50.00%) Flat Ridge 2 Wind Energy LLC (50.00%)b Flat Ridge 2 Wind Holdings LLC (50.00%)b Flughafen Hannover Pipeline Verwaltungsgesellschaft mbH (50.00%) Flughafen Hannover Pipelinegesellschaft mbH & Co. KG (50.00%)f Fly Victor Ltd (26.23%) Flytanking AS (50.00%) Foreseer Ltd (25.00%) Fowler II Holdings LLC (50.00%)b Fowler Ridge II Wind Farm LLC (50.00%)b Free Power for Schools 13 Limited (49.97%) Rheinstraße 36, 49090 Osnabrück, Germany Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Überseeallee 1, 20457, Hamburg, Hamburg, Germany Überseeallee 1, 20457, Hamburg, Hamburg, Germany 60 Sloane Avenue, London, SW3 3XB, United Kingdom Postboks 36, Stjordal, NO-7501, Norway 121A Thoday Street, Cambridge , Cambridgeshire, CB1 3AT , United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Free Power for Schools 14 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Free Power for Schools 15 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Free Power for Schools 17 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 288 bp Annual Report and Form 20-F 2020 Financial statements 14. Related undertakings of the group – continued Free Power for Schools 19 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Free Power for Schools 4 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Free Power for Schools 5 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Free Power for Schools 6 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Free Power for Schools 7 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Freetricity Central June Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Freetricity Commercial June Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom FreeWire Technologies, Inc. (28.18%) Fresh-Serve Bakeries LLC (44.27%)b Fuelling Aviation Service - FAS (50.00%)b Fuerzas Energéticas del Sur de Europa IV, SL (49.97%) 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Corporation Service Company, 421 West Main Street, Frankfort KY 40601, United States 3 Rue des Vignes, Aéroport Roissy Charles de Gaulle, 93290, TREMBLAY EN FRANCE, France Calle Alcala numero 63, 28014, Madrid, Spain Fuerzas Energéticas del Sur de Europa XIX, SL (49.97%) Calle Alcala numero 63, 28014, Madrid, Spain Fuerzas Energéticas del Sur de Europa, S.L. (49.97%) Calle Alcala numero 63, 28014, Madrid, Spain Fundación para la Eficiencia Energética de la Comunidad Valenciana (33.33%)b Calle Lituania nº 10, Castellón de la Plana, Spain Gardermeon Fuelling Services AS (33.33%) Postboks 133, Gardermoen, NO-2061, Norway Gas Natural Acu Comercializadora de Energia Ltda. (50.00%) Rua do Russel 804, 5th floor, Gloria, Rio de Janeiro, Brazil Gas Natural Acu S.A. (30.00%) Praia do Flamengo 66, 13th and 14th floors, Block A, Flamengo, Rio de Janeiro, Brazil Gas Natural Infraestrutura S.A. (27.96%) Rua do Russel 804, 5th floor, Gloria, Rio de Janeiro, Brazil Gemalsur S.A. (50.00%) Georgian Pipeline Company (30.37%)z Gezamenlijke Tankdienst Schiphol B.V. (50.00%) GISSCO S.A. (50.00%) Glade CD Solar Holdings, LLC (49.97%)b Glade Solar Class B, LLC (49.97%)b Glade Solar Construction Holdings, LLC (49.97%)b Glade Solar Construction, LLC (49.97%)b Glade Solar Holdings 1, LLC (49.97%)b Glade Solar Holdings 2, LLC (49.97%)b Glade Solar Holdings, LLC (24.99%)b Glade Solar Land Holdings, LLC (49.97%)b Gnowee Power Limited (49.97%) Goshen Phase II LLC (50.00%)b Gothenburgh Fuelling Company AB (GFC) (33.33%) Great Ropemaker Partnership (G.P.) Limited (50.00%)y Great Ropemaker Property (Nominee 1) Limited (50.00%) Colonia 810, Oficina 403, Montevideo, Uruguay 190 Elgin Avenue, George Town, Grand Cayman , KY1-9005, Cayman Islands Anchoragelaan 6, 1118LD Luchthaven Schiphol, Netherlands 2,Vouliagmenis Ave & Papaflessa, 16777 Elliniko, Athens, Attika, Greece 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Box 2154, 438 14, LANDVETTER, Sweden 33 Cavendish Square, London, W1G 0PW, United Kingdom 33 Cavendish Square, London, W1G 0PW, United Kingdom Great Ropemaker Property (Nominee 2) Limited (50.00%) 33 Cavendish Square, London, W1G 0PW, United Kingdom Great Ropemaker Property Limited (50.00%) 33 Cavendish Square, London, W1G 0PW, United Kingdom Green Growth Feeder Fund Pte. Ltd (24.99%) 163 Penang Road, #08-01, Winsland House II, 238463, Singapore Groupement Pétrolier de Saint Pierre des Corps - GPSPC (20.00%)b Guangdong Dapeng LNG Company Limited (30.00%)b GVÖ Gebinde-Verwertungsgesellschaft der Mineralölwirtschaft mbH (21.00%) H7 Energy Limited (49.97%) Hamburg Tank Service (HTS) GbR (33.00%)f Happy Solar 1, LLC (49.97%)b Hebei Dongming Yinglun Petroleum Co., Ltd. (49.00%)b Heinrich Fip GmbH & Co. KG (50.00%)f Heliex Power Limited (32.40%)a Henan Dongming Yinglun Petroleum Co., Ltd. (49.00%)b HFS Hamburg Fuelling Services GbR (50.00%)f Hiergeist Heizolhandel GmbH & Co. KG (50.00%)f Hokchi Energy S.A. de C.V. (50.00%) Hokchi Iberica S.L. (50.00%) 150 Avenue Yves Farge, 37700, SAINT PIERRE DES CORPS, France 10-11/FTime Finance Center, No.4001 Shennan Dadao, Futian Street, Futian District, Shenzhen, Guangdong Province, China Steindamm 55, 20099 Hamburg, Germany 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Sportallee 6, 22335 Hamburg, Germany 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States South Side, Floor 10, Insurance Industrial Park, No. 672, Chengjiao Street,, Qiaoxi District, Shijiazhuang City, Hebei Province, China Rheinstraße 36, 49090 Osnabrück, Germany Kelvin Building , Bramah Avenue , East Kilbride, Glasgow , Scotland, G75 0RD, United Kingdom Room 124, Longhu Enterprise Service Center, Floor 1, Building No. 10, Courtyard No.1, Long Xing Jia Yuan, No. 66, Longhu Outer Ring Road, Zhengdong New District, Zhenzhou City Sportallee 6, 22335 Hamburg, Germany Grubenweg 4, 83666 Waakirchen-Marienstein, Germany Torre A, piso 4, oficina 402, Calzada Legaria 549, Colonia 10 de Abril, Delegación Miguel Hidalgo, Ciudad de Mexico, C. P. 11250, Mexico Campus Empresarial Arbea - Edificio No 1, Carretera Fuencarral a Alcobendas (M-603), km 3.8, Alcobendas, Madrid, Spain The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 289 14. Related undertakings of the group – continued Howbery Solar Park Limited (49.97%) Impact Solar 1, LLC (49.97%)b Impact Solar Class B, LLC (49.97%)b Impact Solar Construction, LLC (49.97%)b Impact Solar Holdings 1, LLC (49.97%)b Impact Solar Holdings 2, LLC (49.97%)b Impact Solar Holdings, LLC (49.97%)b Implantación de Fuentes Energéticas de Origen Renovable, SL (49.97%) In Salah Gas Limited (25.50%)y In Salah Gas Services Limited (25.50%)y India Gas Solutions Private Limited (50.00%) Jamaica Aircraft Refuelling Services Limited (51.00%)h Johnson Corner Solar I, LLC (24.99%)b Kala Power Limited (49.97%) Klaus Köhn GmbH (50.00%) Köhn & Plambeck GmbH & Co. KG (50.00%)f Kurt Ammenn GmbH & Co. KG (50.00%)f LCA Aviation Fuelling Systems Limited (35.00%) Lensky Nefteprovod Limited Liability Company (20.00%) LFS Langenhagen Fuelling Services GbR (50.00%)f Lightning Systems, Inc. (35.30%)a Lightsource Asset Holdings (Australia) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Calle Alcala numero 63, 28014, Madrid, Spain IFC 5, St Helier, Jersey, JE1 1ST, Jersey IFC 5, St Helier, Jersey, JE1 1ST, Jersey Unit Nos.71 & 737th Floor, Maker Maxity, 2nd North Avenue, Bandra - Kurla Complex, Bandra (East), Mumbai 400 051, Maharashtra, India PCJ Building36 Trafalgar Road, Kingston 10, Jamaica Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom An der Braker Bahn 22, 26122 Oldenburg, Germany An der Braker Bahn 22, 26122 Oldenburg, Germany Luisenstraße 5 a, 26382 Wilhelmshaven, Germany 90 Archiepiskopou str, Dromolaxia – Meneou, 7020 Larnaca , Cyprus Pervomayskaya str, 32a, Republic of Saha (Yakytya), 678144, city of Lensk, Lenskiy region, Russian Federation Sportallee 6, 22335 Hamburg, Germany 160 Greentree Drive, Suite 101, Dover, County of Kent DE 19904, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Asset Holdings (Europe) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Asset Holdings (Spain) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Asset Holdings (UK) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Asset Holdings (USA) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Asset Holdings (Vendimia I) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Asset Holdings (Vendimia II) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Asset Holdings 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Asset Holdings 2 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Asset Holdings 3 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Asset Management Australia Pty Ltd (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia Lightsource Asset Management Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Australia FinCo Holdings Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Australia SPV 1 Pty Limited (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia Lightsource Australia SPV 2 Pty Limited (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia Lightsource Australia SPV 3 Pty Limited (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia Lightsource Australia SPV 4 Pty Limited (49.97%) Lightsource Beacon 2, LLC (49.97%)b Lightsource Beacon Holdings, LLC (49.97%)b Lightsource Beacon, LLC (49.97%)b Lightsource Bodegas 2 Limited (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Bodegas 3 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Bodegas 4 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Bodegas Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Bom Lugar IV Geração de Energia Ltda (49.97%) Fazenda Terra Nova, located at Rod. Padre Cicero (CE 153), S/N, KM 58, Lima Campos, Ico, Ceara, 63.435-000, Brazil Lightsource Bom Lugar IX Geração de Energia Ltda. (49.97%) Fazenda Terra Nova, located at Rod. Padre Cicero (CE 153), S/N, KM 58, Lima Campos, Ico, Ceara, 63.435-000, Brazil Lightsource Bom Lugar V Geração de Energia Ltda. (49.97%) Fazenda Terra Nova, located at Rod. Padre Cicero (CE 153), S/N, KM 58, Lima Campos, Ico, Ceara, 63.435-000, Brazil Lightsource Bom Lugar VI Geração de Energia Ltda. (49.97%) Fazenda Terra Nova, located at Rod. Padre Cicero (CE 153), S/N, KM 58, Lima Campos, Ico, Ceara, 63.435-000, Brazil Lightsource Bom Lugar VII Geração de Energia Ltda. (49.97%) Fazenda Terra Nova, located at Rod. Padre Cicero (CE 153), S/N, KM 58, Lima Campos, Ico, Ceara, 63.435-000, Brazil Lightsource Bom Lugar VIII Geração de Energia Ltda. (49.97%) Fazenda Terra Nova, located at Rod. Padre Cicero (CE 153), S/N, KM 58, Lima Campos, Ico, Ceara, 63.435-000, Brazil The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 290 bp Annual Report and Form 20-F 2020 14. Related undertakings of the group – continued Lightsource BP Hassan Allam Developments for Renewable Energy S.A.E (24.99%) 14 Kamal El Tawil ST, Zamalek, Cairo, Egypt Lightsource BP Hassan Allam Holdings B.V. (24.99%) Jan van Goyenkade 8, 1075HP, Amsterdam, Netherlands Lightsource BP Renewable Energy Investments Limited (49.97%)γ 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Brasil Energia Renovável Ltda (49.97%) Avenida Bernardino de Campos 98, 12th floor, room 38, suite A, Paraiso, Sao Paulo, 04004-040, Brazil Lightsource Brasil Energia Renovável Particições S.A. (49.97%) Avenida Bernardino de Campos 98, 12th floor, room 38, suite A, Paraiso, Sao Paulo, 04004-040, Brazil Financial statements Lightsource Brazil Holdings 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Lightsource Brazil Holdings 2 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Commercial Rooftops (Buyback) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Commercial Rooftops Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Construction Management Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Development Services Australia Pty Ltd (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia Lightsource Development Services Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Egypt Holdings Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Lightsource Elk Hill 2 Solar Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Elk Hill Solar 2 Holdings Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Europe Asset Management, SL (49.97%) Calle Suero de Quinones, Numero 34-36, 28002, Madrid, Spain Lightsource Finance 55 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Lightsource Finca 2 Limited (49.97%) Lightsource Finca 3 Limited (49.97%) Lightsource Finca Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Grace 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Grace 2 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Grace 3 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Greece SPV 1 Single Member S.A. (49.97%) 280 Kifissias Ave, 152 32 Halandri, Anthens, Greece Lightsource Holdings 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Holdings 2 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Holdings 3 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Iberia Project Holdings Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Impact 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Impact 2 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource India Holdings (Mauritius) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource India Holdings Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource India Investments (UK) Limited (49.97%) Lightsource India Limited (25.49%)h Lightsource India Maharashtra 1 Holdings Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource India Maharashtra 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Kingfisher Holdings Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Kingpin 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Kingpin 2 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Kingpin 3 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Labs 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Lightsource Labs Australia Pty Limited (49.97%) C/- Baker McKenzie, Level 19, 181 William Street, Melbourne VIC 3000, Australia Lightsource Labs Holdings Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Lightsource Labs Limited (49.97%) Trinity House, Charleston Road, Ranelagh, Dublin 6, D06C8X4, Ireland Lightsource Largescale Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Manzanilla Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Midscale Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Milagres I Geração de Energia Ltda. (49.97%) Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil Lightsource Milagres II Geração de Energia Ltda. (49.97%) Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil Lightsource Milagres III Geração de Energia Ltda. (49.97%) Lightsource Milagres IV Geração de Energia Ltda. (49.97%) Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil Lightsource Milagres V Geração de Energia Ltda. (49.97%) Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil Lightsource Nala Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 291 14. Related undertakings of the group – continued Lightsource Operations 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Operations 2 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Operations 3 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Operations Services Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Poland Holdings (UK) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Property 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Property 2 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Property Investment Holdings Ltd (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Property Investment Management (LPIM) LLP (49.97%)f 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Property Investments 1 Ltd (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Pumbaa Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Radiate 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Radiate 2 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Raindrop Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Renewable Energy (Australia) Pty Ltd (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia Lightsource Renewable Energy (India) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Renewable Energy (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource Renewable Energy Asset Holdings 1, LLC (49.97%)b Lightsource Renewable Energy Asset Holdings, LLC (49.97%)b Lightsource Renewable Energy Asset Management Holdings, LLC (49.97%)b Lightsource Renewable Energy Asset Management, LLC (49.97%)b Lightsource Renewable Energy Australia Holdings Limited (49.97%) 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Renewable Energy Cariñena S.L. (49.97%) Calle Alcala numero 63, 28014, Madrid, Spain Lightsource Renewable Energy Development, LLC (49.97%)b Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States Lightsource Renewable Energy Garnacha, S.L. (49.97%) Calle Alcala numero 63, 28014, Madrid, Spain Lightsource Renewable Energy Greece Holdings (UK) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Renewable Energy Holdings Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Renewable Energy Iberia Holdings Limited (49.97%) Lightsource Renewable Energy India Assets Limited (49.97%) Lightsource Renewable Energy India Holdings Limited (49.97%) Lightsource Renewable Energy India Opco Private Limited (49.97%) Lightsource Renewable Energy India Projects Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 815-816 International Trade Tower, Nehru Place, New Delhi 110019, Delhi, India 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Renewable Energy Ireland Limited (49.97%) Trinity House, Charleston Road, Ranelagh, Dublin 6, D06C8X4, Ireland Lightsource Renewable Energy Italy Development s.r.l. (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Lightsource Renewable Energy Italy Finco s.r.l. (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Lightsource Renewable Energy Italy Holdings Limited (49.97%) Lightsource Renewable Energy Italy Holdings s.r.l. (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Lightsource Renewable Energy Italy SPV 1 s.r.l. (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Lightsource Renewable Energy Italy SPV 10 s.r.l. (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Lightsource Renewable Energy Italy SPV 11 S.r.l (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Lightsource Renewable Energy Italy SPV 2 s.r.l. (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Lightsource Renewable Energy Italy SPV 3 s.r.l. (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Lightsource Renewable Energy Italy SPV 4 s.r.l. (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Lightsource Renewable Energy Italy SPV 6 s.r.l. (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Lightsource Renewable Energy Italy SPV 7 s.r.l. (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Lightsource Renewable Energy Italy SPV 8 s.r.l. (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 292 bp Annual Report and Form 20-F 2020 Financial statements 14. Related undertakings of the group – continued Lightsource Renewable Energy Italy SPV 9 s.r.l. (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Lightsource Renewable Energy Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Renewable Energy Management, LLC (49.97%)b Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States Lightsource Renewable Energy Netherlands Development B.V. (49.97%) Prins Bernhardplein 200 1097JB, Amsterdam, Netherlands Lightsource Renewable Energy Netherlands Holdings B.V. (49.97%) Prins Bernhardplein 200 1097JB, Amsterdam, Netherlands Lightsource Renewable Energy Netherlands Holdings Limited (49.97%) Lightsource Renewable Energy Operations, LLC (49.97%)b Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States 7th Floor 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Renewable Energy Portugal (HoldCo), Lda (49.97%) Lightsource Renewable Energy Portugal Holdings Limited (49.97%) Lightsource Renewable Energy Services Holdings, LLC (49.97%)b Rua Sousa Martins, no 10, 1050 218, Lisboa, Portugal 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Lightsource Renewable Energy Services, Inc. (49.97%) 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Lightsource Renewable Energy Spain Development, SL (49.97%) Lightsource Renewable Energy Spain Holdings, SL (49.97%) Calle Alcala numero 63, 28014, Madrid, Spain Calle Alcala numero 63, 28014, Madrid, Spain Lightsource Renewable Energy Spain SPV 1, SL (49.97%) Calle Alcala numero 63, 28014, Madrid, Spain Lightsource Renewable Energy Trading, LLC (49.97%)b Lightsource Renewable Energy Trading, SL (49.97%) Lightsource Renewable Energy US Assets, LLC (49.97%)b 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Lightsource Renewable Energy US, LLC (49.97%)b Lightsource Renewable Global Development Limited (49.97%) 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom C/Pradillo 5, Bajo Exterior Derecha, 28002, Madrid, Spain Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States Lightsource Renewable Services Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Lightsource Renewable UK Development Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Residential NI Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource Residential Rooftops (Buyback) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Residential Rooftops (PPA) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Residential Rooftops Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Simba Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Singapore Renewables Holdings Private Limited (49.97%) Lightsource Singapore Renewables Private Limited (49.97%) 8 Marina Boulevard, #05-02, Marina Bay Financial Centre, 018981, Singapore 8 Marina Boulevard, #05-02, Marina Bay Financial Centre, 018981, Singapore Lightsource Spain O&M, SL (49.97%) Calle Suero de Quinones, Numero 34-36, 28002, Madrid, Spain Lightsource SPV 10 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 100 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 101 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 105 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 106 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 108 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 109 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 112 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 114 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 115 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 116 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 118 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 123 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 126 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 127 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 128 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 130 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 133 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 293 14. Related undertakings of the group – continued Lightsource SPV 135 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 138 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 140 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 142 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 143 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 145 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 149 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 151 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 152 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 154 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 155 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 156 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 160 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 162 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 166 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 167 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 169 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 170 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 171 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 174 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 175 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 176 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 179 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 18 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 180 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 182 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 183 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 184 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 185 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 187 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 189 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 19 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 191 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 192 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 196 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 199 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 20 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 200 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 201 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 202 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 203 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 204 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 205 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 206 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 212 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 213 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 214 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 215 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 216 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 217 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 221 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 222 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 223 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 224 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 232 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 233 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 234 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 235 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 236 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 294 bp Annual Report and Form 20-F 2020 Financial statements 14. Related undertakings of the group – continued Lightsource SPV 239 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 242 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 243 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 244 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 245 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 246 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 247 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 248 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 249 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 25 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 251 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 252 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 253 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 254 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 258 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 259 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 26 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 261 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 262 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 263 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 264 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 265 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 266 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 267 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 268 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 269 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 270 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 271 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 272 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 273 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 274 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 275 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 276 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 277 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 278 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 279 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 280 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 281 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 282 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 283 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 284 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 285 (NI) Limited (49.97%) Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom Lightsource SPV 286 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource SPV 29 Limited (49.97%) Lightsource SPV 32 Limited (49.97%) Lightsource SPV 35 Limited (49.97%) Lightsource SPV 39 Limited (49.97%) Lightsource SPV 40 Limited (49.97%) Lightsource SPV 41 Limited (49.97%) Lightsource SPV 42 Limited (49.97%) Lightsource SPV 44 Limited (49.97%) Lightsource SPV 47 Limited (49.97%) Lightsource SPV 49 Limited (49.97%) Lightsource SPV 5 Limited (49.97%) Lightsource SPV 50 Limited (49.97%) Lightsource SPV 54 Limited (49.97%) Lightsource SPV 56 Limited (49.97%) Lightsource SPV 60 Limited (49.97%) Lightsource SPV 69 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 295 14. Related undertakings of the group – continued Lightsource SPV 73 Limited (49.97%) Lightsource SPV 74 Limited (49.97%) Lightsource SPV 75 Limited (49.97%) Lightsource SPV 76 Limited (49.97%) Lightsource SPV 78 Limited (49.97%) Lightsource SPV 79 Limited (49.97%) Lightsource SPV 8 Limited (49.97%) Lightsource SPV 88 Limited (49.97%) Lightsource SPV 91 Limited (49.97%) Lightsource SPV 92 Limited (49.97%) Lightsource SPV 98 Limited (49.97%) Lightsource Timon Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Trading Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Trinidad Holdings (UK) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Viking 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Viking 2 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Xenium 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Lightsource Xenium 2 Limited (49.97%) Limited Liability Company TYNGD (20.00%)b Limited Liability Company Yermak Neftegaz (49.00%)b LL Property Services 2 Limited (49.97%) LL Property Services Limited (49.97%) LLC "Kharampurneftegaz" (49.00%)b Lora Solar Limited (49.97%) Lotos - Air BP Polska Spółka z ograniczoną odpowiedzialnością (50.00%) LREHL Renewables India SPV 1 Private Limited (25.49%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Pervomayskaya street, 32A, 678144, Lensk, Sakha (Yakutiya) Republic, Russian Federation Kosmodamianskaya nab, 52/3, 115035, Moscow, Russian Federation 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 629830 Yamalo-Nenetskiy Anatomy Region, city of Gubkinskiy, Russian Federation 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Grunwaldzka 472B, 80-309, Gdansk, Poland 815-816 International Trade Tower, Nehru Place, New Delhi, 110019, India LS Australia FinCo 1 Pty Limited (49.97%) C/- Baker McKenzie, Level 19, 181 William Street, Melbourne VIC 3000, Australia LS Australia FinCo 2 Pty Limited (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia LS Australia HoldCo1 Pty Ltd (49.97%) LSBP NE Development, LLC (49.97%)b Maasvlakte Europoort Pipeline Maatschap (50.00%)f Maatschap Europoort Terminal (50.00%)f Mach Monument Aviation Fuelling Co. Ltd. (70.00%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands Moezelweg 101, 3198LS Europoort, Rotterdam, Netherlands Naz City, Building J, Suite 10 Erbil, Iraq Malmo Fuelling Services AB (33.33%) Box 22, SE 230 32 Malmö-Sturup, Sweden Manchester Airport Storage and Hydrant Company Limited (25.00%) One Bartholomew Close , London, EC1A 7BL, United Kingdom Manor Farm (Solar Power) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Manpetrol S.A. (50.00%) Francisco Behr 20, Barrio Pueyrredon, Comodoro Rivadavia, Provincia del Chubut, Argentina Maputo International Airport Fuelling Services (MIAFS) Limitada (50.00%)b Masana Employee Share Trust No. 1 (37.88%)b Maverick Solar Class B, LLC (49.97%)b Maverick Solar Construction, LLC (49.97%)b Maverick Solar Holdings 1, LLC (49.97%)b Maverick Solar Holdings 2, LLC (49.97%)b Maverick Solar Holdings, LLC (49.97%)b Mavrix, LLC (50.00%)b McFall Fuel Limited (49.00%) Mediteranean Gas Co. "MEDGAS" (25.00%) Mehoopany Wind Energy LLC (50.00%)b Mehoopany Wind Holdings LLC (50.00%)b Meri Power Limited (49.97%) Middle East Lubricants Company LLC (29.33%) Mobene Beteiligungs GmbH & Co. KG (50.00%)f Mobene Beteiligungs Verwaltungs GmbH (50.00%) Mobene GmbH & Co. KG (50.00%)f Mobene Verwaltungs-GmbH (50.00%) Praca Dos Trabalhadores, Nr 09, Distrito Urbano 1, Maputo, Mozambique 199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States KPMG, 247 Cameron Road, Tauranga, 3110, New Zealand 5 El Mokhayam El Daiem St, 6th Sector, Nasr City, Egypt Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 6th Flr City Tower, 2 - Sheikh Zayed Road, PO Box 1699, Dubai, United Arab Emirates Spaldingstraße 64, 20097 Hamburg, Germany Spaldingstraße 64, 20097 Hamburg, Germany Spaldingstraße 64, 20097 Hamburg, Germany Spaldingstraße 64, 20097 Hamburg, Germany Modelos Energéticos Sostenibles, S.L. (49.97%) Calle Alcala numero 63, 28014, Madrid, Spain MTS Francis Court Solar Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 296 bp Annual Report and Form 20-F 2020 Financial statements 14. Related undertakings of the group – continued MTS Trefinnick Solar Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom N.V. Rotterdam-Rijn-Pijpleiding Maatschappij (RRP) (44.40%) Butaanweg 215, NL-3196 KC Vondelingenplaat, Rotterdam, 3045, Havennummer , Netherlands Natural Gas Vehicles Company "NGVC" (40.00%) 85 El Nasr Road, Cairo, Cairo, Egypt New Zealand Oil Services Limited (50.00%) Level 3, 139 The Terrace, Wellington, 6011, New Zealand Nextpower Trevemper Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom NFX Combustíveis Marítimos Ltda. (50.00%) Avenida Atlântica, no. 1.130, 2nd floor (part), Copacabana, Rio de Janeiro, RJ, 22021-000, Brazil Nima Power Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Nord-West Oelleitung GmbH (59.33%) Zum Ölhafen 207, 26384 Wilhelmshaven, Germany Ocwen Energy Pty Ltd (49.50%) Olympic Pipe Line Company LLC (70.00%)b Oslo Lufthaven Tankanlegg AS (33.33%) PAE E & P Bolivia Limited (50.00%) PAE Oil & Gas Bolivia Ltda. (50.00%) GTH Accounting Group Pty Ltd '2', 1A Kitchener Street, Toowoomba QLD 4350, Australia Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Postboks 134, Gardermoen, NO-2061, Norway Trinity Place Annex, Corner of Frederick & Shirley Streets, P.O. Box N-4805, Nassau, Bahamas Cuarto anillo, Avda. Ovidio Barbery N° 4200, Edificio Torre , e/ Jaime Román y Victor Pinto, Equipetrol Norte, Santa Cruz de la Sierra, Bolivia Palk Power Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Pan American Energy Chile Limitada (50.00%) Pan American Energy do Brasil Ltda. (50.00%)b Pan American Energy Group, S.L. (50.00%)y Nueva de Lyon Nº 145, piso 12, oficina 1203, Edificio Costa, Santiago de Chile, Chile Rua Manoel da Nóbrega n°1280, 10° andar, Sao Paulo, Sao Paulo, 04001-902, Brazil Arbea Campus Empresarial, Edifico 1. Ctra de Fuencarral a Alcobendas, M603, KM 3,8 28108 Alcobendas, MADRID, SPAIN Pan American Energy Holdings S.A. (50.00%) Colonia 810, Oficina 403, Montevideo, Uruguay Pan American Energy Iberica S.L. (50.00%) Campus Empresarial Arbea - Edificio Nº 1, Carretera Fuencarral a Alcobendas (M-603), Km 3,8., Alcobendas, Madrid, Spain Pan American Energy Investments Ltd. (50.00%) Trinity Place Annex, Corner of Frederick & Shirley Streets, P.O. Box N-4805, Nassau, Bahamas Pan American Energy Uruguay S.A. (50.00%) Pan American Energy US LLC (51.00%)b Pan American Energy, S.L. (50.00%)b Colonia 810, Oficina 403, Montevideo, Uruguay Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Arbea Campus Empresarial, Edifico 1. Ctra de Fuencarral a Alcobendas, M603, KM 3,8 28108 Alcobendas, MADRID, SPAIN Pan American Fueguina S.A. (50.00%) O´Higgins N° 194, Rio Grande, Argentina Pan American Sur S.A. (50.00%) O´Higgins N° 194, Rio Grande, Argentina Parque Eolico Del Sur S.A. (27.50%) Peninsular Aviation Services Company Limited (50.00%)i Pentland Aviation Fuelling Services Limited (50.00%)c Petrostock SA (50.00%) Av. Leandro N. Alem 1180, piso 11°, Buenos Aires, Argentina P O Box 6369, Jeddah21442, Saudi Arabia Suite 44 (C/O Best4Business Accountants), Beaufort Court, Admirals Way, London, E14 9XL, United Kingdom route de Pré-Bois 2, 1214, Vernier, Switzerland Pharaonic Petroleum Company "PhPC" (25.00%) 70/72 Road 200, Maadi, Cairo, Egypt Pollon s.r.l. (32.48%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy Pont Andrew Limited (49.97%) POPLAR SOLAR 1, LLC (49.97%)b Porteiras Geração de Energia Ltda. (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Estrada BR 135, número S/N, KM 250, bairro / distrito Angico de Minas, município Japonvar - MG, CEP 39335-000, Brazil Proteus Oil Pipeline Company, LLC (45.72%)b PT Petro Storindo Energi (30.00%) Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Bakrie Tower 17th Floor, Rasuna Epicentrum Complex Jl. H.R Rasuna Said, Jakarta, 12940, Indonesia PT. Dirgantara Petroindo Raya (49.90%) Wisma AKR, 25th floor, Jalan Panjang No.5, Kebon Jeruk, , Jakarta Barat, 11530, Indonesia Rahamat Petroleum Company (PETRORAHAMAT) (50.00%) 70/72 Road 200, Maadi, Cairo, Egypt Raststaette Glarnerland AG, Niederurnen (20.00%) Nideracher 1, 8867, Niederurnen, Switzerland RD Petroleum Limited (49.00%) 399 Moray Place, Dunedin, 9016, New Zealand Reliance BP Mobility Limited (49.00%) Resolution Partners LLP (68.00%)f Rhein-Main-Rohrleitungstransportgesellschaft mbH (35.00%) 3rd Floor, Maker Chambers IV, 222, Nariman Point, Mumbai, 400 021, India 1675 Broadway, Denver CO 80202, United States Godorfer Hauptstraße 186, 50997 Köln, Germany RMF Holdings Limited (49.00%) KPMG, 247 Cameron Road, Tauranga, 3110, New Zealand Romanian Fuelling Services S.R.L. (50.00%) 59 Aurel Vlaicu Street, Otopeni, Ilfov County, Romania Rosneft Oil Company (19.75%) Routex B.V. (25.00%) 26/1 Sofiyskaya Embankment, 115035, Moscow, Russian Federation, Russian Federation Strawinskylaan 1725, 1077XX Amsterdam, Netherlands S&JD Robertson North Air Limited (49.00%) 1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom SABA- Sociedade Abastecedora de Aeronaves, Lda (25.00%) Grupo Operacional de Combustiveis do Aeroporto de Lisboa, Edificio 19, 1.º Sala Saba, Lisboa, Portugal SAFCO SA (33.33%) Salzburg Fuelling GmbH (33.00%)b International airport "El. Venizelos", Athens, Greece Innsbrucker Bundesstraße 95, 5020 Salzburg, Austria The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 297 14. Related undertakings of the group – continued SAMCOL - Sociedade de Armazenamento e Manuseamento de Combustiveis Liquidos, Limitada (50.00%)b Saraco SA (20.00%) SeaPort Midstream Partners, LLC (49.00%)b Sel PV 09 Limited (49.97%) Servicios Logísticos de Combustibles de Aviación, S.L (50.00%) Parcela 729, via onze mil cento e trinta, numero cento e qua, Matola Lingamo, Mozambique route de Pré-Bois 17, 1216, Cointrin, Switzerland Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Paseo de la Castellana 278, Madrid, Spain, Spain Shakti Power Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Shandong Dongming Yinglun Petroleum Co., Ltd. (49.00%)b Sharjah Aviation Services Co. LLC (49.00%)y Sharjah Pipeline Company LLC (49.00%) Shell and BP South African Petroleum Refineries (Pty) Ltd (37.50%)h Shell Mex and B.P. Limited (40.00%)y Shenzhen Cheng Yuan Aviation Oil Company Limited (25.00%)b Room B-703, B-704, B-705, B-706, B-707, Floor 7, Block B, No.8, Luoyuan Avenue, Lixia District, Jinan City, China P O Box- 97, Sharjah, United Arab Emirates Sharjah 42244, Sharjah, UAE, Sharjah, United Arab Emirates 1 Refinery Road, Prospecton, 4110, South Africa Shell Centre, London, SE1 7NA, United Kingdom Fu Yong Town, Bao An county, ShenZhen Airport, Guangdong Province, China Shenzhen Dapeng LNG Marketing Company Limited (30.00%)b Guangdong Dapeng Liquefied Natural Gas Filling Station, Cheng Tou Corner, Xia Sha Village, Dapeng Street, Dapeng New District, Shenzhen, China SKA Energy Holdings Limited (50.00%) LOB 16, Suite #309, Jebel Ali Free Zone, Dubai, PO BOX 262794, United Arab Emirates SM Realisations Limited (In Liquidation) (40.00%) Shell International Petroleum, Co Ltd, Shell Centre, 8 York Road, London, SE1 7NA , United Kingdom Société d'Avitaillement et de Stockage de Carburants Aviation "SASCA" (40.00%)b Société de Gestion de Produits Pétroliers - SOGEPP (37.00%) 1 Place Gustave Eiffel, 94150, RUNGIS, France 27 Route du Bassin Numéro 6, 92230, GENNEVILLIERS, France Solar Photovoltaic (SPV2) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Solar Photovoltaic (SPV3) Limited (49.97%) South Caucasus Pipeline Company Limited (28.83%)y 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands South Caucasus Pipeline Holding Company Limited (28.83%) Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands South Caucasus Pipeline Option Gas Company Limited (28.83%) Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands South China Bluesky Aviation Oil Company Limited (24.50%)b 2-5F, No. 571, Yuncheng Dong Road, Baiyun District, Guangzhou City, Guangdong Province, China Srednelenskoye Limited Liability Company (49.00%) Kosmodamianskaya embarkment, 52 bldg 3, floor 9, unit 29, 115035, Moscow, Russian Federation Stansted Intoplane Company Limited (20.00%) Causeway House, 1 Dane Street, Bishop's Stortford, Hertfordshire, CM23 3BT, United Kingdom STDG Strassentransport Dispositions Gesellschaft mbH (50.00%) Jenfelder Allee 80, 22039, Hamburg, Germany Stockholm Fuelling Services Aktiebolag (25.00%) Box 7, 190 45 Arlanda, Sweden Sula Power Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Sun and Soil Renewable 12 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Tankanlage AG Mellingen (33.33%) Birmenstorferstrasse 2, 5507, Mellingen, Switzerland TAR - Tankanlage Ruemlang AG (27.32%) Zwüscheteich, 8153, Rümlang, Switzerland TAU Tanklager Auhafen AG (50.00%) Auhafenstrasse 10a, 4132, Muttenz, Switzerland Team Terminal B.V. (22.80%) Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands Tecklenburg GmbH (50.00%) Tecklenburg GmbH & Co. Energiebedarf KG (50.00%)f Terminal CP S.A.U. (50.00%) Wesermünder Straße 1, 27729 Hambergen, Germany Wesermünder Straße 1, 27729 Hambergen, Germany Av. Leandro N. Alem 1180, piso 11°, Buenos Aires, Argentina Terminal de Combustiveis Paulinia S.A. (50.00%) Avenida Paris, 4077, Suite 3, Cascata, Paulínia, São Paulo State, 13046-061, Brazil Terminales Canarios, S.L. (50.00%) TFSS Turbo Fuel Services Sachsen GbR (20.00%)f TGC Solar 106 Limited (49.97%) TGC Solar 91 Limited (49.97%) TGH Tankdienst-Gesellschaft Hamburg GbR (66.67%)f TGHL Tanklager-Gesellschaft Hannover-Langenhagen GbR (50.00%)f TGK Tanklagergesellschaft Koln-Bonn (25.00%)f Thames Electricity Limited (49.97%) The Baku-Tbilisi-Ceyhan Pipeline Company (30.10%)β Carretera de San Andréss/n, La Jurada-María Jiménez, Santa Cruz de Tenerife, Spain Sportallee 6, 22335 Hamburg, Germany 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Sportallee 6, 22335 Hamburg, Germany Sportallee 6, 22335 Hamburg, Germany Sportallee 6, 22335 Hamburg, Germany 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 298 bp Annual Report and Form 20-F 2020 Financial statements 14. Related undertakings of the group – continued The Consolidated Petroleum Company Limited (50.00%)y The Consolidated Petroleum Supply Company Limited (50.00%)ⳝ The Great Ropemaker Partnership (50.00%)f Thornton Transportation LLC (44.27%)b Thorntons LLC (44.27%)b TLK Holding Company LLC (44.27%)b TLK Intermediate Holding Company LLC (44.27%)b TLK Operating Company LLC (44.27%)b TLM Tanklager Management GmbH (49.00%)b TLS Tanklager Stuttgart GmbH (45.00%) Shell Centre, London, SE1 7NA, United Kingdom Shell Centre, London, SE1 7NA, United Kingdom 33 Cavendish Square, London, W1G 0PW, United Kingdom Corporation Service Company, 421 West Main Street, Frankfort KY 40601, United States CSC, 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States Am Tankhafen 4, 4020 Linz, Austria Zum Ölhafen 49, 70327 Stuttgart, Germany Tonatiuh Trading 1 Limited (49.97%) TRaBP GbR (75.00%)f Trafineo GmbH & Co. KG (75.00%)f Trafineo Service GmbH (75.00%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Huestraße 25, 44787, Bochum, Germany Wittener Straße 56, Bochum, Germany Wittener Straße 45, 44789 Bochum, Germany Trafineo Verwaltungs-GmbH (75.00%) Wittener Straße 56, Bochum, Germany Trans Adriatic Pipeline AG (20.00%) Lindenstrasse 2, 6340 Baar, Switzerland TransTank GmbH (50.00%) Tuwale Power Limited (49.97%) TWQE2 Limited (49.97%) Am Stadthafen 60, 45881 Gelsenkirchen, Germany 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Ubiworx Systems Designated Activity Company (49.97%) Trinity House, Charleston Road, Ranelagh, Dublin 6, D06C8X4, Ireland United Gas Derivatives Company "UGDC" (33.33%) Building No. 349 & 351, Third Sector of City Centre, Fifth Settlement, New Cairo, Egypt United Kingdom Oil Pipelines Limited (22.15%) 5-7 Alexandra Road, Hemel Hempstead, Hertfordshire, HP2 5BS, United Kingdom Vale do Cochá Geração de Energia Ltda. (49.97%) Estrada BR 030, número S/N, CXPST 08, bairro / distrito Zona Rural, município Montalvania - MG, CEP 39495-000, Brazil Vendimia Grid, AIE (49.97%) Ventress Solar Farm 1, LLC (49.97%)b Verde Grande Geração de Energia Ltda. (49.97%) Calle Alcala numero 63, 28014, Madrid, Spain 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Fazenda Contendas na Rodovia Joaquim de Freitas, sentido Mato Verde a Catut, Km 2 à direita, Zona Rural, município de Mato Verde-MG, CEP 39527-000, Brazil VIC CBM Limited (50.00%) Vientos Ombu III S.A. (25.00%) Eni House, 10 Ebury Bridge Road, London, SW1W 8PZ, United Kingdom Av. Leandro N. Alem 1180, piso 11°, Buenos Aires, Argentina Vientos Patagonicos Chubut Norte III S.A. (24.50%) Lavalle 190, piso 6 Depto L, Buenos Aires, Argentina Vientos Sudamericanos Chubut Norte IV S.A. (24.50%) Lavalle 190, piso 6 Depto L, Buenos Aires, Argentina Virginia Indonesia Co. CBM Limited (50.00%) Eni House, 10 Ebury Bridge Road, London, SW1W 8PZ, United Kingdom Walton-Gatwick Pipeline Company Limited (42.33%) 5-7 Alexandra Road, Hemel Hempstead, Herts., HP2 5BS, United Kingdom Wellington LandCo Pty Ltd (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia Wellington North Solar Farm Pty Limited (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia West London Pipeline and Storage Limited (30.50%) 5-7 Alexandra Road, Hemel Hempstead, Herts., HP2 5BS, United Kingdom West Wyalong FinCo Pty Ltd (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia West Wyalong Fund Pty Ltd (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia West Wyalong HoldCo 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom West Wyalong HoldCo 2 Pty Ltd (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia West Wyalong Trust (49.97%) Whitetail Solar 1, LLC (24.99%)b Whitetail Solar 2, LLC (24.99%)b Whitetail Solar 3, LLC (24.99%)b Whitetail Solar 6, LLC (49.97%)b Whitetail Solar Land Holdings, LLC (49.97%)b Wick Farm Grid Limited (24.99%) Wildflower Solar 1, LLC (49.97%)b Wildflower Solar Land Holdings, LLC (49.97%)b Wiri Oil Services Limited (27.78%) Woolooga FinCo Pty Ltd (49.97%) Woolooga Fund Pty Ltd (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Woodwater House, Pynes Hill, Exeter, EX2 5WR, United Kingdom 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States Ross Pauling & Partners Limited, 106b Bush Road, Albany, Auckland, 0632, New Zealand Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia Woolooga HoldCo 1 Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom Woolooga HoldCo 2 Pty Ltd (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia Woolooga Trust (49.97%) Your Power No. 1 Limited (49.97%) Your Power No. 10 Limited (49.97%) Your Power No. 19 Limited (49.97%) Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 299 14. Related undertakings of the group – continued Your Power No. 2 Limited (49.97%) Your Power No. 3 Limited (49.97%) Your Power No. 8 Limited (49.97%) Your Power No12 Limited (49.97%) Zonneweide Westdorperveen B.V. (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom 7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom Prins Bernhardplein 200 1097JB, Amsterdam, Netherlands 160 Greentree Drive, Suite 101, Dover, County of Kent DE 19904, United States Zubie, Inc. (20.30%) a  Preference shares b Member interest c  A and B shares d Common stock and preference shares e Ordinary shares and preference shares f  Partnership interest g  A, B and D shares h  A shares i Interest held directly by BP p.l.c. j 99% held directly by BP p.l.c. k 1% held directly by BP p.l.c. l  Ordinary, A and B shares m Common stock and redeemable preference shares n  Ordinary A, B and C shares o 0.008% held directly by BP p.l.c. p  80.01% ordinary shares and 99.07% preference shares q  Members interest, (49.99%) subordinated units and (4.37%) common units traded on the New York stock exchange r  93.64% ordinary shares and 81.18% preference shares s  Subsidiary in which the group does not hold a majority of the voting rights but exercises control over it t  Ordinary shares and redeemable preference shares u Ordinary and A shares v  Ordinary and deferred shares w 100% ordinary shares and 58.65% preference shares x  15% held directly by BP p.l.c y B shares z Unlimited redeemable shares ⍺ 96.52% C shares β 1.89% A shares and 40.80% B shares γ 49.97% A shares, 50.00% C shares, 50.00% D shares, 50.00% E shares, 49.95% F shares and 50.00% G shares ⳝ 5% held directly by BP p.l.c The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. 300 bp Annual Report and Form 20-F 2020 Additional disclosures Additional disclosures Selected financial information Liquidity and capital resources Oil and gas disclosures for the group Additional information for downstream Additional information for Rosneft Environmental expenditure Regulation of the group’s business International trade sanctions Material contracts Property, plant and equipment Related-party transactions Corporate governance practices Code of ethics Controls and procedures Principal accountant’s fees and services Directors’ report information Disclosures required under Listing Rule 9.8.4R Cautionary statement 302 306 308 318 320 321 321 325 326 326 326 326 326 326 327 327 328 329 bp Annual Report and Form 20-F 2020 301 Selected financial information This information has been extracted or derived from the audited consolidated financial statements of the bp group. Note 1 to the financial statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related notes. The audited consolidated financial statements and related notes as of 31 December 2020 and 2019 and for the three years ended 31 December 2020 are presented on page 130. Income statement data Sales and other operating revenues Profit (loss) before interest and taxation Finance costs and net finance expense relating to pensions and other post- retirement benefits Taxation Non-controlling interests Profit (loss) for the yeara Inventory holding (gains) losses«, before tax Taxation charge (credit) on inventory holding gains and losses RC profit (loss)« for the year Net (favourable) adverse impact of non-operating items« b and fair value accounting effects« b, before tax Taxation charge (credit) on non-operating items and fair value accounting effects, and certain foreign exchange impacts on the group’s tax charge for the period Underlying RC profit« for the year Earnings per sharec – cents Profit (loss) for the yeara per ordinary share Basic Diluted RC profit (loss) for the year per ordinary share« Underlying RC profit for the year per ordinary share« Dividends paid per share – cents – pence Capital expenditure« d Organic capital expenditure« Inorganic capital expenditure« 2020 2019 2018 2017 2016 $ million except per share amounts 180,366 (21,740) 278,397 11,706 298,756 19,378 240,208 9,474 183,008 (430) (3,148) 4,159 424 (20,305) 2,868 (667) (18,104) (3,552) (3,964) (164) 4,026 (667) 156 3,515 (2,655) (7,145) (195) 9,383 801 (198) 9,986 (2,294) (3,712) (79) 3,389 (853) 225 2,761 (1,865) 2,467 (57) 115 (1,597) 483 (999) 16,649 8,263 3,380 3,730 6,746 (4,235) (5,690) (1,788) 9,990 (643) 12,723 (325) 6,166 (3,162) 2,585 (100.42) (100.42) (89.53) (28.14) 31.50 24.458 12,034 2,021 14,055 19.84 19.73 17.32 49.24 41.00 31.977 15,238 4,183 19,421 46.98 46.67 50.00 63.70 40.50 30.568 15,140 9,948 25,088 17.20 17.10 14.02 31.31 40.00 30.979 16,501 1,339 17,840 0.61 0.60 (5.33) 13.79 40.00 29.418 16,675 777 17,452 Balance sheet data (at 31 December) Total assets Net assets Share capital bp shareholders’ equity Finance debt due after more than one year Gearing« Ordinary share datae Basic weighted average number of shares Diluted weighted average number of shares a Profit attributable to bp shareholders. b See pages 304 and 305 for further analysis of these items. c A reconciliation to GAAP information is provided on page 348. d From 2017 onwards bp reports organic, inorganic and total capital expenditure on a cash basis which were previously reported on an accruals basis. This aligns with bp's financial framework and is 267,654 85,568 5,383 71,250 63,305 31.3% 295,194 100,708 5,404 98,412 57,237 31.1% 282,176 101,548 5,402 99,444 55,803 30.0% 276,515 100,404 5,343 98,491 54,873 27.0% 20,222 20,222 19,970 20,102 20,285 20,400 19,693 19,816 263,316 96,843 5,284 95,286 51,073 26.5% Share million 18,745 18,855 consistent with other financial metrics used when comparing sources and uses of cash. e The number of ordinary shares shown has been used to calculate the per share amounts. 302 bp Annual Report and Form 20-F 2020 « See Glossary Additional information Capital expenditure Capital expenditure Organic capital expenditure Inorganic capital expenditureab Organic capital expenditure by segment Upstream US Non-US Downstream US Non-US Other businesses and corporate US Non-US Organic capital expenditure by geographical area US Non-US Additional disclosures 2020 2019 12,034 2,021 14,055 15,238 4,183 19,421 2020 2019 $ million 2018 15,140 9,948 25,088 $ million 2018 3,341 6,009 9,350 632 1,698 2,330 80 274 354 12,034 4,053 7,981 12,034 4,019 7,885 3,482 8,545 11,904 12,027 913 2,084 2,997 47 290 337 15,238 4,979 10,259 15,238 877 1,904 2,781 54 278 332 15,140 4,413 10,727 15,140 a On 31 October 2018, bp acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation, a wholly owned subsidiary of BHP that holds a portfolio of unconventional onshore US oil and gas assets. The entire consideration payable of $10,268 million, after customary closing adjustments, was paid in instalments between July 2018 and April 2019. The amounts presented as inorganic capital expenditure include $3,480 million for 2019 and $6,788 million for 2018 relating to this transaction. 2018 includes $1,739 million relating to the purchase of an additional 16.5% interest in the Clair field west of Shetland in the North Sea, as part of the agreements with Conoco-Phillips in which Conoco-Philips simultaneously purchased bp's entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska. 2020, 2019 and 2018 also include amounts relating to the 25-year extension to our ACG production-sharing agreement« in Azerbaijan. b 2020 includes a $500 million deposit in respect of the strategic partnership with Equinor and $1 billion relating to an investment in a 49% interest in the group's Indian fuels and mobility venture with Reliance industries. « See Glossary bp Annual Report and Form 20-F 2020 303 Non-operating items Non-operating items are charges and credits included in the financial statements that bp discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors to understand better and evaluate the group’s reported financial performance. An analysis of non-operating items is shown in the table below. Upstream Gain on sale of businesses and fixed assetsa Impairment and losses on sale of businesses and fixed assetsa b Environmental and other provisions Restructuring, integration and rationalization costsc Fair value gain (loss) on embedded derivatives Otherd e Downstream Gain on sale of businesses and fixed assetsa f Impairment and losses on sale of businesses and fixed assetsa Environmental and other provisions Restructuring, integration and rationalization costsc Fair value gain (loss) on embedded derivatives Other Rosneft Other Other businesses and corporate Gain on sale of businesses and fixed assetsa Impairment and losses on sale of businesses and fixed assetsa g Environmental and other provisionsh Restructuring, integration and rationalization costsc Fair value gain (loss) on embedded derivatives Gulf of Mexico oil spill response Otheri Total before interest and taxation Finance costsj Total before taxation 2020 2019 $ million 2018 360 (13,214) (2) (401) — (2,511) (15,768) 2,320 (1,136) (33) (633) — (39) 479 (205) (205) 194 (19) (177) (262) — (255) 201 143 (7,036) (32) (89) — 67 (6,947) 50 (122) (78) 85 — (12) (77) (103) (103) — (917) (231) 6 — (319) (30) 437 (527) (35) (131) 17 56 (183) 15 (69) (83) (405) — (174) (716) (95) (95) 4 (264) (640) (190) — (714) (159) (318) (15,812) (625) (16,437) 4,345 — (99) (12,191) (1,491) (8,618) (511) (9,129) 1,943 — — (7,186) (1,963) (2,957) (479) (3,436) 510 121 — (2,805) Taxation credit (charge) on non-operating items Taxation - impact of US tax reformk Taxation - impact of foreign exchangel Total after taxation a See Financial statements – Note 4 for further information. b 2020 impairment charges for Upstream include $156 million in relation to the likely disposal of an exploration asset. 2019 includes impairments charges principally resulting from the announcements to dispose of certain assets in the US and Egypt. 2018 includes an impairment reversal for assets in the North Sea and Angola. c Restructuring charges are classified as non-operating items where they relate to an announced major group restructuring. A major group restructuring is a restructuring programme affecting more than one of the group’s operating segments that is expected to result in charges of more than $1 billion over a defined period. 2020 includes recognized provisions for restructuring costs for plans that were formalized during the year. 2018 includes amounts related to the programme originally announced in 2014 that was completed in 2018. d 2020 includes exploration write-offs of $1,974 million relating to fair value ascribed to certain licences as part of the accounting at the time of acquisition of upstream assets in Brazil, India and the Gulf of Mexico and the impairment of certain intangible assets in Mauritania and Senegal. 2018 includes exploration write-offs of $124 million in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. e 2020 includes $545 million net impairments reported by equity-accounted entities. f 2020 includes a gain of $2.3 billion on the sale of our petrochemicals business. g 2019 includes $877 million relating to the reclassification of accumulated foreign exchange losses from reserves to the income statement upon the contribution of our Brazilian biofuels business to BP Bunge Bioenergia. h All periods primarily reflect charges due to the annual update of environmental provisions, including asbestos-related provisions for past operations, together with updates of non-Gulf of Mexico oil spill related legal provisions. i From 2020, BP is presenting temporary valuation differences associated with the group’s interest rate and foreign currency exchange risk management of finance debt as non-operating items. These amounts represent: (i) the impact of ineffectiveness and the amortisation of cross currency basis resulting from the application of fair value hedge accounting; and (ii) the net impact of foreign currency exchange movements on finance debt and associated derivatives where hedge accounting is not applied. Relevant amounts in the comparative periods presented were not material. j All periods presented include the unwinding of discounting effects relating to Gulf of Mexico oil spill payables. 2020 also includes the income statement impact associated with the buyback of finance debt. See Note 26 for further information. k In 2017 the US tax reform reduced the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018. 2018 reflects a further impact following a clarification of the tax reform. The impact of the US tax reform has been treated as a non-operating item because it is not considered to be part of underlying business operations, has a material impact upon the reported result and is substantially impacted by Gulf of Mexico oil spill charges, which are also treated as non-operating items. Separate disclosure is considered meaningful and relevant to investors. l From 2020, bp is presenting certain foreign exchange effects on tax as non-operating items. These amounts represent the impact of: (i) foreign exchange on deferred tax balances arising from the conversion of local currency tax base amounts into functional currency, and (ii) taxable gains and losses from the retranslation of US dollar-denominated intra-group loans to local currency. Relevant amounts in the comparative periods presented were not material. 304 bp Annual Report and Form 20-F 2020 « See Glossary Non-GAAP information on fair value accounting effects The impacts of fair value accounting effects, relative to management’s internal measure of performance, and a reconciliation to GAAP information is set out below. Further information on fair value accounting effects is provided on page 344. Additional disclosures Upstream Unrecognized (gains) losses brought forward from previous perioda Favourable (adverse) impact relative to management’s measure of performance Exchange translation gains (losses) on fair value accounting effects Unrecognized (gains) losses carried forward Downstream Unrecognized (gains) losses brought forward from previous perioda Favourable (adverse) impact relative to management’s measure of performance Unrecognized (gains) losses carried forward Other businesses and corporate Favourable (adverse) impact relative to management’s measure of performanceb Unrecognized (gains) losses carried forward Favourable (adverse) impact relative to management’s measure of performance – by region Upstream US Non-US Downstream US Non-US Other businesses and corporate US Non-US Taxation credit (charge) 2020 2019 $ million 2018 253 (738) — (485) 104 (149) (45) 675 675 198 (936) (738) 27 (176) (149) — 675 675 (212) (11) (223) (455) 706 2 253 (56) 160 104 — — (179) 885 706 148 12 160 — — — 866 (155) 711 (419) (39) 3 (455) (151) 95 (56) — — (35) (4) (39) (155) 250 95 — — — 56 12 68 a 2018 brought forward fair value accounting effect balances include a $55-million adjustment between Upstream and Downstream as part of the transfer of the NGL business between segments. b From 2020 fair value accounting effects include changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. For further information see page 344. Net debt including leases Net debt including leases« is shown in the table below. At 31 December Net debt« Lease liabilities Net partner (receivable) payable for leases entered into on behalf of joint operations« Net debt including leases Total equity Gearing including leases« 2020 38,941 9,262 (7) 48,196 85,568 36.0% $ million 2019 45,442 9,722 (158) 55,006 100,708 35.3% « See Glossary bp Annual Report and Form 20-F 2020 305 Liquidity and capital resources Financial framework bp has a resilient financial framework that, taken together with our strategy, creates a compelling investor proposition offering committed distributions, profitable growth and sustainable value. The framework comprises a coherent approach to capital allocation, a resilient balance sheet, a disciplined approach to investment allocation and a relentless focus on executing bp’s business plan. bp’s approach to capital allocation leads to a clear set of priorities – funding our resilient dividend as the first priority, deleveraging the balance sheet, investment in low carbon« and convenience and mobility to advance our energy transition strategy, investment in resilient hydrocarbons to generate sustainable cash flow, and then returning surplus cash« as share buybacks. In a period of low prices, the group has the flexibility to reduce cash costs and to reduce or defer capital investment, as appropriate. Our shareholder distribution policy reflects these priorities for the uses of cash alongside an ongoing consideration of factors, including changes in the environment, the underlying performance of the business, the outlook for the group financial framework, and other market factors which may vary quarter to quarter. Net debt« at 31 December 2020 was $38.9 billion and is expected to reduce in line with the receipt of divestment proceeds and the growth in operating cash flow« . bp is targeting $25 billion of proceeds by 2025 (from mid 2020), and at the end of 2020 bp had completed or agreed transactions for over half of this target. We expect operating cash flow to cover capital expenditure« and the dividend, with capital expenditure initially in a range of $13-15 billion, before increasing to $14-16 billion once net debt reaches $35 billion. Capital expenditure is expected to be at the lower end of the initial range in 2021. Looking further out across 2021-25, bp's cash balancing point is expected to average around $40 per barrel (assuming an average refining marker margin of around $11 and Henry Hub gas price at $3) in 2020 real terms. Gulf of Mexico oil spill payments on a post-tax basis were just over $1.6 billion in 2020 and are expected to be around $1 billion in 2021. In 2020, the return on average capital employed« was (3.8)%a at an average of $42 per barrel. The return on average capital employed is targeted to grow to 12-14% by 2025 at $50 to 60 per barrel in 2020 real terms, and assuming bp planning assumptions, as we continue to execute our strategy. This is supported by an expected 7-9% growth in earnings before interest, tax, depreciation and amortization (compound annual growth rate) across the same period and subject to the same price and planning assumptions. a Nearest equivalent GAAP measures: Numerator – Loss attributable to bp shareholders $(20.3); Denominator – Average capital employed $163.3 billion. Dividends and other distributions to shareholders The dividend is determined in US dollars, the economic currency of bp, and the dividend level is reviewed by the board each quarter. The quarterly dividend was reset to 5.25 cents per ordinary share per quarter as part of a wider distribution policy announced in August 2020, and is intended to remain fixed at this level. The total dividend distributed to bp shareholders in 2020 was $6.4 billion (2019 $8.3 billion). This dividend was all paid in cash as shareholders no longer have the option to receive a scrip dividend in place of receiving cash. Included in the distribution policy is a commitment that, once net debt reaches $35 billion and subject to maintaining a strong investment grade credit rating, at least 60% of surplus cash will be distributed to shareholders through share buybacks. The share buyback programme to offset the dilutive impact of the legacy scrip dividend concluded in January 2020 and purchased 120 million ordinary shares in 2020 at a cost of $776 million (2019 $1.5 billion), including fees and stamp duty. Financing the group’s activities The group’s principal commodities, oil and gas, are priced internationally in US dollars. Group policy has generally been to minimize economic exposure to currency movements by financing operations with US dollar debt. Where debt and hybrid bonds are issued in other currencies, they are generally swapped back to US dollars using derivative contracts, or else hedged by maintaining offsetting cash positions in the same currency. Cash balances of the group are mainly held in US dollars or swapped to US dollars and holdings are well diversified to reduce concentration risk. The group is not, therefore, exposed to significant currency risk regarding its cash or borrowings. Also see Risk factors on page 67 for further information on risks associated with prices and markets and Financial statements – Note 29. The group’s finance debt at 31 December 2020 amounted to $72.7 billion (2019 $67.7 billion). Of the total finance debt, $9.4 billion is classified as short term at the end of 2020 (2019 $10.5 billion). See Financial statements – Note 26 for more information on the short-term balance. Net debt« was $38.9 billion at the end of 2020, a decrease of $6.5 billion from the 2019 year-end position of $45.4 billion. On 17 June 2020, a group subsidiary« issued perpetual subordinated hybrid bonds in EUR, GBP and USD for a US dollar equivalent amount of $11.9 billion. As the group has the unconditional right to avoid transferring cash or another financial asset in relation to these hybrid bonds, they are classified as equity instruments and reported within non-controlling interests. The ratio of finance debt to finance debt plus total equity at 31 December 2020 was 45.9% (2019 40.2%). Gearing was 31.3% at the end of 2020 (2019 31.1%). See Financial statements – Note 27 for finance debt, which is the nearest equivalent measure on an IFRS basis, and for further information on net debt. Cash and cash equivalents of $31.1 billion at 31 December 2020 (2019 $22.5 billion) are included in net debt. We manage our cash position so that the group has adequate cover to respond to potential short-term market liquidity, short term price environment volatility and expect to maintain a robust cash position. The group also has an undrawn committed $8 billion credit facility and undrawn committed bank facilities of $4 billion (see Financial statements – Note 29 for more information). We believe that the group has sufficient working capital for foreseeable requirements, taking into account the amounts of undrawn borrowing facilities and levels of cash and cash equivalents, and its ongoing ability to generate cash. bp utilizes various arrangements in order to manage its working capital including discounting of receivables and, in the supply and trading business, the active management of supplier payment terms, inventory and collateral. Standard & Poor’s Ratings’ long-term credit rating for BP p.l.c. is A- (negative outlook), the Moody’s Investors Service rating is A1 (negative outlook) and the Fitch Ratings’ long-term credit rating is A (stable). The group’s sources of funding, its access to capital markets and maintaining a strong cash position are described in Financial statements – Note 25 and Note 29. Further information on the management of liquidity risk and credit risk, and the maturity profile and fixed/floating rate characteristics of the group’s debt are also provided in Financial statements– Note 26 and Note 29. The information above contains forward-looking statements, which by their nature involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of bp. You are urged to read the Cautionary statement on page 329 and Risk factors on page 67, which describe the risks and uncertainties that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements. 306 bp Annual Report and Form 20-F 2020 « See Glossary Off-balance sheet arrangements At 31 December 2020, the group’s share of third-party finance debt of equity-accounted entities was $19.9 billion (2019 $17.3 billion). These amounts are not reflected in the group’s debt on the balance sheet. The group has issued third-party guarantees under which amounts outstanding, incremental to amounts recognized on the balance sheet, at 31 December 2020 were $1,405 million (2019 $692 million) in respect of liabilities of joint ventures« and associates« and $661 million (2019 $523 million) in respect of liabilities of other third parties. Of these amounts, $1,393 million (2019 $681 million) of the joint ventures and associates guarantees relate to borrowings and for other third-party guarantees, $568 million (2019 $494 million) relate to guarantees of borrowings. Contractual obligations The following table summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2020 and the proportion of that expenditure for which contracts have been placed. Additional disclosures Capital expenditure Committed of which is contracted Total 18,025 8,009 2021 9,016 4,878 2022 5,467 2,805 2023 1,747 166 2024 747 65 $ million Payments due by period 2025 505 27 2026 and thereafter 543 68 Capital expenditure is considered to be committed when the project has received the appropriate level of internal management approval. For joint operations«, the net bp share is included in the amounts above. In addition, at 31 December 2020, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to $3,774 million. Contracts were in place for $1,270 million of this total. The following table summarizes the group’s principal contractual obligations at 31 December 2020, distinguishing between those for which a liability is recognized on the balance sheet and those for which no liability is recognized. Further information on borrowings is given in Financial statements – Note 26 and more information on leases is given in Financial statements – Note 28. $ million Payments due by period Expected payments by period under contractual obligations Total 2021 2022 2023 2024 2025 Balance sheet obligations Borrowingsa Lease liabilitiesb Decommissioning liabilitiesc Environmental liabilitiesc Gulf of Mexico oil spill liabilitiesd Pensions and other post-retirement benefitse Off-balance sheet obligations Unconditional purchase obligationsf Crude oil and oil products Natural gas and LNG Chemicals and other refinery feedstocks Power Utilities Transportation Use of facilities and services 81,076 10,884 22,466 1,880 14,569 17,448 148,323 13,981 2,262 470 272 1,409 1,039 19,433 7,541 1,672 244 290 1,278 978 12,003 8,146 1,340 279 242 1,222 946 12,175 9,001 1,025 233 196 1,141 922 12,518 7,445 878 221 157 1,136 917 10,754 2026 and thereafter 34,962 3,707 21,019 723 8,383 12,646 81,440 44,322 35,337 684 4,240 762 19,270 19,830 124,445 272,768 35,702 11,255 422 2,124 91 1,792 2,810 54,196 73,629 4,495 4,779 70 730 91 1,529 2,010 13,704 25,707 1,988 3,155 63 364 53 1,459 1,628 8,710 20,885 993 2,442 54 176 51 1,357 1,358 6,431 18,949 477 1,465 53 193 50 1,189 1,207 4,634 667 12,241 22 653 426 11,944 10,817 36,770 15,388 118,210 Total a Expected payments include interest totalling $8,412 million ($1,503 million in 2021, $1,249 million in 2022, $1,115 million in 2023, $954 million in 2024, $793 million in 2025 and $2,798 million thereafter). b Expected payments include interest totalling $1,622 million ($275 million in 2021, $228 million in 2022, $190 million in 2023, $156 million in 2024, $126 million in 2025 and $647 million thereafter). c The amounts presented are undiscounted. d The amounts presented are undiscounted. Gulf of Mexico oil spill liabilities are included in the group balance sheet, on a discounted basis, within other payables. See Financial statements – Note 22 for further information. e Represents the expected future contributions to funded pension plans and payments by the group for unfunded pension plans and the expected future payments for other post-retirement benefits. f Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms (such as fixed or minimum purchase volumes, timing of purchase and pricing provisions). Agreements that do not specify all significant terms, or that are not enforceable, are excluded. The amounts shown include arrangements to secure long-term access to supplies of crude oil, natural gas, feedstocks and pipeline systems. In addition, the amounts shown for 2021 include purchase commitments existing at 31 December 2020 entered into principally to meet the group’s short-term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts is discussed in Financial statements – Note 29. Commitments for the delivery of oil and gas We sell crude oil, natural gas and liquefied natural gas under a variety of contractual obligations.  Some of these contracts specify the delivery of fixed and determinable quantities.  For the period from 2021 to 2023 worldwide, we are contractually committed to deliver approximately 228 million barrels of oil, 8,500 billion cubic feet of natural gas, and 37 million tonnes of liquefied natural gas. The commitments principally relate to group subsidiaries« based in Canada, Egypt, Singapore, United Kingdom and United States.  We expect to fulfil these delivery commitments with production from our proved developed reserves and supplies from existing contracts, supplemented by market purchases as necessary. « See Glossary bp Annual Report and Form 20-F 2020 307 Oil and gas disclosures for the group Analysis by region Our oil and gas operations are set out below by geographical area, with associated significant events for 2020. bp’s percentage working interest in oil and gas assets is shown in brackets. Working interest is the cost- bearing ownership share of an oil or gas lease. Consequently, the percentages disclosed for certain agreements do not necessarily reflect the percentage interests in proved reserves, production or revenue. See page 320 for more information on Rosneft. In addition to exploration, development and production activities, our Upstream business also includes certain midstream and liquefied natural gas (LNG) supply activities. Midstream activities involve the ownership and management of crude oil and natural gas pipelines, processing facilities and export terminals, LNG processing facilities and transportation, and our natural gas liquids (NGLs) processing business. Our LNG activities are located in Abu Dhabi, Angola, Australia, Indonesia and Trinidad. In 2020 we marketed around 5.0 million tonnes of LNG production from these assets to IST which supplements equity production with merchant third party volumes to build a global trading portfolio. The LNG is marketed through contractual rights to access import terminal capacity in the liquid markets of Europe, UK and US, and relationships to market directly to end user customers or trading entities. LNG is supplied to all major LNG demand centres for example Argentina, Brazil, Caribbean, China, Croatia, Mediterranean and North West Europe, India, Israel, Japan, Singapore, South Korea, Taiwan, Thailand, Turkey and the UK. Europe bp is active in the North Sea and the Norwegian Sea. In 2020 bp’s production came from three key areas: the Shetland area comprising the Clair, Foinaven, and Schiehallion fields; the central area comprising the Andrew area, Culzean, ETAP and Shearwater fields; and Norway, through our equity accounted 30% interest in Aker BP. • On 29 March, bp confirmed completion of the restructuring of contractual arrangements for the Petrojari Foinaven floating production, storage and offloading vessel on the Foinaven field to the west of the Shetlands (bp 72% and operator). bp has around 260 lease blocks in the Gulf of Mexico and operates four production hubs. • On 25 August, bp confirmed it started production at Atlantis Phase 3 in the US Gulf of Mexico (bp 56% and operator). • Construction and installation at the Thunder Horse South Expansion Phase 2 project is underway and drilling set to commence in the first half of 2021. First oil from the project is expected in the third quarter of 2021. • bp was awarded 12 leases in the lease sale conducted in March and 10 leases in the sale held in November. • The Mad Dog 2 project execute timeline was impacted by both COVID-19 and delays to fabrication of the floating production unit. The unit has now set sail from Korea, and wells activity and subsea installation are once again progressing. First oil is now expected in the second quarter of 2022. • During the year, exploration write-offs of $2,643 million were recognized in relation to certain Gulf of Mexico assets, primarily due to management's re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long- term strategic plan and changes in the group's long-term price assumptions. See also Financial Statements – Note 1 for further information on exploration leases. bpx energy, bp's onshore oil and gas business in the Lower 48 states, has significant operated and non-operated activities across Louisiana, Texas and Wyoming producing natural gas, oil, NGLs and condensate, with primary focus on developing unconventional resources in Texas. It had a 1.5 billion boe proved reserve base at 31 December 2020, predominantly in unconventional reservoirs (tight gas«, shale gas and newly acquired shale oil). BPX Energy's assets span 2.1 million net developed acres and it had over 7,000 operated gross wells at 31 December 2020, with daily net production around 370mboe/d. bpx energy operated as a separate business in 2020 while remaining part of the Upstream segment. With its own governance, systems and processes, it is structured to increase competitive performance through swift decision making and innovation, while maintaining bp’s commitment to safe, reliable and compliant operations. • During the year, impairment charges of $2,796 million were recognized in respect of certain North Sea assets, primarily as a result of changes to the group's long-term price assumptions. • During the year, impairment charges of $1,444 million were recognized in respect of certain bpx energy assets, primarily as a result of changes to the group's long term price assumptions. • In March 2020, EnQuest, the Thistle field operator, announced it no longer expected to re-start production at the Thistle field (bp 82%) . A Cessation of Production application was approved by the regulator in July, with an effective decommissioning date of 31 May 2020. • During the third quarter, bp was awarded eight operated and three non- operated blocks in the North Sea as part of the UK Oil & Gas Authority 32nd offshore licensing round. • On 6 October, bp confirmed that the planned divestment to Premier Oil of its interests in the Andrew area and Shearwater assets, both located in the UK North Sea, would not proceed following the announcement of a proposed merger between Chrysaor and Premier Oil. bp had announced this divestment in January 2020. The divestment was to cover the Andrew, Arundel, Cyrus, Farragon and Kinnoull fields plus bp's interest in Shearwater. Marketing of both assets continues. • On 26 November, bp announced that production had started at the Vorlich field (bp 66%), just two years after the project was sanctioned. Vorlich is the latest in a programme of fast-paced, high-return subsea tiebacks in the UK North Sea. bp and partner Ithaca Energy invested £230 million to develop the field, which was discovered in 2014 and received regulatory approval for development in 2018. North America Our upstream activities in North America are located in four areas: deepwater Gulf of Mexico, the Lower 48 states, Canada and Mexico. Our interests in Alaska were disposed of during the year, further details are provided below. • In December bp announced that it had reached agreement to sell its interest in the Wamsutter asset in Wyoming to Williams Field Services LLC. The transaction completed in January 2021. bp’s onshore US crude oil and product pipelines and related transportation assets were included in the Downstream segment in 2020. In Alaska, BP Exploration (Alaska) Inc. (BPXA) operated nine North Slope oilfields in the Greater Prudhoe Bay area and held interests in three producing fields operated by others, as well as a non-operating interest in the Liberty development project prior to the completion in the second quarter of 2020 of the divestment of its Upstream business to Hilcorp Energy announced in 2019. BP Pipelines (Alaska) Inc. (BPPA) owned a 49% interest in the Trans- Alaska Pipeline System (TAPS) prior to completion in the fourth quarter of 2020 of the divestment of its Midstream interests to Hilcorp Energy announced in 2019. As part of this transaction impairments of $1,002 million were recognized in 2020. bp retained the decommissioning liability relating to its interest in TAPS which will be partially offset by a 30% reimbursement of costs incurred from Hilcorp. In Canada bp is focused on pursuing offshore exploration opportunities and its Sunrise Oil Sands operations. We have offshore exploration licences in Nova Scotia, Newfoundland and Labrador and the Canadian Beaufort Sea. In addition to Sunrise Oil Sands we hold interests in two further oil sands lease areas through the Terre de Grace partnership and the Pike Oil Sands joint operation«. In-situ steam-assisted gravity drainage (SAGD) technology is utilized in our existing oil sands operations, which uses the injection of steam into the reservoir to warm the bitumen so that it can flow to the surface through producing wells. 308 bp Annual Report and Form 20-F 2020 « See Glossary • The order issued by the government of Canada in 2019 prohibiting any work or activity authorized under the Canada Oil and Gas Operations Act on frontier lands that are situated in Canadian Arctic offshore waters remains in effect until 31 December 2021. • During the year, impairment charges of $865 million were recognized in respect of certain assets in Canada, primarily as a result of changes to the group's long-term price assumptions. • Also during the year, exploration write-offs of $2,539 million were recognized in relation to certain assets in Canada following management's re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long- term strategic plan and changes in the group's long-term price assumptions. A $247-million write-off was also recognized in relation to a prepayment for the Pike access pipeline. • On 29 October, bp confirmed oil discoveries at the Cappahayden and Cambriol prospects in the Flemish Pass basin (bp 40%), offshore Newfoundland. In Mexico, we have interests in two exploration joint operations in the Salina Basin with Equinor and Total, Block 1 (bp 33% and operator) and Block 3 (bp 33%), and in one exploration joint operation in the Sureste Basin with Total and Hokchi, a subsidiary of Pan American Energy Group (PAEG), Block 34 (bp 42.5% and operator). South America bp has upstream activities in Argentina, Brazil and Trinidad & Tobago and through PAEG, in Argentina, Bolivia and Uruguay. In Argentina bp and Total are partners on a 50/50 basis in two offshore exploration concessions. Total is the operator. In Brazil bp has interests in 22 exploration concessions across five basins. • During the year, exploration write-offs of $2,141 million were recognized in relation to certain assets in Brazil following management's re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long- term strategic plan and changes in the group's long-term price assumptions. • In the Foz do Amazonas basin, Total's request for a license extension for blocks FZA-M-57, 86, 88, 125 and 127was approved by the Brazilian regulatory authorities. Following their resignation from operatorship in August, Total reached agreement in October to transfer its working interest in these blocks to Petrobras. This transfer was also approved by the regulatory authorities. • In FZA-M-59 block, bp requested a two year license extension to May 2022 which was approved by the ANP in June, based on Resolution 708/2017. bp also transferred its operatorship of this block to Petrobras, and this was approved by the ANP in October. • bp reached an agreement to sell Itaipu and Wahoo exploration assets to PetroRio for $100 million to be paid in instalments from 2021 onwards; a further $40 million payment is contingent on pre-agreed conditions. The completion of this transaction is subject to the approval from the Brazilian regulatory authorities. PAEG, a joint venture that is owned by bp (50%) and Bridas Corporation (50%), has activities mainly in Argentina and Mexico, but is also present in Uruguay and Bolivia. • On 24 May, the Hokchi project in Mexico, operated by PAEG, achieved first oil, producing 1.2mboe/d in 2020. In Trinidad & Tobago bp holds interests in exploration and production licences and production-sharing contracts« (PSCs) covering 1.6 million acres offshore of the east and north-east coast. Facilities include 15 offshore platforms and two onshore processing facilities. Production comprises gas and associated liquids. bp also holds interests in the Atlantic LNG facility. bp’s shareholding averages 39% across four LNG trains« with a combined capacity of approximately 15 million tonnes per annum. During 2020 we sold gas to trains 1, 2 and 3 and processed gas in train 4. Most of the LNG produced from bp gas supplied to trains 2, 3 and 4 is sold to third parties under long- term contracts. Additional disclosures • The Cassia Compression project, a new compression platform with a 1.2bcf/d capacity bridge-linked to the Cassia B processing platform was expected to start up in 2021 but is delayed to 2022 as a result of COVID-19 impacting delivery lines. • Impairment charges of $2,416 million were recognized in 2020 in respect of certain assets in Trinidad, primarily as a result of changes to the group's long-term price assumptions. • bp holds a 30% interest in two deepwater blocks, Block 23(a) and TTDAA14, with BHP as the Operator holding a 70% interest. There were four successful exploration wells drilled in 2019 and appraisal work is ongoing on these discoveries. • bp’s initial gas sales and LNG offtake arrangements for Atlantic LNG Train 1 ended in September 2018. Subsequently, short term gas sales and LNG offtake arrangements were established and rolled over up until December 2020, with bp lifting the majority of the LNG produced. The National Gas Company of Trinidad & Tobago (NGC) has agreed to fund the operating cost of Train 1 up to the end of December 2021 for the right but not the obligation to supply gas into Train 1 and offtake 100% of the resultant LNG. • On 28 September, BP Trinidad and Tobago LLC started up the Galeota expansion project in Trinidad. The project comprises a new produced water handling facility, a new flare system, relocation of the control room away from production and upgrades to the existing condensate stabilization facility. • bp is operator of the Manakin Block which was discovered in 1998 and is a cross border reservoir field with the Venezuelan reservoir, Cocuina. Manakin declared commerciality in January 2018 however cross border discussions have not progressed due to the US sanctions. Africa bp’s upstream activities in Africa are located in Algeria, Angola, Côte d'Ivoire, Egypt, The Gambia, Libya, Mauritania, São Tomé & Príncipe and Senegal. bp's interest in Madagascar was relinquished in 2020. In Algeria bp, Sonatrach and Equinor are partners in the In Salah (bp 33.15%) and In Amenas (bp 45.89%) non-operated joint ventures that supply gas to the domestic and European markets. In Angola, bp owns an interest in five major deepwater offshore licences and is operator in two of these, Blocks 18 and 31, that are producing. We also have an equity interest in the Angola LNG plant (bp 13.6%). • During the year, exploration write-offs of $832 million were recognized in relation to certain assets in Angola following management's re- assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan and changes in the group's long-term price assumptions. • Also during the year, impairment charges of $316 million were recognized in relation to certain assets in Angola, primarily as a result of changes to the group's long-term price assumptions. • Development progressed at the Total-operated Zinia 2 deep offshore development project in Block 17 (bp 15.84%) and first production is expected in 2021. • During the year, construction activity started at the Platina project in Block 18, with first production expected in 2022. • Following the signing of an agreement in December 2019 by bp and its partners with the Agência Nacional de Petróleo, Gás e Biocombustíveis (ANPG), to extend the production-sharing agreement« (PSA) for Block 17 until 2045, all conditions precedent relating to the agreement were met in the second quarter of 2020 and the new agreement became effective on 1 April 2020. Under the agreement the state- owned company Sonangol acquired a 5% equity interest in the block on the effective date with a further 5% to be transferred in 2036. • In June 2019, bp and the contractor group signed an agreement with ANPG, extending the PSA for Block 15 until 2032. Under the agreement Sonangol acquired a 10% equity interest in the block, reducing bp’s interest from 26.67% to 24%. All conditions precedent relating to the agreement were met on 27 January 2020 and the new agreement became effective as from 1 October 2019. « See Glossary bp Annual Report and Form 20-F 2020 309 • In December 2018, bp and the contractor group signed an agreement with ANPG, extending the Block 18 PSA until 2032. Under the agreement, effective from 1 July 2020, Sonangol acquired an 8% equity interest in the block, reducing bp’s interest from 50% to 46%. All conditions precedent relating to the agreement were met on 17 December 2020. In Côte d’Ivoire, bp has interests in five offshore oil blocks with Kosmos Energy (KE) under agreements with the government of Côte d'Ivoire and the state oil company Société Nationale d'Operations Pétrolières de la Côte d'Ivoire (PETROCI) (bp 45%). In Egypt, bp and its partners currently produce 60% of Egypt’s gas production. • During the year, exploration write-offs of $952 million were recognized in relation to certain assets in Egypt following management's re- assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan and changes in the group's long-term price assumptions. • In July, bp confirmed the Bashrush gas discovery, located offshore Egypt in the North El Hammad concession (bp 37.5%). • On 16 September, bp confirmed a gas discovery with the Nidoco NW-1 exploratory well in the Abu Madi West development lease, offshore Egypt (bp 25%). • On 26 October bp announced the start-up of gas production from the Qattameya gas field in the North Damietta offshore concession (bp 100%). Qattameya, whose discovery was announced in 2017, is located approximately 45 km west 𝅺of the Ha’py platform and is tied back to the Ha’py and Tuart field 𝅺development via a new 50km pipeline. • Work on the West Nile Delta Raven project (BP 82.75%) is almost complete, with start up expected in the first quarter of 2021. Raven is the third project in North Alexandria and West Mediterranean deepwater offshore blocks. In the Gambia, bp has a 90% interest in offshore block A1 with the state oil company, Gambia National Petroleum Corporation. In Libya, bp partners with the Libyan Investment Authority (LIA) in an exploration and production sharing agreement (EPSA) to explore acreage in the onshore Ghadames and offshore Sirt basins (bp 85%). bp wrote off all balances associated with the Libya EPSA in 2015. • bp, LIA and Eni continue to work with the NOC towards Eni acquiring a 42.5% interest in the bp-operated EPSA in Libya. On completion, Eni would become operator of the EPSA. The companies are continuing to work together to finalize and complete all agreements. In Mauritania and Senegal, bp has a 62% participating interest in the C8, C12 and C13 exploration blocks in Mauritania and a 60% participating interest in the Cayar Profond Offshore and St Louis Profond Offshore exploration blocks in Senegal. We relinquished our interest in the C6 exploration block in October. Together the remaining blocks cover approximately 19,700 square kilometres. For the Greater Tortue Ahmeyin (GTA) Unit across the border of Mauritania and Senegal, bp has a 56% participating interest. The Phase 1 construction activity for the GTA major project« was severely affected by COVID-19 and the 2020 weather window for installation works was not met resulting in a delay to start up of around one year. A force majeure (FM) notice was issued under the lease and operate agreement with Golar LNG over the provision of a floating liquified natural gas vessel, where due to the FM event the lessee was not able to meet the connection date. On 1 October, bp confirmed force majeure was lifted on the project. • During the first quarter, bp executed a gas sale and purchase agreement with partners in the Greater Tortue Ahmeyim (GTA) project. • During the year, impairment charges and an exploration write-off totalling $2,260 million were recognized in respect of certain assets in the region, primarily as a result of changes to the group's long-term price assumptions. In Madagascar, during the second quarter, following management's re- assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan and changes in the group's long-term price assumptions, bp relinquished its interest in three PSCs (the fourth was relinquished in February 2020) for exploration licences situated offshore northwest Madagascar, under agreements with the government of Madagascar represented by Office des Mines Nationales et des Industries Stratégiques (OMNIS) (bp 100%). In São Tomé & Príncipe, bp is operator in two offshore blocks under PSAs with Shell who acquired the interests of KE in December 2020, and the state oil company Agencia Nacional do Petroleo (bp 50%). Asia bp has activities in Abu Dhabi, Azerbaijan, China, India, Indonesia, Iraq, Kuwait, Oman and Russia. In China we have a 30% equity stake in the Guangdong LNG regasification terminal and trunkline project with a total storage capacity of 640,000 cubic metres. The project is supplied under a long-term contract with Australia’s North West Shelf venture (bp 16.67%). In Azerbaijan, bp operates two PSAs, Azeri-Chirag-Gunashli (ACG) (bp 30.37%) and Shah Deniz (bp 28.83%) and also holds a number of other exploration leases. • Naftiran Intertrade Co Ltd (NICO), a subsidiary of the National Iranian Oil Company, holds a 10% interest in the Shah Deniz joint venture. For information on the exclusion of this project from EU and US trade sanctions, or exemptions from such trade sanctions in relation to this project, see International trade sanctions on page 325. • During the year, impairment charges of $537 million were recognized in respect of certain assets in the region, primarily as a result of changes to the group's long-term price assumptions. • In January 2020 bp announced that drilling of the first well on the Shafag-Asiman offshore block had commenced. The drilling of the SAX01 well continued in 2020 and we expect it to reach the target depth in the first half of 2021. bp holds a 30.1% interest in and operates the Baku-Tbilisi-Ceyhan oil pipeline. The 1,768-kilometre pipeline transports oil from the bp-operated ACG oilfield and gas condensate from the Shah Deniz gas field in the Caspian Sea, along with other third-party oil, to the eastern Mediterranean port of Ceyhan. The pipeline has a capacity of 1mmboe/d, with an average throughput in 2020 of 570mboe/d. bp (as operator of Azerbaijan International Operating Company) also operates the Western Route Export Pipeline that transports ACG oil to Supsa on the Black Sea coast of Georgia, with an average throughput of 85mboe/d in 2020. bp holds a 28.83% interest in and performs some operations for the 693 kilometre South Caucasus Pipeline. The pipeline takes gas from Azerbaijan through Georgia to the Turkish border and has a capacity of 440mboe/d (including expansion), with average throughput in 2020 of 210mboe/d. bp also holds a 12% interest in the Trans Anatolian Natural Gas Pipeline (TANAP). In the first phase, which commenced in 2018, gas from Shah Deniz is transported to Eskisehir in Turkey. The capacity of the pipeline during the first phase is 100mboe/d and the average throughput in 2020 was 80mboe/d. The second phase takes gas further to TANAP's connection with the Trans Adriatic Pipeline (TAP) at the Turkey-Greece border. bp has a 20% interest in TAP, that takes gas through Greece and Albania into Italy. Commercial deliveries of gas via TAP commenced at the end of 2020. In Oman bp operates Block 61, the largest tight gas« development in the Middle East (bp 60%), and is a 50% owner in Block 77. • The Block 77 Exploration and PSA was approved by Royal Decree in the first quarter of 2020, with a plan to process seismic and drill one exploration well within the next three years. ENI (50%) is operator during the exploration phase and bp will be the operator of any potential development. • On 12 October, bp announced production had begun from the Block 61 Phase 2 Ghazeer gas field, around 33 months after bp and its partners approved the development. bp brought the project online ahead of the original planned start-up in early 2021, and under budget. • On 1 February 2021 bp announced that it had agreed to sell a 20% participating interest in Block 61 to PTT Exploration and Production 310 bp Annual Report and Form 20-F 2020 « See Glossary Public Company Limited (PTTEP) of Thailand for a total consideration of $2.6 billion. Following completion of the sale, which is subject to Royal Decree, bp will remain operator of the block with a 40% interest. Australasia bp has activities in Australia and Eastern Indonesia. Additional disclosures In Australia bp is one of seven participants in the North West Shelf (NWS) venture, which has been producing LNG, pipeline gas, condensate, LPG and oil since the 1980s. Six partners (including bp) hold an equal 16.67% interest in the gas infrastructure and an equal 15.78% interest in the gas and condensate reserves, with a seventh partner owning the remaining 5.32%. bp also has a 16.67% interest in some of the NWS oil reserves and related infrastructure. The NWS venture is currently the largest single source supplier to the domestic market in Western Australia and one of the largest LNG export projects in the region, with five LNG trains in operation. bp’s net share of the capacity of NWS LNG trains 1-5 is 2.7 million tonnes of LNG per year. bp is also one of five participants in the Browse LNG venture (operated by Woodside) and holds a 17.33% interest. • The Browse joint venture participants continue to progress the development of Browse by connecting it via a 900km pipeline to the NWS Venture's Karratha Gas Plant. In Papua Barat, Eastern Indonesia, bp operates the Tangguh LNG plant (bp 40.22%). The asset currently comprises 16 producing wells, two offshore platforms, two pipelines and an LNG plant with two production trains. It has a total capacity of 7.6 million tonnes of LNG per annum. Tangguh supplies LNG to customers in Indonesia, Mexico, China, South Korea, and Japan through a combination of long, medium and short-term contracts. The Tangguh expansion project comprises a third LNG processing train, two offshore platforms, 10 new production wells, an expanded LNG loading facility, and supporting infrastructure. The project will add 3.8 million tonnes per annum (mtpa) of production capacity to the existing facility, bringing total plant capacity to 11.4mtpa. Due to COVID-19 and the need to relocate personnel from the remote project, the start-up is expected to be delayed to 2022. In Abu Dhabi, bp holds a 10% interest in the ADNOC Onshore concession. We also have a 10% equity shareholding in ADNOC LNG and a 10% shareholding in the shipping company NGSCO. ADNOC LNG supplied approximately 5.69 million tonnes of LNG (0.748bcfe/d regasified) in 2020. Our interest in the ADNOC Onshore concession expires at the end of 2054. In 2016 bp signed an enhanced technical service agreement for south and east Kuwait conventional oilfields, which includes the Burgan field, with Kuwait Oil Company. Delivery of the 2019-2020 plan was above target performance and implementation of the 2020-21 plan is underway. In India we have a participating interest in two oil and gas PSAs (KG D6 33.33% and NEC25 33.33%), and one oil and gas block under a Revenue Sharing Contract (KG-UDWHP-2018/1 40%), all operated by Reliance Industries Limited (RIL). We also have a 50% stake in India Gas Solutions Private Limited, a joint venture with RIL, for the sourcing and marketing of gas in India. • On 3 February, bp and RIL confirmed that they had completed the safe cessation of production in a planned manner, from the D1 D3 field in Block KG D6, off the east coast of India (bp 33.33%). • During the year, impairment charges of $1,313 million were recognized in respect of certain assets in India, primarily as a result of changes to the group's long-term price assumptions. • Also during the year, exploration write-offs of $333 million were recognized in relation to certain assets in India following management's re-assessment of expectations to extract value from certain exploration prospects as a result of a review of the group's long-term strategic plan and changes in the group's long-term price assumptions. • On 18 December, bp and RIL announced the start of gas production from R-Series, the first of the three projects in Block KG D6. The other two projects (Satellites Cluster and MJ) are under development with first gas production phased over 2021-2022. In Indonesia bp successfully completed the purchase of a 30% non- operated working interest in the Andaman II PSC from KrisEnergy in April. Andaman II is a deep-water block covering 7,400 square kilometres area in the North Sumatra basin, offshore from Aceh. Other interest holders are Premier Oil (40%, operator) and Mubadala Petroleum (30%). In Iraq bp holds a 47.6% working interest and is the lead contractor in the Rumaila technical service contract in southern Iraq. The technical services contract runs to December 2034. Rumaila is one of the world’s largest oil fields, comprising five producing reservoirs. bp's activities have not been materially impacted by the continued political instability and public protests which have occurred in 2020. In Russia in addition to its interest in Rosneft as detailed on page 320, bp holds a 20% interest in Taas-Yuryakh Neftegazodobycha (Taas) together with Rosneft (50.1%) and a consortium comprising Oil India Limited, Indian Oil Corporation Limited and Bharat PetroResources Limited (29.9%). Taas is developing the Srednebotuobinskoye oil and gas condensate field in East Siberia. Also with Rosneft, we hold a 49% interest in Kharampurneftegaz LLC (Kharampur) to develop subsoil resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets. Rosneft (51%) and bp (49%) jointly own Yermak Neftegaz LLC (Yermak), which conducts onshore exploration in the West Siberian and Yenisei-Khatanga basins and currently holds six exploration and production licences. • During the year bp received $86 million of dividends net of withholding taxes and $51 million of distribution of paid in capital from Taas. « See Glossary bp Annual Report and Form 20-F 2020 311 Oil and natural gas Resource progression bp manages its hydrocarbon resources in three major categories: prospect inventory, contingent resources and reserves. When a discovery is made, volumes usually transfer from the prospect inventory to the contingent resources category. The contingent resources move through various sub-categories as their technical and commercial maturity increases through appraisal activity. At the point of final investment decision, most proved reserves will be categorized as proved undeveloped (PUD). Volumes will subsequently be recategorized from PUD to proved developed (PD) as a consequence of development activity. When part of a well’s proved reserves depends on a later phase of activity, only that portion of proved reserves associated with existing, available facilities and infrastructure moves to PD. The first PD bookings will typically occur at the point of first oil or gas production. Major development projects typically take one to five years from the time of initial booking of PUD to the start of production. Changes to proved reserves bookings may be made due to analysis of new or existing data concerning production, reservoir performance, commercial factors and additional reservoir development activity. Volumes can also be added or removed from our portfolio through acquisition or divestment of properties and projects. When we dispose of an interest in a property or project, the volumes associated with our adopted plan of development for which we have a final investment decision will be removed from our proved reserves upon completion of the transaction. When we acquire an interest in a property or project, the volumes associated with the existing development and any committed projects will be added to our proved reserves if bp has made a final investment decision and they satisfy the SEC’s criteria for attribution of proved status. Following the acquisition, additional volumes may be progressed to proved reserves from non-proved reserves or contingent resources. Non-proved reserves and contingent resources in a field will only be recategorized as proved reserves when all the criteria for attribution of proved status have been met and the volumes are included in the business plan and scheduled for development, typically within five years. bp will only book proved reserves where development is scheduled to commence after more than five years, if these proved reserves satisfy the SEC’s criteria for attribution of proved status and bp management has reasonable certainty that these proved reserves will be produced. At the end of 2020 bp had material volumes of proved undeveloped reserves held for more than five years in Russia, Trinidad, Gulf of Mexico, Azerbaijan, Indonesia and the North Sea. These are part of ongoing infrastructure-led development activities for which bp has a historical track record of completing comparable projects in these countries. We have no proved undeveloped reserves held for more than five years in our onshore US developments. In each case the volumes are being progressed as part of an adopted development plan where there are physical limits to the development timing such as infrastructure limitations, contractual limits including gas delivery commitments, late life compression and the complex nature of working in remote locations, or where there are significant commitments on delivery to the relevant authority. Over the past five years, bp has annually progressed a weighted average 17% (19% for 2019 five-year average) of our group proved undeveloped reserves (including the impact of disposals and price acceleration effects in PSAs) to proved developed reserves. This equates to a turnover time of six years. Proved reserves as estimated at the end of 2020 meet bp’s criteria for project sanctioning and SEC tests for proved reserves. We have not halted or changed our commitment to proceed with any material project to which proved undeveloped reserves have been attributed. entities). The major areas with progressed volumes in 2020 were Russia, US, Egypt and Oman. Revisions of previous estimates for proved undeveloped reserves are due to changes relating to field performance, well results or changes in commercial conditions including price impacts. The following tables describe the changes to our proved undeveloped reserves position through the year for our subsidiaries and equity- accounted entities and for our subsidiaries alone. Subsidiaries and equity-accounted entities Proved undeveloped reserves at 1 January 2020 Revisions of previous estimates Improved recovery Discoveries and extensions Purchases Sales Total in year proved undeveloped reserves changes Proved developed reserves reclassified as undeveloped Progressed to proved developed reserves by development activities (e.g. drilling/completion) Proved undeveloped reserves at 31 December 2020 volumes in mmboea 8,152 298 133 436 442 (940) 369 247 (897) 7,871 Subsidiaries only Proved undeveloped reserves at 1 January 2020 Revisions of previous estimates Improved recovery Discoveries and extensions Purchases Sales Total in year proved undeveloped reserves changes Proved developed reserves reclassified as undeveloped Progressed to proved developed reserves by development activities (e.g. drilling/completion) Proved undeveloped reserves at 31 December 2020 volumes in mmboea 3,771 42 122 84 — (8) 240 173 (512) 3,673 a Because of rounding, some totals may not agree exactly with the sum of their component parts. bp bases its proved reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements. bp only applies technologies that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. bp applies high-resolution seismic data for the identification of reservoir extent and fluid contacts only where there is an overwhelming track record of success in its local application. In certain cases bp uses numerical simulation as part of a holistic assessment of recovery factor for its fields, where these simulations have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In certain deepwater fields bp has booked proved reserves before production flow tests are conducted, in part because of the significant safety, cost and environmental implications of conducting these tests. The industry has made substantial technological improvements in understanding, measuring and delineating reservoir properties without the need for flow tests. To determine reasonable certainty of commercial recovery, bp employs a general method of reserves assessment that relies on the integration of three types of data: • well data used to assess the local characteristics and conditions of reservoirs and fluids • field scale seismic data to allow the interpolation and extrapolation of these characteristics outside the immediate area of the local well control • data from relevant analogous fields. In 2020 we progressed 897 mmboe of proved undeveloped reserves (512 mmboe for our subsidiaries« alone) to proved developed reserves through ongoing investment in our subsidiaries’ and equity-accounted entities’ upstream development activities. Total development expenditure, excluding midstream activities, was $11,041 million in 2020 ($7,650 million for subsidiaries and $3,391 million for equity-accounted Well data includes appraisal wells or sidetrack holes, full logging suites, core data and fluid samples. bp considers the integration of this data in certain cases to be superior to a flow test in providing understanding of overall reservoir performance. The collection of data from logs, cores, wireline formation testers, pressures and fluid samples calibrated to each other and to the seismic data can allow reservoir properties to be 312 bp Annual Report and Form 20-F 2020 « See Glossary determined over a greater volume than the localized volume of investigation associated with a short-term flow test. There is a strong track record of proved reserves recorded using these methods, validated by actual production levels. Regulation S-X. All reserves estimates involve some degree of uncertainty. bp has filed D&M’s independent report on its reserves estimates as an exhibit to this Annual Report on Form 20-F filed with the SEC. Additional disclosures Governance bp’s centrally controlled process for proved reserves estimation approval forms part of a holistic and integrated system of internal control. It consists of the following elements: • Accountabilities of certain officers of the group to ensure that there is review and approval of proved reserves bookings independent of the operating business and that there are effective controls in the approval process and verification that the proved reserves estimates and the related financial impacts are reported in a timely manner. • Capital allocation processes, whereby delegated authority is exercised to commit to capital projects that are consistent with the delivery of the group’s business plan. A formal review process exists to ensure that both technical and commercial criteria are met prior to the commitment of capital to projects. • Group audit, whose role is to consider whether the group’s system of internal control is adequately designed and operating effectively to respond appropriately to the risks that are significant to bp. • Approval hierarchy, whereby proved reserves changes above certain threshold volumes require immediate review and all proved reserves require annual central authorization and have scheduled periodic reviews. The frequency of periodic review ensures that 100% of the bp proved reserves base undergoes central review every three years. bp’s vice president of segment reserves is the individual primarily responsible for overseeing the preparation of the reserves estimate. He has more than 27 years of diversified industry experience in reserves estimation with the past 2 years managing the governance and compliance. He is a past Chairman of the Society of Petroleum Engineers (Russia & Caspian) and a member of the United Nations Economic Commission for Europe Expert Group on Resource Management. No specific portion of compensation bonuses for senior management is directly related to proved reserves targets. Additions to proved reserves is one of several indicators by which the performance of the Upstream segment is assessed by the remuneration committee for the purposes of determining compensation bonuses for the executive directors. Other indicators include a number of financial and operational measures. bp’s variable pay programme for the other senior managers in the Upstream segment is based on individual performance contracts. Individual performance contracts are based on agreed items from the business performance plan, one of which, if chosen, could relate to proved reserves. Compliance International Financial Reporting Standards (IFRS) do not provide specific guidance on reserves disclosures. bp estimates proved reserves in accordance with SEC Rule 4-10 (a) of Regulation S-X and relevant Compliance and Disclosure Interpretations (C&DI) and Staff Accounting Bulletins as issued by the SEC staff. By their nature, there is always risk involved in the ultimate development and production of proved reserves including, but not limited to: final regulatory approval; the installation of new or additional infrastructure, as well as changes in oil and gas prices; changes in operating and development costs; and the continued availability of additional development capital. All the group’s proved reserves held in subsidiaries and equity-accounted entities are estimated by the group’s petroleum engineers or by independent petroleum engineering consulting firms and then assured by the group’s petroleum engineers. DeGolyer & MacNaughton (D&M), an independent petroleum engineering consulting firm, has estimated the net proved crude oil, condensate, natural gas liquids (NGLs) and natural gas reserves, as of 31 December 2020, of certain properties owned by Rosneft as part of our equity- accounted proved reserves. The properties evaluated by D&M account for 100% of Rosneft’s net proved reserves as of 31 December 2020. The net proved reserves estimates prepared by D&M were prepared in accordance with the reserves definitions of Rule 4-10(a)(1)-(32) of Netherland, Sewell & Associates (NSAI), an independent petroleum engineering consulting firm, has estimated the net proved crude oil, condensate, natural gas liquids (NGLs) and natural gas reserves, as of 31 December 2020, of certain properties owned by bp in the US Lower 48. The properties evaluated by NSAI account for 100% of bp’s net proved reserves in the US Lower 48 as of 31 December 2020. The net proved reserves estimates prepared by NSAI were prepared in accordance with the reserves definitions of Rule 4-10(a)(1)-(32) of Regulation S-X. All reserves estimates involve some degree of uncertainty. bp has filed NSAI’s independent report on its reserves estimates as an exhibit to this Annual Report on Form 20-F filed with the SEC. Our proved reserves are associated with both concessions (tax and royalty arrangements) and agreements where the group is exposed to the upstream risks and rewards of ownership, but where our entitlement to the hydrocarbons is calculated using a more complex formula, such as with PSAs. In a concession, the consortium of which we are a part is entitled to the proved reserves that can be produced over the licence period, which may be the life of the field. In a PSA, we are entitled to recover volumes that equate to costs incurred to develop and produce the proved reserves and an agreed share of the remaining volumes or the economic equivalent. As part of our entitlement is driven by the monetary amount of costs to be recovered, price fluctuations will have an impact on both production volumes and reserves. We disclose our share of proved reserves held in equity-accounted entities (joint ventures« and associates«), although we do not control these entities or the assets held by such entities. bp’s estimated net proved reserves and proved reserves replacement 92% of our total proved reserves of subsidiaries at 31 December 2020 were held through joint operations« (91% in 2019), and 31% of the proved reserves were held through such joint operations where we were not the operator (28% in 2019). Estimated net proved reserves of crude oil at 31 December 2020a b c UK USd Rest of North Americad South Americae Africa Rest of Asia Australasia Subsidiaries Equity-accounted entities Total million barrels Developed Undeveloped 162 697 37 8 116 1,100 34 2,154 3,517 5,671 148 742 195 9 21 547 5 1,666 2,776 4,441 Total 309 1,438 232 16 137 1,647 38 3,819 6,293 10,112 Estimated net proved reserves of natural gas liquids at 31 December 2020a b million barrels UK US Rest of North America South America Africa Rest of Asia Australasia Subsidiaries Equity-accounted entities Total Developed Undeveloped 7 115 — 2 13 — 2 139 129 268 — 218 — 19 1 — — 237 44 281 Total 7 333 — 21 14 — 2 376 172 549 313 « See Glossary bp Annual Report and Form 20-F 2020 Estimated net proved reserves of liquids« million barrels Developed Undeveloped Subsidiariese Equity-accounted entitiesf Total Estimated net proved reserves of natural gas at 31 December 2020a b 2,293 3,645 5,938 1,903 2,819 4,722 Total 4,196 6,465 10,661 billion cubic feet Developed Undeveloped UK US Rest of North America South Americag Africa Rest of Asia Australasia Subsidiaries Equity-accounted entitiesh Total Estimated net proved reserves on an oil equivalent basisi 306 1,921 — 1,567 1,382 3,883 2,058 11,118 13,088 24,206 51 3,423 — 1,964 158 3,641 1,029 10,267 7,994 18,260 Total 358 5,344 — 3,531 1,541 7,524 3,087 21,385 21,082 42,467 million barrels of oil equivalent Developed Undeveloped Total 7,883 10,100 17,982 Subsidiaries Equity-accounted entities Total a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the 4,210 5,902 10,112 3,673 4,198 7,871 royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently, and include non-controlling interests in consolidated operations. We disclose our share of reserves held in joint ventures and associates that are accounted for by the equity method although we do not control these entities or the assets held by such entities. b The 2020 marker prices used were Brent« $41.31/bbl (2019 $62.74/bbl and 2018 $71.43/bbl) and Henry Hub« $1.94/mmBtu (2019 $2.58/mmBtu and 2018 $3.10/mmBtu). c Includes condensate. d All of the reserves in Canada are bitumen. e Includes 11 million barrels of liquids in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. f Includes  405 million barrels in respect of the non-controlling interest in Rosneft, including 19mmboe held through bp’s interests in Russia other than Rosneft. g Includes 1,059 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. h Includes 1,640 billion cubic feet of natural gas in respect of the 10.01% non-controlling interest in Rosneft including 614 billion cubic feet held through bp’s interests in Russia other than Rosneft. i Includes 264 million barrels of oil equivalent associated with Assets Held for Sale in Oman. Because of rounding, some totals may not agree exactly with the sum of their component parts. Proved reserves replacement Total hydrocarbon proved reserves at 31 December 2020, on an oil equivalent basis including equity-accounted entities, decreased by 7% compared with 31 December 2019. Natural gas represented about 41% (47% for subsidiaries and 36% for equity-accounted entities) of these reserves. The change includes a net decrease from acquisitions and disposals of 1,069mmboe (decrease of 1,072mmboe within our subsidiaries and increase of 3mmboe within our equity-accounted entities). Acquisition and divestment activity occurred in our equity- accounted entities in Russia, and divestment activity in our subsidiaries in the US including Alaska. The proved reserves replacement ratio« is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery, and extensions and discoveries. For 2020, the proved reserves replacement ratio excluding acquisitions and disposals was 78% (67% in 2019 and 100% in 2018) for subsidiaries and equity-accounted entities, 47% for subsidiaries alone and 127% for equity-accounted entities alone. There was a net decrease (373mmboe) of reserves due to lower gas and oil prices within the US, North Sea and Angola partly offset by increases related to price in some of our PSAs in Iraq and Azerbaijan. In 2020 net additions to the group’s proved reserves (excluding production and sales and purchases of reserves-in-place) amounted to 1,006mmboe (380mmboe for subsidiaries and 626mmboe for equity- accounted entities), through revisions to previous estimates including price, improved recovery from, and extensions to, existing fields and discoveries of new fields. The subsidiary additions were through improved recovery from, and extensions to, existing fields and discoveries of new fields where they represented a mixture of proved developed and proved undeveloped reserves. Volumes added in 2020 principally resulted from the application of conventional technologies and extensions of field size by development drilling. The principal proved reserves additions in our subsidiaries by region were in the US, Oman, Azerbaijan and Angola. The principal reserves additions in our equity-accounted entities were in Rosneft and Pan American Energy Group. 16% of our proved reserves are associated with PSAs. The countries in which we produced under PSAs in 2020 were Algeria, Angola, Azerbaijan, Egypt, India, Indonesia and Oman. In addition, the technical service contract (TSC) governing our investment in the Rumaila field in Iraq functions as a PSA. The group holds no licences due to expire within the next three years that would have a significant impact on bp’s reserves or production. bp holds reserves classified as Assets held for sale in Oman. For further information on our reserves see page 238. 314 bp Annual Report and Form 20-F 2020 « See Glossary bp’s net production by country – crude oila and natural gas liquids Subsidiaries UKc d Total Europe Alaskac Lower 48 onshorec Gulf of Mexico deepwaterc Total US Canadae Total Rest of North America Total North America Trinidad & Tobago Total South America Angola Egyptc Algeria Total Africa Abu Dhabi Azerbaijan Iraq Oman Total Rest of Asia Total Asia Australia Eastern Indonesia Total Australasia Total subsidiaries Equity-accounted entities (bp share) Rosneftf (Russia, Venezuela) Abu Dhabi Additional disclosures thousand barrels per day bp net share of productionb 2020 2019 Crude oil 2018 2020 2019 Natural gas liquids 2018 96 96 38 72 235 345 22 22 367 7 7 108 9 6 123 158 97 100 21 375 375 13 2 15 983 100 100 71 66 263 400 24 24 424 7 7 115 34 7 156 180 79 64 20 343 343 101 101 106 18 261 385 24 24 408 7 7 147 49 9 204 169 72 54 17 313 313 15 2 17 1,046 16 2 17 1,051 5 5 — 59 20 79 — — 79 7 7 — — 8 8 — — — — — — 2 — 2 101 3 3 — 58 24 81 — — 81 9 9 — — 8 8 — — — — — — 2 — 2 104 5 5 — 37 23 60 — — 60 9 9 — — 11 11 — — — — — — 2 — 2 88 4 — — — — 3 2 — 3 12 100 3 — 1 — — 3 2 — 5 14 118 3 — 1 — — 2 3 — 5 14 115 873 — 52 0 2 — 50 30 1 1,009 1,991 920 — 54 — 2 — 35 35 1 1,047 2,093 919 16 52 — 3 — 34 14 1 1,040 2,091 Argentina Mexico Bolivia Egyptc Norway Russiac Angola Total equity-accounted entities Total subsidiaries and equity-accounted entitiesg a Includes condensate. b Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. c In 2020, bp disposed of its Alaska interests and certain Lower 48 onshore interests in the US. In 2019, bp completed the sale of its interest in the Gulf of Suez Petroleum Company (GUPCO) in Egypt and certain US assets in Lower 48 onshore and disposed of its interests in the Gulf of Mexico Santiago and Santa Cruz wells. In 2018, bp acquired various interests in the Permian Basin, Eagle Ford and Haynesville Shales in Lower 48 onshore as a result of the acquisition of BHP’s US unconventional assets, increased its interest in the Clair asset in the UK North Sea, and acquired an interest in LLC Kharampurneftegaz in Russia, and in certain US offshore assets. It also disposed of its interests in the Greater Kuparuk Area in Alaska, the Magnus field in the UK North Sea, and in certain other assets in the UK North Sea and US onshore assets. d Volumes relate to six bp-operated fields within ETAP. bp has no interests in the remaining three ETAP fields, which are operated by Shell. e All of the production from Canada in Subsidiaries is bitumen. f Includes production in respect of the non-controlling interest in Rosneft, including production held through bp’s interests in Russia other than Rosneft. g Includes 3 net mboe/d of NGLs from processing plants in which bp has an interest (2019 3mboe/d and 2018 3mboe/d). Because of rounding, some totals may not agree exactly with the sum of their component parts. « See Glossary bp Annual Report and Form 20-F 2020 315 bp’s net production by country – natural gas Subsidiaries UKb Total Europe Lower 48 onshoreb Gulf of Mexico deepwaterb Alaskab Total US Canada Total Rest of North America Total North America Trinidad & Tobago Total South America Egyptb Algeria Total Africa Azerbaijan India Oman Total Rest of Asia Total Asia Australia Eastern Indonesia Total Australasia Total subsidiariesc Equity-accounted entities (bp share) Rosneftd (Russia, Canada, Egypt, Vietnam) Argentina Bolivia Mexico Norway Russiab Angola Total equity-accounted entitiesc Total subsidiaries and equity-accounted entities million cubic feet per day bp net share of productiona 2020 2019 2018 221 221 1,405 154 3 1,561 2 2 1,563 1,695 1,695 782 141 923 413 2 550 966 966 396 399 795 6,163 1,286 230 56 0 61 41 92 1,765 7,929 129 129 2,175 179 4 2,358 2 2 2,361 1,977 1,977 952 186 1,138 367 15 594 976 976 411 375 786 7,366 1,279 250 64 — 56 — 87 1,736 9,102 152 152 1,705 190 5 1,900 7 7 1,907 2,136 2,136 878 183 1,061 256 32 538 826 826 437 382 819 6,900 1,286 264 71 — 59 — 80 1,760 8,659 a Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. b In 2020, bp disposed of its Alaska interests and certain Lower 48 onshore interests in the US. In 2019, bp completed the sale of its interest in the Gulf of Suez Petroleum Company (GUPCO) in Egypt and certain US assets in Lower 48 onshore and disposed of its interests in the Gulf of Mexico Santiago and Santa Cruz wells. In 2018, bp acquired various interests in the Permian Basin, Eagle Ford and Haynesville Shales in Lower 48 onshore as a result of the acquisition of BHP’s US unconventional assets, increased its interest in the Clair asset in the UK North Sea, and acquired an interest in LLC Kharampurneftegaz in Russia, and in certain US offshore assets. It also disposed of its interests in the Greater Kuparuk Area in Alaska, the Magnus field in the UK North Sea, and in certain other assets in the UK North Sea and US onshore assets. c Natural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group’s reserves. d Includes production in respect of the non-controlling interest in Rosneft, including production held through bp’s interests in Russia other than Rosneft. Because of rounding, some totals may not agree exactly with the sum of their component parts. 316 bp Annual Report and Form 20-F 2020 « See Glossary The following tables provide additional data and disclosures in relation to our oil and gas operations. Average sales price per unit of production (realizations«)a Additional disclosures Europe UK Rest of Europe North America US Rest of North America South America Africa Asia Russiab Rest of Asia $ per unit of production Total group average Australasia 42.70 25.31 3.13 65.44 29.58 4.01 71.28 31.63 7.71 — — — — — — — — — 38.14 10.22 1.30 26.70 — 1.70 42.27 16.49 1.86 41.60 25.39 3.89 59.19 14.67 1.93 40.92 — 0.75 63.30 25.86 2.78 63.75 31.89 4.59 67.11 25.81 2.43 33.57 — 0.83 69.17 35.74 3.08 68.81 39.14 4.82 — — — — — — — — — 37.76 — 3.91 33.21 24.73 4.66 64.39 — 3.99 59.65 38.11 6.86 70.80 — 3.85 67.54 52.14 7.97 — — — — — — — — — 40.00 — 3.76 64.75 — 5.01 70.24 — 7.93 — — — — — — — — — — — — — — — — — — 40.41 15.93 2.88 56.85 18.14 3.98 62.35 — 4.36 — — — — — — — — — 35.10 N/A 1.51 56.52 N/A 1.83 — — — — — — 62.51 N/A 1.70 39.49 — — — — — — — — — — — 38.46 12.91 2.75 61.56 18.23 3.39 67.81 29.42 3.92 35.94 15.93 1.85 56.96 18.14 2.38 62.29 — 2.50 Subsidiaries 2020 Crude oilc Natural gas liquids Gas 2019 Crude oilc Natural gas liquids Gas 2018 Crude oilc Natural gas liquids Gas Equity-accounted entitiesd 2020 Crude oilc Natural gas liquidse Gas 2019 Crude oilc Natural gas liquidse Gas 2018 Crude oilc Natural gas liquidse Gas Average production cost per unit of productionf Europe UK Rest of Europe North America US Rest of North America South America Africa Asia $ per unit of production Total group average Australasia Russiac Rest of Asia 12.49 13.22 13.76 — — — 8.11 8.46 9.63 12.46 13.36 13.10 3.76 3.36 3.08 7.71 7.95 7.31 — — — 4.41 5.15 5.72 2.02 2.33 2.35 6.39 6.84 7.15 Subsidiaries 2020 2019 2018 Equity-accounted entities 2020 2019 2018 a Units of production are barrels for liquids and thousands of cubic feet for gas. Realizations include transfers between businesses, except in the case of Russia. b An amendment has been made to 2019 and 2018 to align with the disclosures for oil and natural gas exploration and production activities. c Includes condensate. d In certain countries it is common for equity-accounted entities’ agreements to include pricing clauses that require selling a significant portion of the entitled production to local governments or markets 12.71 11.50 10.61 8.14 12.51 12.15 3.54 3.45 3.37 — — 5.92 — — — — — — — — — — — — — — — 4.55 4.50 4.38 at discounted prices. e Natural gas liquids for Russia are included in crude oil. f Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes. « See Glossary bp Annual Report and Form 20-F 2020 317 Additional information for Downstream Refinery throughputsa b Retail sitesa US Europe Rest of the world Total 2020 693 742 192 1,627 2019 737 787 225 1,749 Refining availability« 96.0 94.9 a This does not include bp’s interest in Pan American Energy Group. b Refinery throughputs reflect crude oil and other feedstock volumes. Sales volume Marketing salesa Trading/supply salesb Total refined product sales Crude oilc Total 2020 2,275 3,026 5,301 2,397 7,698 2019 2,727 3,268 5,995 2,713 8,708 thousand barrels per day 2018 703 781 241 1,725 % 95.0 thousand barrels per day 2018 2,736 3,194 5,930 2,624 8,554 a Marketing sales include branded and unbranded sales of refined fuel products and lubricants to business-to-business and business-to-consumer customers, including service station dealers, jobbers, airlines, small and large resellers such as hypermarkets, and the military. b Trading/supply sales are fuel sales to large unbranded resellers and other oil companies. c Crude oil sales relate to transactions executed by our integrated supply and trading function, primarily for optimizing crude oil supplies to our refineries and in other trading. 2020 includes 44 thousand barrels per day relating to revenues reported by the Upstream segment. Sales volumes reported in the table above are for those transactions that are reported as gross sales in the group income statement. From 2021, certain sales and purchase transactions that have previously been reported gross in the group income statement will be reported on a net basis in the income statement. The volumes for 2020 transactions that would have been subject to potential netting in the income statement but are presented gross in this table are approximately 2,063 thousand barrels a day of crude oil, 2,613 thousand barrels a day of trading/supply sales, and 126 thousand barrels a day of marketing sales. US Europe Rest of the world Total Number of bp-branded retail sites 2018 7,200 8,200 3,300 2020 7,300 8,200 4,800 2019 7,200 8,200 3,500 20,300 18,900 18,700 a Reported to the nearest 100. Includes sites operated by dealers, jobbers, franchisees, brand licensees or JV partners, under the bp brand. These may move to and from the bp brand as their fuel supply agreement or brand licence agreement expires and are renegotiated in the normal course of business. Retail sites are primarily branded bp, ARCO, Amoco, Aral and Thorntons, and also include sites in India through our Jio-bp JV. Reconciliation of RC profit before interest and tax to gross margin for convenience, retail fuels and electrification RC profit before interest and tax for Downstream Net (favourable) adverse impact of non- operating items« and fair value accounting effects« Underlying RC profit before interest and tax for Downstream Subtract underlying RC profit (loss) for petrochemicals, refining and trading, and lubricants Add back: 2020 3.4 $ billion 2019 6.5 (0.3) (0.1) 3.1 6.4 1.0 3.9 Fuels (excluding refining and trading) depreciation, depletion and amortization 1.0 1.0 Fuels (excluding refining and trading) production and manufacturing, distribution and administration expenses and adjusted for aviation, B2B and midstream gross margin Adjusted for earnings from equity- accounted entities in fuels (excluding refining and trading) Gross margin for convenience, retail fuels and electrification« Of which: Convenience gross margin Retail fuels gross margin Electrification gross margin 1.9 1.8 (0.2) (0.3) 4.8 1.3 3.5 0.0 5.0 1.2 3.7 0.0 318 bp Annual Report and Form 20-F 2020 « See Glossary Refinery capacity The following tablea summarizes bp group’s interests in refineries and average daily crude distillation capacities as at 31 December 2020. Additional disclosures Fuels value chain US US North West US East of Rockies Europe Rhine Iberia Rest of world Australia New Zealand Southern Africa Country Refinery US Cherry Point Whiting Toledo Germany Netherlands Spain Gelsenkirchen Lingen Rotterdam Castellón Australia New Zealand South Africa Kwinanad Whangareief Durbane Crude distillation capacitiesb Group interestc (%) BP share thousand barrels per day 100 100 50 100 100 100 100 100 10.1 50 251 440 80 771 265 97 390 110 862 152 34 90 276 1,909 Total bp share of capacity at 31 December 2020 a This does not include bp’s interest in Pan American Energy Group. b Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period under normal operational conditions. c bp share of equity, which is not the same as bp share of processing entitlements. d In the fourth quarter 2020, we announced plans to cease fuel production at our Kwinana Refinery and 𝅺convert it to an import terminal. e Indicates refineries not operated by bp. f Reflects bp share of processing entitlement, which is not the same as bp share of equity. « See Glossary bp Annual Report and Form 20-F 2020 319       presented its public statement regarding human rights and the Declaration on Human Rights for interacting with suppliers of goods, works and services. In February 2021,Rosneft and bp signed a Strategic Collaboration Agreement focused on 𝅺supporting carbon management and sustainability activities of both companies. The agreement builds on bp’s longstanding strategic partnership with Rosneft and will explore opportunities for new investment and collaboration in Russia across several key focus areas: • Developing industry methodologies and standards on carbon management, including methane reduction initiatives and energy efficiency applications. • Evaluating new projects in renewables, carbon capture and hydrogen. • Assessing opportunities in the downstream including advanced fuels, natural forest sinks and carbon offset credits. • Sustainable development and social investment, including biodiversity. Additional information for Rosneft About Rosneft Rosneft is the largest oil company in Russia, with a strong portfolio of current and future opportunities. Russia has one of the largest and lowest-cost hydrocarbon resource bases in the world and its resources play an important role in long-term energy supply to the global economy. Rosneft is one of the largest publicly traded oil companies in the world based on hydrocarbon production volume. And it has a major resource base of hydrocarbons onshore and offshore, with assets in all of Russia’s key hydrocarbon regions and abroad. bp's share of Rosneft hydrocarbon production in 2020 was 1,098mboe/d, compared with 1,144mboe/d in 2019. Rosneft is a member of the Methane Guiding Principles initiative that aims to reduce methane emissions along the natural gas value chain. It reaffirmed its commitment to the 17 UN Sustainable Development Goals and the core principles of the UN Global Compact. Rosneft is the leading Russian refining company based on throughput. It owns and operates 13 refineries in Russia and holds stakes in three refineries in Germany, one in India and one in Belarus. Rosneft refinery throughput in 2020 was 2,103mb/d, compared with 2,236mb/d in 2019. Downstream operations include jet fuel, bunkering, bitumen and lubricants. Rosneft also owns and operates over 3,055 retail service stations in Russia and abroad. These includes Rosneft-branded sites, as well as bp-branded sites operating under a licensing agreement. Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is wholly owned by the Russian government. At 31 December 2020, Rosneftegaz held 40.4% (2019: 50% plus one share) of the voting share capital of Rosneft. 2020 summary bp remains committed to our strategic investment in Rosneft, while complying with all relevant sanctions. bp’s two nominees, Bernard Looney and Bob Dudley, were elected to Rosneft’s board at Rosneft's annual general meeting (AGM) in June. Bob Dudley is a chairman of the Rosneft board’s Strategy and Sustainable Development Committee. At the AGM, shareholders also approved a resolution to pay a dividend. bp received a payment of $480 million, after the deduction of withholding tax, in July. On 30 April, Rosneft completed a transaction to transfer all of its interest and cease participation in its Venezuelan businesses to a company owned by the government of the Russian Federation. In consideration, it received shares equal to a 9.6% share of its own equity. The shares are held by a 100% subsidiary of Rosneft and accounted for as treasury shares. Rosneft also has an approved programme of share buybacks under which shares are being repurchased. Those shares are also accounted for as treasury shares. bp retains 19.75% of the voting rights at meetings of Rosneft shareholders and continues to be entitled to dividends based on that shareholding. bp’s economic interest as of 31 December 2020, however, has increased to 22.03% as a result of its indirect interest in the shares held by the subsidiaries of Rosneft. bp’s share of profit or loss of Rosneft reflects its economic interest. On 14 December 2020, Rosneft announced the sale of a 49% stake in Krasgeonats to Equinor for approximately $550 million. Krasgeonats owns 12 licences for exploration and production in Eastern Siberia, including the recently launched North-Danilovskoye field. On 28 December, Rosneft announced completion of the acquisition of 100% stakes in JSC Taimyrneftegaz and LLC Taimyrburservis, and the sale of a 10% interest in LLC Vostok Oil to Trafigura for Euro 7 billion. In December, Rosneft announced that it has developed a 2035 Carbon Management Plan, a long-term framework for its development in the context of transitioning to a low carbon economy, including management of climate risks and identification of opportunities related to future energy demand. 2020 marked the 10th anniversary of Rosneft’s participation in UN Global Compact, the world’s largest sustainability initiative. In 2020, Rosneft 320 bp Annual Report and Form 20-F 2020 « See Glossary Environmental expenditure Operating expenditure Capital expenditure Clean-ups Additions to environmental remediation provision Increase (decrease) in 2020 531 241 29 2019 511 468 23 $ million 2018 501 449 31 297 272 428 decommissioning provision (686) 1,045 137 Operating and capital expenditure on the prevention, control, treatment or elimination of air and water emissions and solid waste is often not incurred as a separately identifiable transaction. Instead, it forms part of a larger transaction that includes, for example, normal operations and maintenance expenditure. The figures for environmental operating and capital expenditure in the table are therefore estimates, based on the definitions and guidelines of the American Petroleum Institute. Environmental operating expenditure of $531 million in 2020 (2019 $511 million) showed an overall increase of 4%, with increases in BP Products and Shipping expenditure largely balanced out by a reduction in expenditure for BPX Energy. Environmental capital expenditure of $241 million in 2020 was significantly down (2019 $468 million) largely due to decreased expenditure in the BPX Energy and BP Products North America business. Clean-up costs were $29 million in 2020 (2019 $23 million) representing oil spill clean-up costs and other associated remediation and disposal costs. The increase compared to 2019 results largely from increased expenditure in three businesses, namely BP Pipelines (North America), Alaska and Remediation Management. In addition to operating and capital expenditure, we also establish provisions for future environmental remediation work. Expenditure against such provisions normally occurs in subsequent periods and is not included in environmental operating expenditure reported for such periods. Provisions for environmental remediation are made when a clean-up is probable and the amount of the obligation can be reliably estimated. Generally, this coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The extent and cost of future environmental restoration, remediation and abatement programmes are inherently difficult to estimate. They often depend on the extent of contamination, and the associated impact and timing of the corrective actions required, technological feasibility and bp’s share of liability. Though the costs of future programmes could be significant and may be material to the results of operations in the period in which they are recognized, it is not expected that such costs will be material to the group’s overall results of operations or financial position. Additions to our environmental remediation provision was similar to prior years and also reflects scope reassessments of the remediation plans of a number of our sites in the US. The charge for environmental remediation provisions in 2020 included $8 million in respect of provisions for new sites (2019 $9 million and 2018 $8 million). In addition, we make provisions on installation of our oil and gas producing assets and related pipelines to meet the cost of eventual decommissioning. On installation of an oil or natural gas production facility, a provision is established that represents the discounted value of the expected future cost of decommissioning the asset. In 2020, the net decrease in the decommissioning provision was due to a change in the discount rate and a change in cost estimate assumptions. We undertake periodic reviews of existing provisions. These reviews take account of revised cost assumptions, changes in decommissioning requirements and any technological developments. Provisions for environmental remediation and decommissioning are usually established on a discounted basis, as required by IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’. Further details of decommissioning and environmental provisions appear in Financial statements – Note 23. Additional disclosures Regulation of the group’s business Our businesses and operations are subject to the laws and regulations applicable in each country, state or other regional or local area in which they occur. These cover virtually all aspects of bp’s activities and include matters such as licence acquisition, production rates, royalties, environmental, health and safety protection, fuel specifications and transportation, trading, pricing, anti-trust, export, taxes, and foreign exchange. Oil and gas contractual and regulatory framework The terms and conditions of the leases, licences and contracts under which our upstream oil and gas interests are held vary from country to country. These leases, licences and contracts are generally granted by or entered into with a government entity or state-owned or controlled company and are sometimes entered into with private property owners. Arrangements with governmental or state entities usually take the form of licences or production-sharing agreements« (PSAs), although arrangements with private entities and the US government entities are usually by lease. Licences (or concessions) give the holder the right to explore for, develop and produce a commercial discovery. Under a licence, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the licence holder is entitled to all production, minus any royalties that are payable in kind. A licence holder is generally required to pay production taxes or royalties, which may be in cash or in kind. In certain countries, separate licences are required for exploration and production activities, and in some cases production licences are limited to only a portion of the area covered by the original exploration licence. PSAs entered into with a government entity or state-owned or controlled company generally require bp (alone or with other contracting companies) to provide all the financing and bear the risk of exploration and production activities in exchange for a share of the production remaining after royalties, if any. Less typically, bp may explore for, develop and produce hydrocarbons under a service agreement with the host entity in exchange for reimbursement of costs and/or a fee paid in cash rather than production. bp frequently conducts its exploration and production activities in joint arrangements« or co-ownership arrangements with other international oil companies, state-owned or controlled companies and/or private companies. Conventionally, all costs, benefits, rights, obligations, liabilities and risks incurred in carrying out joint arrangement or co-ownership operations under a lease, licence or PSA are shared among the joint arrangement or co-owning parties according to agreed ownership interests among them. To the extent that any liabilities arise, whether to governments or third parties, or as between the joint arrangement parties or co-owners themselves, each joint arrangement party or co-owner will generally be liable to meet these in proportion to its ownership interest. In many upstream operations, a party (known as the operator) will be appointed (pursuant to a joint operating agreement) to carry out day to-day operations on behalf of the joint arrangement or co-ownership. The operator is typically one of the joint arrangement parties or a co- owner and will carry out its duties either through its own staff, or by contracting out various elements to third-party contractors or service providers. bp acts as operator on behalf of joint arrangements and co- ownerships in a number of countries. Frequently, work (including drilling and related activities) will be contracted out to third-party service providers. The relevant contract will specify the work, the remuneration, and typically the risk allocation between the parties. Depending on the service to be provided, the contract may also contain provisions allocating risks and liabilities associated with pollution and environmental damage, damage to a well or hydrocarbon reservoirs and for claims from third parties or other losses. The allocation of those risks vary among contracts and are determined through negotiation between the parties. « See Glossary bp Annual Report and Form 20-F 2020 321 In general, bp incurs income tax on income generated from production activities (whether under a licence or PSA). In addition, depending on the area, bp’s production activities may be subject to a range of other taxes, levies and assessments, including special petroleum taxes and revenue taxes. The taxes imposed on oil and gas production profits and activities may be substantially higher than those imposed on other activities, for example in Abu Dhabi, Angola, Egypt, Norway, the UK, the US, Russia and Trinidad & Tobago. Sustainable finance On 12 July 2020, elements of Regulation (EU) 2020/852 on the establishment of a framework to facilitate sustainable investment (Taxonomy Regulation) entered into force and form part of UK law pursuant to the European Union (Withdrawal) Act of 2018. The Taxonomy Regulation establishes a classification system for determining whether an economic activity is environmentally sustainable for the purposes of guiding investors in financial products which are marketed as promoting environmental objectives. Although the UK government has expressed its intention to retain the overall taxonomy framework and objectives as set forth in the Taxonomy Regulation, it is not yet clear to what extent UK law will align with elements of the Taxonomy Regulation which were not in effect as of the end of the Brexit transition period on 31 December 2020. bp may in the future be required to comply with the Taxonomy Regulation or any parallel or similar legislation which may come into force in the UK. Greenhouse gas regulation In December 2015, nearly 200 nations at the United Nations climate change conference in Paris (COP21) agreed the Paris Agreement which aims to hold the increase in the global average temperature to well below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5°C above pre-industrial levels. Signatories aim to reach global peaking of greenhouse gas (GHG) emissions as soon as possible and to undertake rapid reductions thereafter, so as to achieve a balance between human caused emissions and removals by sinks of GHGs in the second half of this century. The Paris Agreement commits all signatories to submit Nationally Determined Contributions (NDCs) (i.e. pledges or plans of climate action) and pursue domestic measures aimed at achieving the objectives of their NDCs. Signatories are required to submit revised NDCs every five years, and the revised NDC’s are expected to be more ambitious with each revision. Global assessments of progress will occur every five years, starting in 2023. Agreement of rules which could enable international carbon trading to assist in meeting NDCs, has been deferred to COP26 which is expected to take place in Glasgow, Scotland in November 2021. More stringent national and regional measures relating to the transition to a lower carbon economy, such as the UK's 2050 net zero carbon emissions commitment, can be expected in the future. These measures could increase bp’s production costs for certain products, increase compliance and litigation costs, increase demand for competing energy alternatives or products with lower-carbon intensity, and affect the sales and specifications of many of bp’s products. Further, such measures could lead to constraints on production and supply and access to new reserves, particularly due to the long term nature of many of bp’s projects. Certain current and announced GHG measures and developments potentially affecting bp’s businesses in various markets in which bp operates are summarized below. For information on steps that bp is taking in relation to climate change issues and for details of bp’s GHG reporting, see Sustainability – Net zero aims on page 49. United States In the US, bp's operations are affected by GHG regulation in a number of ways. The federal Clean Air Act (CAA), for example, regulates air emissions, permitting, fuel specifications and other aspects of our production, refining, distribution and marketing activities. Environmental Protection Agency (EPA) regulations aimed at limiting methane emissions from new and modified sources in the oil and natural gas sector in the US by 40-45% from 2012 levels by 2025 were the subject of an August 2020, EPA final ‘policy rule’ intended to significantly revise that regulation. This rule is the subject of litigation in the D.C. Circuit. In addition, the Bureau of Land Management (BLM) in 2018 issued a new waste prevention rule which rescinded the prior 2017 rule regarding methane regulation on federal lands. While litigation around both rules is expected to continue, the Biden administration has taken executive action with respect to Federal regulations promulgated during the Trump administration relating to climate change, including a review of both of these rules. Other EPA GHG regulations which may affect electricity generation practices and prices and have an impact on the market for fuels used to generate electricity and on renewable energy installations are in flux due to changes in approach between presidential administrations, as well as lawsuits challenging proposed regulations. In 2019, the EPA issued the final Affordable Clean Energy (ACE) Rule, which is intended to address GHG emissions from certain existing sources in the electricity sector, and which is intended to replace the Obama administration’s Clean Power Plan (CPP). A number of lawsuits have been filed regarding the legality of the ACE Rule and the repeal of the CPP regulations, and on 19 January 2021, the DC Circuit struck down the ACE rule in its entirety. The Biden administration may develop new regulations that more closely mirror the CPP. The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 impose the Renewable Fuel Standard (RFS), requiring transportation fuel sold in the United States to contain a minimum volume of renewable fuels. Certain state initiatives impose lower GHG emissions thresholds for transportation fuels (e.g., in California and Oregon). In 2020, EPA changed its approach to Small Refinery Exemptions based on court activity. EPA is behind schedule in setting RFS requirements for 2021 and we expect the administration to begin the process of setting 2023 and beyond volumes in 2021 as well. The GHG mandatory reporting rule, requires operators of certain facilities and producers and importers/exporters of petroleum products to file annual GHG emissions reports with the EPA quantifying direct emissions from affected facilities, as well as volumes of petroleum products, certain natural gas liquids and GHG products and notional GHG emissions as if these products were fully combusted. A number of states, municipalities and regional organizations have responded to current and proposed federal changes easing environmental regulation with separate initiatives that affect our US operations. For example, the California cap and trade programme started in January 2012 and expanded to cover emissions from transportation fuels in 2015. The State of Washington has adopted a carbon cap rule although the state’s Supreme Court has modified the rule to exclude coverage of sales and distribution of petroleum fuels. We expect a number of states to advance economy-wide and transport/fuels specific regulations in 2021. Our US businesses are subject to increased GHG and other environmental requirements and regulatory uncertainty, including that the Biden or any future US administrations could revise or revoke current or prior administration programs, as well as increased expenditures in having to comply with numerous diverse and non- uniform regulatory initiatives at the state and local level. US fuel markets are affected by EPA regulation of light, medium and heavy duty vehicle emissions (both fuel economy and tailpipe standards) as well as for non-road engines and vehicles and certain large GHG stationary emission sources. California also imposes Low Emission Vehicle (LEV) and Zero Emission Vehicle (ZEV) standards on vehicle manufacturers and a number of other states, as allowed by CAA authority, have adopted standards identical to California’s standards. These regulations may impact bp’s product mix and demand for particular products in those states. In August 2020, California also entered into agreements with several carmakers to meet more demanding emissions standards in California. In 2019 the Trump administration issued the Safer Affordable Fuel- Efficient Vehicles rule rolling back the Obama administration’s fuel economy and tailpipe carbon dioxide emissions standards for passenger cars and light trucks covering model years (MY) 2021 through 2026 by locking in the 2020 standards until 2026. It has also proposed eliminating the waiver allowing California to set its own LEV and ZEV standards and for other states to adopt those standards. Litigation challenging these regulations is ongoing although the Biden 322 bp Annual Report and Form 20-F 2020 « See Glossary administration is expected to restore the California waiver and commence rulemaking to reinstate the stricter fuel economy and tailpipe carbon dioxide emissions standards. In January 2020, EPA solicited on a proposed rulemaking known as the Cleaner Trucks Initiative. The rule would, among other things, establish new emission standards for oxides of nitrogen (NOx) and other pollutants for highway heavy-duty engines and the Biden administration is expected to modify and continue this proposed rulemaking. California has also adopted a “Heavy-Duty Low NOx Omnibus Regulation” which will require manufacturers to comply with stricter emissions standards. The rule is being phased in, with the first phase effective in 2024. bp continues to monitor these rules for implications for fuels. European Union • The EU and its member states have adopted various measures seeking to reduce GHG emissions and encourage renewables. A set of regulatory measures adopted by the EU include: a collective national reduction target for emissions not covered by the EU Emissions Trading System (EU ETS) Directive; binding national renewable energy targets (including targets in the transport sector) under the Renewable Energy Directive; and a legal framework to promote carbon capture and storage. • In 2014, EU leaders adopted a climate and energy framework setting targets for the year 2030 including at least 40% reductions in GHG emissions from 1990 levels and in December 2020 the Council agreed an increase to a 55% reductions target from 1990 levels which is pending before the European Parliament. • In December 2019, the European Commission proposed an ambitious ‘European Green Deal’. These proposals, which require formal approval by EU Member States to be adopted and include climate neutrality and increased GHG reduction targets, tightening of the emissions caps in the EU ETS, extending the EU ETS to include the maritime sector and reducing allowances allocated to airlines, implement a carbon border tax adjustment and harmonise energy taxation across the EU Member States. • In October 2020 the European Commission presented an EU strategy to reduce methane emissions. The strategy sets out measures to cut methane emissions in Europe and internationally. It presents legislative and non-legislative actions in the energy, agriculture and waste sectors, which account for around 95% of methane emissions associated with human activity worldwide. • European regulations also establish passenger car performance standards for CO2 tailpipe emissions (European Regulation (EC) No 443/2009). By 2021, the European passenger fleet emissions target for new vehicles will be 95 grams of CO2 per kilometre. This target will be achieved by manufacturing fuel efficient vehicles and vehicles using alternative, low carbon fuels such as hydrogen and electricity. • In 2019, the European Parliament and the Council adopted Regulation (EU) 2019/631 setting CO2 emission performance standards for new passenger cars and for new light commercial vehicles (vans) in the EU for the period after 2020. From a 2021 baseline, it requires EU fleet- wide reductions of 15% by 2025 and 37.5% by 2030 for passenger cars, and 15% by 2025 and 31% by 2030 for new light commercial vehicles. • The EU Fuel Quality Directive affects our production and marketing of transport fuels including mandating reductions in the life cycle GHG emissions per unit of energy and tighter environmental fuel quality standards for petrol and diesel. • Germany is expected to launch a national emissions trading system in 2021 for transport and heating fuels. Impacted fuel suppliers in Germany will pay a fixed price for emissions certificates of EUR 25 per tonne CO2 in 2021 rising to EUR 55 per tonne by 2025. In 2026, emissions certificates will be auctioned but with prices limited between EUR 55 and EUR 65 per tonne CO2 emitted. A review of the system is expected to take place in 2025 to determine the position beyond 2026. Other • In December 2020 the UK Government announced a targeted reduction in the UK’s GHG emissions of at least 68% by 2030, compared to 1990 levels. The UK also announced an emissions trading system from 1 Additional disclosures January 2021 onwards which would include the same installations in the UK that were previously subject to the EU ETS. • China is operating emission trading pilot programmes in five cities and three provinces. One of bp's subsidiaries« and one of bp’s joint venture« companies in China are participating in these schemes. China launched its national emissions trading market (National ETS), initially covering the power sector only, politically in 2017. On 31 December 2020, China promulgated the national regulation on National ETS which became effective on 1 February 2021, when the National ETS was officially launched. • China has also adopted more stringent vehicle tailpipe emission standards and vehicle efficiency standards to address air pollution and GHG emissions. These standards will have an impact on transportation fuel product mix and overall demand. In addition, China has also introduced a mandate for sales of new energy vehicles (NEVs) commencing in 2020. This has been accelerating NEV penetration into the light vehicle sector and impact light fuel demand. Other environmental regulation In addition to GHG regulations including current and proposed fuel and product specifications and emission controls (including control of vehicle emissions) referred to above, climate change programmes and regulation of unconventional oil and gas extraction under a number of environmental laws may have a significant effect on the production, sale and profitability of many of bp’s products. Environmental laws also require bp to remediate and restore areas affected by the release of hazardous substances or hydrocarbons associated with our operations or properties. These laws may apply to sites that bp currently owns or operates, sites that it previously owned or operated, or sites used for the disposal of its and other parties’ waste. See Financial Statements – Note 23 for information on provisions for environmental restoration and remediation. A number of pending or anticipated governmental proceedings against certain bp group companies under environmental laws could result in monetary or other sanctions. Group companies are also subject to environmental claims for personal injury and property damage alleging the release of, or exposure to, hazardous substances. The costs associated with future environmental remediation obligations, governmental proceedings and claims could be significant and may be material to the results of operations in the period in which they are recognized. We cannot accurately predict the effects of future developments, such as stricter environmental laws and regulations or enforcement policies, or future events at our facilities, on the group, and there can be no assurance that material liabilities and costs will not be incurred in the future. For a discussion of the group’s environmental expenditure, see page 321 and for a discussion of legal proceedings, see page 226. Significant legislation and regulation in the US and the EU affecting our businesses and profitability, in addition to those referred to above, include the following: United States • The Clean Water Act regulates wastewater and other effluent discharges from bp’s facilities, and bp is required to obtain discharge permits, install control equipment and implement operational controls and preventative measures. • The Resource Conservation and Recovery Act regulates the generation, storage, transportation and disposal of wastes associated with our operations and can require corrective action at locations where such wastes have been disposed of or released. bp has incurred, or is likely to incur, liability under RCRA or similar state laws in connection with sites bp operates or previously operated. • The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) can, in certain circumstances, impose the entire cost of investigation and remediation on a party who owned or operated a site contaminated with a hazardous substance, or who arranged for disposal of a hazardous substance at a site. bp has incurred, or is likely to incur, liability under CERCLA or similar state laws, including costs attributed to insolvent or unidentified parties. bp is also subject to claims for remediation costs and natural resource damages under CERCLA and other federal and state laws. « See Glossary bp Annual Report and Form 20-F 2020 323 • The Emergency Planning and Community Right-to-Know Act requires reporting on the storage, use and releases of certain quantities of listed hazardous substances to designated government agencies. • The Toxic Substances Control Act (TSCA) regulates bp’s manufacture, import, export, sale and use of chemical substances and products. In addition, EPA has revised processes and procedures for prioritisation of existing chemicals for risk evaluation, assessment and management. Agency actions and announcements are monitored regularly to identify developments with potential impacts on chemical substances important to bp products and operations. Thus far, bp has identified two substances for specific ongoing monitoring of developments and impacts. • The Occupational Safety and Health Act imposes workplace safety and health requirements on bp operations along with significant process safety management obligations, requiring continuous evaluation and improvement of operational practices to enhance safety and reduce workplace emissions at gas processing, refining and other regulated facilities. • The Oil Pollution Act 1990 (OPA) imposes operational requirements, liability standards and other obligations governing the transportation of petroleum products in US waters. States may impose additional obligations. Alaska and the West Coast states currently have the most demanding state requirements. • The Outer Continental Shelf Land Act, the Mineral Leasing Act and other statutes give the Department of Interior (DOI) and the BLM authority to regulate operations and air emissions, including equipment and testing, on offshore and onshore operations on federal lands subject to DOI authority. • The Endangered Species Act (ESA) and Marine Mammal Protection Act protect certain species’ habitats from adverse human impacts by restricting operations or development at certain times and in certain places. In 2020, the US Fish and Wildlife Service published two proposed rules impacting designations under ESA, but on 20 January 2021 the Biden administration announced a review of these proposed rules reducing the scope of habitat protections. European Union • The Industrial Emissions Directive (IED) 2010 provides the framework for granting permits for major industrial sites. It lays down rules on integrated prevention and control of air, water and soil pollution arising from industrial activities. As part of the IED framework, additional emission limit values are informed by sector specific and cross-sector Best Available Technology (BAT) Conclusions. These include the BAT Conclusions for the refining sector, for large combustion plants as well as common wastewater and waste gas treatment and management systems in the chemical sector. These may require bp to further reduce its emissions, particularly its air and water emissions. • The EU Regulation on substances that deplete the ozone layer 2009 (ODS Regulation) requires companies to reduce the use of ozone depleting substances (ODSs) and phase out use of certain ODSs. bp continues to replace ODSs in refrigerants and/or equipment in the EU and elsewhere, in accordance with the Montreal Protocol and related legislation. • The Medium Combustion Plants Directive 2015 (MCPD) regulates sulphur dioxide (SO2), nitrogen oxides (NOx) and particulates emissions and monitoring of carbon monoxide (CO) emissions from certain mid- size plants. It applies to new plants and by 2025 or 2030 to existing plants, depending on their size. • The National Emission Ceilings Directive 2016 (NECD) introduces stricter emissions limits from 2020 and 2030, with new indicative national targets applying from 2025. NECD has been implemented in the UK by the National Emission Ceilings Regulations 2018. Each EU Member State was also required to produce a National Air Pollution Control Programme setting out the measures it will take to ensure compliance with the 2020 and 2030 reduction commitments. • The EU Registration, Evaluation Authorization and Restriction of Chemicals (REACH) Regulation 2006 requires registration of chemical substances manufactured in or imported into the EU, together with the submission of relevant hazard and risk data. REACH affects our manufacturing or trading/import operations in the EU. bp maintains compliance by checking whether imports are covered by the registrations of non-EU suppliers’ representatives, preparing and submitting registration dossiers to cover new manufactured and imported substances, and updating previously submitted registrations as required. Some substances registered previously, including substances supplied to us by third parties for our use, are now subject to evaluation and review for potential authorization or restriction procedures, and possible banning, by the European Chemicals Agency and EU Member State authorities. In addition, bp’s facilities and operations in several EU countries continue to undergo REACH compliance inspections by the competent authority for the respective EU Member State. An amendment to the Annex of the Regulation on classification, labelling and packaging of substances and mixture (CLP Regulation) requires harmonized notification of information on hazardous materials (certain lubricant and fuel formations) to EU Member State poison centres. The uniform notification rules apply as of January 2020 for consumer products, from 2021 for professional and 2024 for industrial uses. • The EU Offshore Safety Directive was adopted in 2013. Its purpose is to introduce a harmonized regime aimed at reducing the potential environmental, health and safety impacts of the offshore oil and gas industry throughout EU waters. The Directive has been implemented in the UK primarily through the Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations 2015. • The Water Framework Directive (WFD) published in 2000 aims to protect the quantity and quality of ground and surface waters of the EU Member States. The implementation in the EU Member States is still ongoing, planned to be finalised by 2027. A Fitness Check (comprehensive policy evaluation) of the EU Water Legislation launched in 2019 concluded that the WFD is broadly fit for purpose. Future proceedings on the determination of pollutants/priority substances as well as environmental quality standards in line with the WFD may require additional compliance efforts and increased costs for managing freshwater withdrawals and discharges from bp’s EU operations. United Kingdom Following the UK’s exit from the European Union on 31 January 2020, the UK entered a transition period which ran until 31 December 2020. During the transition period, most EU law continued to apply to the UK and therefore to bp’s UK business during that period. From 1 January 2021, operative EU laws were retained in UK law by the European Union (Withdrawal) Act 2018. The vast majority of environment related statutory instruments passed by the UK Government in anticipation of Brexit have included no substantive changes to the current EU underlying regime, but rather seek to make the amendments required to allow their continued operation after the transition period. The UK Government’s Environment Bill and 25 Year Plan will be central to the UK’s environmental regime going forward but further changes are as yet uncertain. Other countries and regions Regulations governing the discharge of treated water have also been developed in countries outside of the US and EU. This includes regulations in Trinidad and Angola which impacts bp’s production operations in those countries. In Trinidad, bp commissioned a new waste water treatment plant in 2020 to meet consent levels agreed with the regulators to apply water discharge rules arising from the Certificate of Environmental Clearance (CEC) Regulations 2001 and associated Water Pollution Rules 2007. In Angola, bp has upgraded produced water treatment systems to meet revised oil in water limits for produced water discharge under Executive Decree ED 97-14. The Abidjan Convention, along with the Additional Protocol published in 2012, sets environmental quality standards for the discharge of chemicals to the marine environment. The convention and associated protocols has been ratified by 19 African nations including Senegal and Mauritania. bp is currently constructing the offshore facilities to include produced water management systems to meet the environmental quality standards for our future gas operations in Mauritania and Senegal. 324 bp Annual Report and Form 20-F 2020 « See Glossary Environmental maritime regulations bp’s shipping operations are subject to extensive national and international regulations governing operations, training, pollution prevention, liability, and insurance. These include: • Liability and spill prevention and planning requirements governing, among others, tankers, barges, and offshore facilities are imposed by OPA in US waters. OPA also mandates a levy on imported and domestically produced oil to fund oil spill responses. Some states, including Alaska, Washington, Oregon and California, impose additional liability for oil spills. Outside US territorial waters, bp shipping tankers are subject to international pollution prevention, liability, spill response and preparedness regulations developed through the UN’s International Maritime Organization (IMO), including the International Convention on Civil Liability for Oil Pollution Damage, the International Convention for the Prevention of Pollution from Ships (MARPOL), the International Convention on Oil Pollution, Preparedness, Response and Co-operation, and the International Convention on Civil Liability for Bunker Oil Pollution Damage. In April 2010, the Hazardous and Noxious Substance (HNS) Protocol 2010 was adopted to address issues that have inhibited ratification of the International Convention on Liability and Compensation for Damage in Connection with the Carriage of Hazardous and Noxious Substances by Sea 1996. As at 31 December 2020, the HNS Convention had not entered into force. • A global sulphur cap of 0.5% applies to marine fuel under MARPOL. In order to comply, ships either need to consume low sulphur marine fuels, operate on alternative low sulphur fuels such as LNG or implement approved abatement technology to enable them to meet the low sulphur emissions requirements while continuing to use higher sulphur fuel. This global cap does not alter the lower limits that apply in the sulphur oxides Emissions Control Areas established by the IMO. • The Convention for the Protection of the Marine Environment of the North-East Atlantic (OSPAR), aims to protect the marine environment of the North-East Atlantic. The OSPAR 2012 Recommendation and Guideline for the implementation of a risk- based approach to the management of produced water discharges from offshore installations in the North Sea supports a key goal of working towards eliminating harmful discharges. In 2020 the International Association of Oil and Gas Producers issued a report “Oil And Gas Risk Based Assessment of Offshore Produced Water Discharges” which presents industry good practice and aims to broaden the understanding and acceptance of Risk Based Assessment (RBA) techniques internationally and improve consistency in the application of assumptions, levels of conservatism, and selection of risk endpoints. To meet its financial responsibility requirements, bp Shipping maintains marine oil pollution liability insurance in respect of its operated ships to a maximum limit of $1 billion for each occurrence through mutual insurance associations (P&I Clubs), although there can be no assurance that a spill would necessarily be adequately covered by insurance or that liabilities would not exceed insurance recoveries. International trade sanctions During the period covered by this report, non-US subsidiaries«, or other non-US entities of BP, conducted limited activities in, or with persons from, certain countries identified by the US Department of State as State Sponsors of Terrorism or otherwise subject to US and EU sanctions (Sanctioned Countries). Sanctions restrictions continue to be insignificant to the group’s financial condition and results of operations. BP monitors its activities with Sanctioned Countries, persons from Sanctioned Countries and individuals and companies subject to US, EU and (following the end of the Brexit transition period) UK sanctions and seeks to comply with applicable sanctions laws and regulations. BP has a 28.83% interest in and operates the Shah Deniz field in Azerbaijan (Shah Deniz), has a 28.83% interest in and performs some operations for a related gas pipeline entity, South Caucasus Pipeline Company Limited (SCPC), and has a 23% non-operating interest in a related gas marketing entity, Azerbaijan Gas Supply Company Limited (AGSC). Naftiran Intertrade Co. Limited and NICO SPV Limited (collectively, NICO) have a 10% non-operating interest in each of Shah Additional disclosures Deniz and SCPC and an 8% non-operating interest in AGSC. Shah Deniz, SCPC and AGSC continue in operation as they were excluded from the application of US sanctions and fall within the exception for certain natural gas projects under Section 603 of the Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA). On 3 December 2018 BP entered into an agreement with, among others, SOCAR and NICO pursuant to which SOCAR pays to BP Exploration (Shah Deniz) Limited (BPXSD), as the Shah Deniz operator, compensation for NICO’s waiver of its right to lift its share of Shah Deniz condensate. Such amounts are used to cover cash calls to NICO in respect of operating costs due from NICO to BPXSD. On 26 October 2020, OFAC issued an amended licence in relation to these arrangements. Following the imposition in 2011 of further US and EU sanctions against Syria, BP terminated all sales of crude oil and petroleum products into Syria, though BP continues to supply aviation fuel to non-governmental Syrian resellers outside of Syria. BP has a joint arrangement in Cuba which imports, manufactures, markets and sells lubricants. During 2014, the US and the EU imposed sanctions on certain sectors of the Russian economy (energy, finance and defence/military) and on certain individuals and entities, including Rosneft. These sectoral sanctions include restrictions on the provision of financial assistance, technical assistance, and services in relation to exploration and production activity in deep water, shale, and offshore Arctic. Additional US sanctions have been imposed since 2014, broadening the scope of US sanctions on Russia-related activity to include certain international deep water, shale, and offshore Arctic projects as well as the provision of goods and services for Russian energy export pipelines. As of 1 January 2021, as a result of the UK’s exit from the EU, the UK has also imposed Russian-related sanctions, which are broadly similar to existing EU sanctions. We are not aware of any material adverse effect on our current income and investment in Russia or elsewhere as a consequence of these sanctions. BP maintains bank accounts and has registered and paid required fees to maintain registrations of patents and trademarks in certain Sanctioned Countries. BP has equity interests in non-operated joint arrangements« with air fuel sellers, resellers, and fuel delivery services around the world. From time to time, the joint arrangement operator or other partners may sell or deliver fuel to airlines from Sanctioned Countries or flights to Sanctioned Countries, without BP's involvement. BP has no control over the activities non-controlled associates« may undertake in Sanctioned Countries or with persons from Sanctioned Countries. Disclosure pursuant to ITRA Section 219 To our knowledge, none of BP’s activities, transactions or dealings are required to be disclosed pursuant to ITRA Section 219, with the following possible exceptions. On 17 July 2018, BP Iran Limited terminated its lease of an office in Tehran. The office had been used for administrative activities. In 2020, taxes with an aggregate US dollar equivalent value of approximately $20,000 were paid from a BP trust account held with Tadvin Co. to Iranian public entities. No gross revenues or net profits were attributable to these activities. BP has a 29.3% interest in Middle East Lubricants Company LLC (Melubco), which is established and manufactures lubricants in the United Arab Emirates. In May 2020, Melubco successfully appealed an Iranian court judgment obtained against it in absentia for non-payment of shipping fees. The applicant, an Iranian shipping company, had confused Melubco with an unrelated, but similarly named, Iranian entity. In order to do so, Melubco paid court filing fees equivalent to approximately $3,000 to the Tehran Judicial Services Office. Melubco does not, and has never, done business in Iran. « See Glossary bp Annual Report and Form 20-F 2020 325 Material contracts On 4 April 2016 the district court approved the Consent Decree among BP Exploration & Production Inc., BP Corporation North America Inc., BP p.l.c., the United States and the states of Alabama, Florida, Louisiana, Mississippi and Texas (the Gulf states) which fully and finally resolved any and all natural resource damages (NRD) claims of the United States, the Gulf states, and their respective natural resource trustees and all Clean Water Act (CWA) penalty claims, and certain other claims of the United States and the Gulf states. Concurrently, the definitive Settlement Agreement that bp entered into with the Gulf states (Settlement Agreement) with respect to State claims for economic, property and other losses became effective. bp has filed the Consent Decree and the Settlement Agreement as exhibits to its Annual Report on Form 20-F 2020 filed with the SEC. For further details of the Consent Decree and the Settlement Agreement, see Legal proceedings in bp Annual Report and Form 20-F 2015. Property, plant and equipment bp has freehold and leasehold interests in real estate and other tangible assets in numerous countries, but no individual property is significant to the group as a whole. For more on the significant subsidiaries« of the group at 31 December 2020 and the group percentage of ordinary share capital see Financial statements – Note 37. For information on significant joint ventures« and associates« of the group see Financial statements – Notes 16 and 17. Related-party transactions Transactions between the group and its significant joint ventures and associates are summarized in Financial statements – Note 16 and Note 17. In the ordinary course of its business, the group enters into transactions with various organizations with which some of its directors or executive officers are associated. Except as described in this report, the group did not have any material transactions or transactions of an unusual nature with, and did not make loans to, related parties in the period commencing 1 January 2020 to 2 March 2021. Corporate governance practices In the US, bp ADSs are listed on the New York Stock Exchange (NYSE). The significant differences between bp’s corporate governance practices as a UK company and those required by NYSE listing standards for US companies are listed as follows: Independence In 2020 bp continued to apply its board governance principles. These reflect the UK Corporate Governance Code approach to corporate governance. As such, the way in which bp makes determinations of directors’ independence differs from the NYSE rules. As set out on page 88, from 1 January 2021 bp has adopted terms of reference for the board and each of its committees. bp’s board governance principles require that all non-executive directors be determined by the board to be ‘independent in character and judgement and free from any business or other relationship which could materially interfere with the exercise of their judgement’. The bp board has determined that, in its judgement, all of the non-executive directors are independent. In doing so, however, the board did not explicitly take into consideration the independence requirements outlined in the NYSE’s listing standards. Committees bp has a number of board committees that are broadly comparable in purpose and composition to those required by NYSE rules for domestic US companies. For instance, bp has a remuneration (rather than a compensation) committee. bp also has an audit committee, which NYSE rules require for both US companies and foreign private issuers. These committees are composed solely of non-executive directors whom the board has determined to be independent, in the manner described above. The bp board governance principles prescribe the composition, main tasks and requirements of each of the committees (see the board committee reports on pages 92-102 and 105). Therefore, during 2020 bp did not have separate charters for each committee. As from the start of 2021 each of the board committees has adopted its own terms of reference which set out their respective roles and responsibilities. Under US securities law and the listing standards of the NYSE, bp is required to have an audit committee that satisfies the requirements of Rule 10A-3 under the Exchange Act and Section 303A.06 of the NYSE Listed Company Manual. bp’s audit committee complies with these requirements. The bp audit committee does not have direct responsibility for the appointment, reappointment or removal of the independent auditors. Instead, it follows the UK Companies Act 2006 and the UK Corporate Governance code 2018 by making recommendations to the board on these matters for it to put forward for shareholder approval at the AGM. One of the NYSE’s additional requirements for the audit committee states that at least one member of the audit committee is to have ‘accounting or related financial management expertise’. The board determined that Brendan Nelson possesses such expertise and also possesses the financial and audit committee experiences set forth in both the UK Corporate Governance Code and SEC rules (see Audit committee report on page 94). Mr Nelson is the audit committee financial expert as defined in Item 16A of Form 20-F. Shareholder approval of equity compensation plans The NYSE rules for US companies require that shareholders must be given the opportunity to vote on all equity-compensation plans and material revisions to those plans. bp complies with UK requirements that are similar to the NYSE rules. The board, however, does not explicitly take into consideration the NYSE’s detailed definition of what are considered ‘material revisions’. Code of ethics The NYSE rules require that US companies adopt and disclose a code of business conduct and ethics for directors, officers and employees. bp has adopted a code of conduct, which applies to all employees and members of the board, and has board governance principles that address the conduct of directors. In addition bp has adopted a code of ethics for senior financial officers as required by the SEC. bp considers that these codes and policies address the matters specified in the NYSE rules for US companies. Code of ethics The company has adopted a code of ethics for its group chief executive, chief financial officer, group controller, group head of audit and chief accounting officer as required by the provisions of Section 406 of the Sarbanes-Oxley Act of 2002 and the rules issued by the SEC. There have been no waivers from the code of ethics relating to any officers. bp also has a code of conduct, which is applicable to all employees, officers and members of the board. This was updated (and published) in July 2014. Controls and procedures Evaluation of disclosure controls and procedures The company maintains ‘disclosure controls and procedures’, as such term is defined in Exchange Act Rule 13a-15(e), that are designed to ensure that information required to be disclosed in reports the company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including the company’s group chief executive and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, our management, including the group chief executive and chief financial officer, recognize that any controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud within the company, if any, have been 326 bp Annual Report and Form 20-F 2020 « See Glossary detected. Further, in the design and evaluation of our disclosure controls and procedures our management necessarily was required to apply its judgement in evaluating the costs and benefits of possible control and procedure design options. Also, we have investments in unconsolidated entities. As we do not control these entities, our disclosure controls and procedures with respect to such entities are necessarily substantially more limited than those we maintain with respect to our consolidated subsidiaries«. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. The company’s disclosure controls and procedures have been designed to meet, and management believes that they meet, reasonable assurance standards. The company’s management, with the participation of the company’s group chief executive and chief financial officer, has evaluated the effectiveness of the company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b) as of the end of the period covered by this annual report. Based on that evaluation, the group chief executive and chief financial officer have concluded that the company’s disclosure controls and procedures were effective at a reasonable assurance level. Management’s report on internal control over financial reporting Management of bp is responsible for establishing and maintaining adequate internal control over financial reporting. bp’s internal control over financial reporting is a process designed under the supervision of the principal executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of bp’s financial statements for external reporting purposes in accordance with IFRS. As of the end of the 2020 fiscal year, management conducted an assessment of the effectiveness of internal control over financial reporting in accordance with the criteria in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting relating to internal control over financial reporting. Based on this assessment, management has determined that bp’s internal control over financial reporting as of 31 December 2020 was effective. The company’s internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with IFRS and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of bp; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of bp’s assets that could have a material effect on our financial statements. bp’s internal control over financial reporting as of 31 December 2020 has been audited by Deloitte LLP, an independent registered public accounting firm, as stated in their report appearing on page 154 of bp Annual Report and Form 20-F 2020. Changes in internal control over financial reporting There were no changes in the group’s internal control over financial reporting that occurred during the period covered by the Form 20-F that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. Principal accountant's fees and services The audit committee has established policies and procedures for the engagement of the independent registered public accounting firm, Deloitte LLP, to render audit and certain assurance services. The policies provide for pre-approval by the audit committee of specifically defined audit, audit-related, non-audit and other services that are not prohibited by regulatory or other professional requirements. Deloitte is engaged for these services when its expertise and experience of bp are important. Most of this work is of an audit nature. The committee regularly reviews Additional disclosures the policy, including in 2020, when it was updated to reflect changes resulting from the FRC Ethical Standard (December 2019). Under the policy, pre-approval is given for specific services within the following categories: advice on accounting, auditing and financial reporting matters; internal accounting and risk management control reviews (excluding any services relating to information systems design and implementation); non-statutory audit; project assurance and advice on business and accounting process improvement (excluding any services relating to information systems design and implementation relating to bp’s financial statements or accounting records); provision of, or access to, Deloitte publications, workshops, seminars and other training materials; provision of reports from data gathered on non-financial policies and information; provision of the independent third party audit in accordance with US Generally Accepted Government Auditing Standards, over the company’s Conflict Minerals Report – where such a report is required under the SEC rule ‘Conflict Minerals’, issued in accordance with Section 1502 of the Dodd Frank Act; and assistance with understanding non-financial regulatory requirements. bp operates a two-tier system for audit and non-audit services. For audit related services, the audit committee has a pre-approved aggregate level, within which specific work may be approved by management. Non-audit services are pre- approved for management to authorize per individual engagement, but above a defined level must be approved by the chairman of the audit committee or the full committee. In response to the revised regulatory guidelines of the UK Financial Reporting Council, the audit committee reviewed and updated its policies with effect from 1 January 2017 and in 2018 further updated its policies to clarify the engagement of the incoming auditor, Deloitte, and the outgoing auditor Ernst & Young to ensure independence. The defined maximum level for pre-approval has been reduced in line with FRC guidance on ‘non-trivial’ engagements. The audit committee has delegated to the chairman of the audit committee authority to approve permitted services provided that the chairman reports any decisions to the committee at its next scheduled meeting. Any proposed service not included in the approved service list must be approved in advance by the audit committee chairman and reported to the committee, or approved by the full audit committee in advance of commencement of the engagement. The audit committee evaluates the performance of the auditor each year. The audit fees payable to Deloitte are reviewed by the committee in the context of other global companies for cost effectiveness. The committee keeps under review the scope and results of audit work and the independence and objectivity of the auditor. External regulation and bp policy requires the auditor to rotate its lead audit partner every five years. See Financial statements – Note 36 and Audit committee report on page 94 for details of fees for services provided by the auditor. Directors’ report information This section of bp Annual Report and Form 20-F 2020 forms part of, and includes certain disclosures which are required by law to be included in, the Directors’ report. Indemnity provisions In accordance with BP’s Articles of Association, on appointment each director is granted an indemnity from the company in respect of liabilities incurred as a result of their office, to the extent permitted by law. These indemnities were in force throughout the financial year and at the date of this report. In respect of those liabilities for which directors may not be indemnified, the company maintained a directors’ and officers’ liability insurance policy throughout 2020. During the year, a review of the terms and scope of the policy was undertaken as part of the annual renewal. Although their defence costs may be met, neither the company’s indemnity nor insurance provides cover in the event that the director is proved to have acted fraudulently or dishonestly. Certain subsidiaries« are trustees of the group’s pension schemes. Each director of these subsidiaries is granted an indemnity from the company in respect of liabilities incurred as a result of such a subsidiary’s activities as a trustee of the pension scheme, to the extent permitted by law. These indemnities were in force throughout the financial year and at the date of this report. « See Glossary bp Annual Report and Form 20-F 2020 327 Financial risk management objectives and policies The disclosures in relation to financial risk management objectives and policies, including the policy for hedging, are included in How we manage risk on page 64, Liquidity and capital resources on page 306 and Financial statements – Notes 29 and 30. Exposure to price risk, credit risk, liquidity risk and cash flow risk The disclosures in relation to exposure to price risk, credit risk, liquidity risk and cash flow risk are included in Financial statements – Note 29. Important events since the end of the financial year Disclosures of the particulars of the important events affecting bp which have occurred since the end of the financial year are included in the Strategic report as well as in other places in the Directors’ report. Likely future developments in the business An indication of the likely future developments in the business of the company is included in the Strategic report. Research and development Indications of our activities in the field of research and development are provided throughout the Strategic report and the Directors’ report including examples on pages 16 (developing next-gen mobility solutions), 17 (driving digital innovation including through bp ventures and Launchpad), 19 (partnering to develop a project to produce hydrogen from water), 36 (innovation and engineering) and 63 (collaborating with universities and academic research). See also page 183 for our expenditure on research and development. Branches As a global group our interests and activities are held or operated through subsidiaries, branches, joint arrangements« or associates« established in – and subject to the laws and regulations of – many different jurisdictions. Employees Disclosures in respect of how the directors have engaged with employees and had regard to their interests are included in How the board has engaged with shareholders, the workforce and other stakeholders on page 86 and section 172 statement on pages 63, 82 and 83. The disclosures concerning policies in relation to the employment of disabled persons and employee involvement are included in Sustainability – People and society on page 57. Employee share schemes Certain shares held as a result of participation in some employee share plans carry voting rights. Voting rights in respect of such shares are exercisable via a nominee. Dividend waivers are in place in respect of unallocated shares held in employee share plan trusts. Suppliers, customers and others Disclosures in respect of how the directors have engaged with suppliers, customers and others in business relationships with the company are included in How the board has engaged with shareholders, the workforce and other stakeholders on page 86 and section 172 statement on pages 63, 82 and 83. Change of control provisions On 5 October 2015, the United States lodged with the district court in MDL 2179 a proposed Consent Decree between the United States, the Gulf states, BP Exploration & Production Inc., BP Corporation North America Inc. and BP p.l.c., to fully and finally resolve any and all natural resource damages claims of the United States, the Gulf states and their respective natural resource trustees and all Clean Water Act penalty claims, and certain other claims of the United States and the Gulf states. Concurrently, bp entered into a definitive Settlement Agreement with the five Gulf states (Settlement Agreement) with respect to state claims for economic, property and other losses. On 4 April 2016, the district court approved the Consent Decree, at which time the Consent Decree and Settlement Agreement became effective. The federal government and the Gulf states may jointly elect to accelerate the payments under the Consent Decree in the event of a change of control or insolvency of BP p.l.c., and the Gulf states individually have similar acceleration rights under the Settlement Agreement. For further details of the Consent Decree and the Settlement Agreement, see Legal proceedings in BP Annual Report and Form 20-F 2015. Greenhouse gas emissions, energy consumption and energy efficiency Disclosures in relation to greenhouse gas emissions, energy consumption and energy efficiency are included in Sustainability – on page 50. Disclosures required under Listing Rule 9.8.4R The information required to be disclosed by Listing Rule 9.8.4R can be located as set out below: Information required (1) Amount of interest capitalized (2) – (4) (5), (6) Waiver of director emoluments (7) – (11) (12), (13) Dividend waivers (14) Page 183 Not applicable 121 Not applicable 328 Not applicable 328 bp Annual Report and Form 20-F 2020 « See Glossary Cautionary statement In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general doctrine of cautionary statements, bp is providing the following cautionary statement. This document contains certain forecasts, projections and forward-looking statements - that is, statements related to future, not past, events and ircumstances - with respect to the financial condition, results of operations and businesses of bp and certain of the plans and objectives of bp with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, (i) certain statements in the Chairman’s letter (pages 4-5), the Group chief executive’s letter (pages 6-7), the Strategic report (inside cover and pages 1-70), Additional disclosures (pages 301-330) and Shareholder information (pages 331-340), including but not limited to statements under the headings ‘Our Energy Outlook’, ‘Reinventing bp – our business model’, ‘Reinventing bp – our strategic focus areas’, ‘Reinventing bp – our financial frame’, ‘2021 guidance’ and ‘Reinventing bp – in line with the Paris goals’ and including but not limited to statements regarding: plans and expectations relating to operating cash flow, capital expenditure (including total capital expenditure, organic capital expenditure and inorganic capital expenditure), maintaining a strong financial frame, deleveraging bp’s balance sheet, working capital and operating cash flows, liquidity, capital discipline, future sustainable free cash flow and shareholder distributions, allocation of capital to bp’s energy transition strategy, amount or timing of payments related to divestment proceeds, net debt, gearing and future dividend payments and share buybacks; bp’s ambition to be a net zero company by 2050 or sooner, including its aims regarding Scope 1, Scope 2 and Scope 3 emissions, its expectations for the energy transition and the carbon content of its oil and gas production, while operating a high- quality base business; bp’s plan to amplify value by focusing on integrating energy systems, partnering with countries, cities and industries, and driving digital innovation; expectations regarding medium and long-term oil prices, the consistency of pricing assumptions with scenarios that are consistent with the Paris goals and bp’s resilience to Paris-consistent pathways; expectations regarding world energy demand, including the growth in relative demand for renewables, oil and gas, and the proportional growth of renewables; expectations regarding bp’s short, medium- and long-term targets and aims for emissions and carbon intensity of bp’s production and marketed products, and statements regarding the resilience of bp’s strategy and portfolio across multiple climate scenarios and the uncertainties in the energy transition; plans and expectations regarding bp’s level of investment in energy sources and technologies other than oil and gas resources and reserves, including plans to increase investment in low carbon from around $750 million in 2020 to $3-4 billion by 2025 and to around $5 billion a year in 2030, with transition capital spend to be as much as 50% of capex in 2030; plans and expectations to significantly increase bp’s investment in low carbon activities in this decade, while also operating a high-quality base business; plans and expectations regarding bp’s five aims to get bp to net zero, including the aim to be net zero across its entire operations on an absolute basis by 2050 or sooner, the aim to be net zero on an absolute basis across the carbon in its upstream oil and gas production by 2050 or sooner, the aim to cut the carbon intensity of products sold by 50% by 2050 or sooner, the aim to install methane measurement at all existing major oil and gas processing sites by 2023, publish the data, and then drive a 50% reduction in methane intensity of operations, and the aim to increase the proportion of investment bp makes into its non-oil and gas businesses; plans and expectations regarding bp’s five aims to get the world to net zero carbon emissions, including the aim to more actively advocate for policies that support net zero, including carbon pricing, the aim to incentivize bp’s global workforce to deliver on these aims and mobilize them to become advocates for net zero, the aim to set new expectations for relationships with trade associations around the globe, the aim to be recognized as an industry leader for the transparency of its reporting and the aim to launch a new team to create integrated clean energy and mobility solutions; expectations with respect to oil and gas supply and demand and prices; expectations with respect to the world energy mix, production, consumption and emissions; plans and Additional disclosures expectations with respect to low carbon spend in 2021; expectations with respect to transition capital, and the percentage of capital expenditure that will be low-carbon; expectations that the aftermath of the pandemic will accelerate the pace of transition to a lower carbon economy and energy system; expectations that the Empire Wind project in New York state will have 2GW generating capacity once operational and Beacon Wind will have 2.4GW generating capacity once operational; expectations regarding future legislative or regulatory action related to greenhouse gases, including emissions disclosure, emissions trading, and fuel-specific regulations, and their impact on bp; expectations regarding pensions and other post-retirement benefits, including contributions; expectations regarding payments under contractual obligations and sales commitments; expectations that around 10,000 employees will leave bp by early 2022; plans and expectations regarding bp’s workforce, including bp’s targets regarding diversity, inclusion and equality; expectations regarding bp’s ability to prevent violations of its code of conduct, including its anti-bribery and corruption policies and procedures; plans and expectations regarding the new leadership structure and governance framework, including areas of focus and effectiveness; plans for incentivising bp’s global workforce; policies and goals related to risk management plans; plans and expectations regarding control deficiencies; expectations regarding bp’s ability to prevent, respond to and recover from cyberattacks or hostile actions; plans and projections regarding oil and gas reserves, including the turnover time of proved undeveloped reserves to proved developed reserves and volume of turnover; expectations regarding the costs of environmental restoration, remediation and abatement programmes; plans and expectations regarding bp’s portfolio, including to maintain a focused portfolio, to manage the portfolio through disciplined investment to support growing returns and to focus on highest-quality barrels; expectations that by 2030 bp’s hydrocarbon production will be around 40% lower relative to 2019 due to active management and high-grading of the portfolio, including divestment of non-core assets; plans and expectations that bp will not undertake exploration activity in new countries; expectations regarding contingent liabilities and their impact on bp; expectations regarding the future value of assets; expectations with respect to reserves bookings from new discoveries; plans and expectations with regard to the supply and trading function, the fuels and the lubricants businesses; plans and expectations with regard to new technologies, including their efficiency and impact on production; plans and expectations regarding sales commitments of bp and its equity-accounted entities; expectations regarding underlying production and capital investment; expectations with respect to ROACE and earnings before interest, tax, depreciation and amortisation; plans and expectations regarding investment, development, and production levels and the timing thereof with respect to projects and partnerships in Angola, Australia, Azerbaijan, Brazil, Egypt, the Gambia, India, Indonesia, Mexico, Russia, São Tomé and Príncipe, Turkey, Oman, the UK North Sea, the Gulf of Mexico, and the continental United States; expectations regarding refining margins; plans to undertake joint exploration and development with Rosneft and plans and expectations for the Strategic Collaboration Agreement signed between Rosneft and bp; expectations regarding future government action, regulations and policy, their impact on bp’s business and plans regarding compliance with such regulations; expectations regarding legal and trial proceedings, court decisions, potential investigations and civil actions by regulators, government entities and/ or other entities or parties, and the timing and potential impact of such proceedings and bp’s intentions in respect thereof; plans and expectations regarding relationships with governments, customers, partners, suppliers, communities and key stakeholders; plans to produce 900,000boe/d from new projects by 2021 and expectations regarding operating cash margins of this production; plans and expectations for bp’s Jio-bp joint venture with Reliance, including the expectation for 5,500 Jio-bp retail sites by 2025; plans and expectations to deliver 2021 financial targets; plans to increase investment in low carbon to $3-4 billion by 2025 and to around $5 billion a year in 2030; expectations related to delivery and execution of Atlantis Phase 3 in the US Gulf of Mexico; expectations regarding customer touchpoints, number of strategic convenience sites, number of retail sites in growth markets, Castrol sales and other operating revenues, number of electric vehicle charge points, margin share from convenience and electrification, unit production costs, Upstream production, Upstream plant reliability, refining throughout, refining availability, developed renewables to final investment decision, bioenergy production, LNG portfolio, and traded electricity; « See Glossary bp Annual Report and Form 20-F 2020 329 preferences; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; delays in the processes for resolving claims; amounts ultimately determined to be payable and the timing of payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; bp’s access to future credit resources; business disruption and crisis management; the impact on bp’s reputation of ethical misconduct and noncompliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft’s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; public health situations (including an outbreak of an epidemic or pandemic); wars and acts of terrorism; cyberattacks or sabotage; and other factors discussed elsewhere in this report including under Risk factors (pages 67-70). In addition to factors set forth elsewhere in this report, those set out above are important factors, although not exhaustive, that may cause actual results and developments to differ materially from those expressed or implied by these forward- looking statements. Statements regarding competitive position Statements referring to bp’s competitive position are based on the company’s belief and, in some cases, rely on a range of sources, including investment analysts’ reports, independent market studies and bp’s internal assessments of market share based on publicly available information about the financial results and performance of market participants. expectations regarding oil prices, including for long-term prices to be affected by the enduring impact of the COVID-19 pandemic, the decisions of OPEC+, confidence in efforts to manage the rollout of vaccination and further virus control measures; expectations regarding Upstream reported production excluding Rosneft , total capital expenditure, depreciation, depletion and amortisation charges, Gulf of Mexico oil spill payments (post-tax), the Other business and corporate annual charge and underlying quarterly charge, and the effective tax rate and the underlying effective tax rate; plans and expectations regarding the effectiveness of the group’s foreign currency exchange risk management; expectations regarding bp’s partnership with Equinor for offshore wind in the US, including bp’s expectation of pursuing further opportunities for offshore wind in the US, and regarding bp’s partnership with Ørsted on an industrial-scale project to produce hydrogen from water, powered by wind; expectations regarding the US gas market in 2021 as supply declines and demand for LNG exports recovers and that the current tightness on global LNG markets and higher US gas prices will lift other regional gas prices; expectations for limited growth in oil supply from non- OPEC+ countries coupled with active market management from OPEC+ leading to normalization of the currently high inventory levels, with prices subject to the decisions of OPEC+; expectations that US gas markets are likely to benefit from lower production and a recovery in international LNG demand driven by demand in Asia; expectations that demand for refined products will remain strong over the remaining useful life of existing assets; expectations that the majority of bp’s Upstream oil and gas properties will start decommissioning within the next two decades; expectations that the majority of bp’s reserves and resources that support the carrying value of the group’s existing oil and gas properties are expected to be produced over the next 10 years; expectations that reported production will be lower due to the impact of the ongoing divestment programme; expectations regarding level and volatility of other businesses and corporate charges for 2021; plans and expectations regarding bp’s in-scope projects’ impact on biodiversity; expectation’s regarding bp’s impact on air emissions and water use and management; expectations regarding fulfillment of existing delivery commitments for oil and gas; expectations regarding Gulf of Mexico oil spill payments; expectations that first oil from the Thunder Horse South Expansion will be reached in the third quarter of 2021 and that first oil for the Mad Dog 2 project will be reached in the second quarter of 2022; expectations that the Cassia Compression project will start up in 2022; expectations that first production from the Total-operated Zinia 2 deep offshore development project will occur in 2021; expectation that first production from the Platina project will occur in 2021; expectation for start-up of the West Nile Delta Raven project in the first quarter of 2021; expectations that the Tangguh expansion project will start-up in 2022; and plans and expectations regarding bp Ventures and Launchpad; and (ii) certain statements in Corporate governance (pages 71-102) and the Directors’ remuneration report (pages 103-126) with regard to: the anticipated future composition of the board of directors and the effects thereof; the board’s goals and areas of focus, including changes to KPIs and those goals stemming from the board’s annual evaluation; plans and expectations regarding directors’ share ownership and remuneration; plans regarding the governance and remuneration processes; and goals, activities and areas of focus of board committees, are all forward looking in nature. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of bp. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward looking statements; the effects of the COVID-19 pandemic and uncertainties about its impact and duration; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new projects onstream; the timing, quantum and nature of certain acquisitions and divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC+ quota restrictions; production-sharing agreements effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations and policies, including related to climate change; changes in social attitudes and customer 330 bp Annual Report and Form 20-F 2020 « See Glossary Shareholder information Shareholder information Share prices and listings Dividends Shareholder taxation information Major shareholders Annual general meeting Memorandum and Articles of Association Purchases of equity securities by the issuer and affiliated purchasers Fees and charges payable by ADS holders Fees and payments made by the Depositary to the issuer Documents on display Shareholding administration 2021 Shareholder calendar 332 332 332 334 335 335 338 339 339 339 340 340 bp Annual Report and Form 20-F 2020 331 Share prices and listings The following table shows dividends announced and paid by the company per ADS for the past five years. Markets and market prices The primary market for the company’s ordinary shares (trading symbol 'BP.'), 8% cumulative first preference shares (trading symbol 'BP.A') and 9% cumulative second preference shares (trading symbol 'BP.B') is the London Stock Exchange (LSE). The company’s ordinary shares are a constituent element of the Financial Times Stock Exchange 100 Index. In the US, the company’s securities are listed and traded on the New York Stock Exchange (NYSE) in the form of ADSs (trading symbol 'BP'), for which JPMorgan Chase Bank, N.A. is the depositary (the Depositary) and transfer agent. The Depositary’s principal office is 383 Madison Avenue, Floor 11, New York, NY, 10179, US. Each ADS represents six ordinary shares. ADSs are evidenced by American depositary receipts (ADRs), which may be issued in either certificated or book entry form. The company's ordinary shares are also traded in the form of a global depositary certificate representing the company's ordinary shares on the Frankfurt, Hamburg and Dusseldorf Stock Exchanges. On 25 February 2021, 849,802,947 ADSs (equivalent to approximately 5,098,817,682 ordinary shares or some 25.06% of the total issued share capital, excluding shares held in treasury) were outstanding and were held by approximately 72,535 ADS holders. Of these, about 71,703 had registered addresses in the US at that date. One of the registered holders of ADSs represents approximately 1,087,342 underlying holders. On 25 February 2021, there were approximately 225,319 ordinary shareholders. Of these shareholders, around 1,539 had registered addresses in the US and held a total of some 4,381,925 ordinary shares. Since a number of the ordinary shares and ADSs were held by brokers and other nominees, the number of holders in the US may not be representative of the number of beneficial holders or their respective country of residence. Dividends The company’s current policy is to pay interim dividends on a quarterly basis on its ordinary shares. Its policy is also to announce dividends for ordinary shares in US dollars and state an equivalent sterling dividend. Dividends on the company's ordinary shares will be paid in sterling and on the company's ADSs in US dollars. The rate of exchange used to determine the sterling amount equivalent is the average of the market exchange rates in London over the four business days prior to the sterling equivalent announcement date. The directors may choose to declare dividends in any currency provided that a sterling equivalent is announced. It is not the company’s intention to change its current policy of announcing dividends on ordinary shares in US dollars. Information regarding dividends announced and paid by the company on ordinary shares and preference shares is provided in Financial statements – Note 10. A Scrip Dividend Programme (Scrip Programme) was approved by shareholders in 2010 and was renewed for a further three years at the 2018 AGM. It is proposed that the Scrip Programme be renewed for a further three years at the 2021 AGM. It enabled the company's ordinary shareholders and ADS holders to elect to receive dividends by way of new fully paid ordinary shares (or ADSs in the case of ADS holders) instead of cash. The operation of the Scrip Programme is always subject to the directors’ decision to make the Scrip Programme offer available in respect of any particular dividend. The company announced on 29 October 2019 and as part of all subsequent quarterly results announcements made since that the board had suspended the Scrip Programme in respect of those quarterly dividends. Ordinary shareholders and ADS holders (subject to certain exceptions) may be able to participate in dividend reinvestment plans. Any decisions with respect to future dividends will be made by the board of BP p.l.c. following the end of each quarter. Future dividends will be dependent on future earnings, the financial condition of the group, the Risk factors set out on page 67 and other matters that may affect the business of the group set out in Our strategy on page 15 and in Liquidity and capital resources on page 306. Dividends per ADSa March June September December Total 60 60 60 60 2018 2017 2016 UK pence 42.08 41.50 45.35 47.59 176.52 US cents 240 60 UK pence 48.95 46.54 45.73 44.66 185.88 US cents 240 60 UK pence 43.01 44.66 47.58 48.15 183.40 US cents 243 UK pence 46.43 48.39 50.09 46.95 191.86 246 US cents 61.50 61.50 61.50 61.50 UK pence 48.94 50.05 24.26 23.50 146.75 189 US cents a Dividends announced and paid by the company on ordinary and preference shares are provided in 63.00 63.00 31.50 31.50 60 61.50 61.50 2020 2019 60 60 60 Financial statements – Note 10. There are currently no UK foreign exchange controls or restrictions on remittances of dividends on the ordinary shares or on the conduct of the company’s operations, other than restrictions applicable to certain countries and persons subject to EU economic sanctions or those sanctions adopted by the UK government which implement resolutions of the Security Council of the United Nations. Shareholder taxation information This section describes the material US federal income tax and UK taxation consequences of owning ordinary shares or ADSs to a US holder who holds the ordinary shares or ADSs as capital assets for tax purposes. It does not apply, however, inter alia to members of special classes of holders some of which may be subject to other rules, including: tax- exempt entities, life insurance companies, dealers in securities, traders in securities that elect a mark-to-market method of accounting for securities holdings, investors liable for alternative minimum tax, holders that, directly or indirectly, hold 10% or more of the company’s shares (as measured by voting power or value), holders that hold the shares or ADSs as part of a straddle or a hedging or conversion transaction, holders that purchase or sell the shares or ADSs as part of a wash sale for US federal income tax purposes, or holders whose functional currency is not the US dollar. In addition, if a partnership holds the shares or ADSs, the US federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership and may not be described fully below. A US holder is any beneficial owner of ordinary shares or ADSs that is for US federal income tax purposes (1) a citizen or resident of the US, (2) a US domestic corporation, (3) an estate whose income is subject to US federal income taxation regardless of its source, or (4) a trust if a US court can exercise primary supervision over the trust’s administration and one or more US persons are authorized to control all substantial decisions of the trust. This section is based on the tax laws of the United States, including the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed US Treasury regulations thereunder, published rulings and court decisions, and the taxation laws of the UK, all as currently in effect, as well as the income tax convention between the US and the UK that entered into force on 31 March 2003 (the ‘Treaty’). These laws are subject to change, possibly on a retroactive basis. This section further assumes that each obligation under the terms of the deposit agreement relating to bp ADSs and any related agreement will be performed in accordance with its terms. For purposes of the Treaty and the estate and gift tax Convention (the ‘Estate Tax Convention’) and for US federal income tax and UK taxation purposes, a holder of ADRs evidencing ADSs will be treated as the owner of the company’s ordinary shares represented by those ADRs. Exchanges of ordinary shares for ADRs and ADRs for ordinary shares generally will not be subject to US federal income tax or to UK taxation other than stamp duty or stamp duty reserve tax, as described below. 332 bp Annual Report and Form 20-F 2020 « See Glossary Shareholder information Investors should consult their own tax adviser regarding the US federal, state and local, UK and other tax consequences of owning and disposing of ordinary shares and ADSs in their particular circumstances, and in particular whether they are eligible for the benefits of the Treaty in respect of their investment in the shares or ADSs. adviser regarding the US tax treatment of the dividend fee in respect of dividends. Dividends will be income from sources outside the US and generally will be ‘passive category income’ or, in the case of certain US holders, ‘general category income’, each of which is treated separately for purposes of computing a US holder’s foreign tax credit limitation. Taxation of dividends UK taxation Under current UK taxation law, no withholding tax will be deducted from dividends paid by the company, including dividends paid to US holders. A shareholder that is a company resident for tax purposes in the UK or trading in the UK through a permanent establishment generally will not be taxable in the UK on a dividend it receives from the company. A shareholder who is an individual resident for tax purposes in the UK is subject to UK tax on dividends received from the company, including dividends received under the dividend reinvestment plan (DRIP) for ordinary shareholders, but until 5 April 2016, was entitled to a tax credit on cash dividends paid on ordinary shares or ADSs of the company equal to one-ninth of the cash dividend. From 6 April 2016 the dividend tax credit was replaced by a new tax-free dividend allowance and dividends paid by the company on or after 6 April 2016 do not carry a UK tax credit. The dividend allowance was £5,000 but this has been reduced to £2,000 as of 6 April 2018. The dividend allowance of £2,000 means there is no UK tax due on the first £2,000 of dividends received. Dividends above this level are subject to tax at 7.5% for basic tax payers, 32.5% for higher rate tax payers and 38.1% for additional rate tax payers. Although the first £2,000 of dividend income is not subject to UK income tax, it does not reduce the total income for tax purposes. Dividends within the dividend allowance still count towards basic or higher rate bands, and may therefore affect the rate of tax paid on dividends received in excess of the £2,000 allowance. For instance, if an individual has an annual gross salary of £50,000 and also receives a dividend of £12,000 they will be subject to the following scenario. The individual's personal allowance and the basic rate tax band will be used up by the gross salary. The remaining part of the salary and the whole of the dividend will be subject to tax at the higher rate, although the dividend allowance will reduce the amount of dividend subject to tax. The dividend of £12,000 will be reduced by the dividend allowance of £2,000 leaving taxable dividend income of £10,000. The dividend will be taxed at 32.5% so that the total tax payable on the dividends is £3,250. How the shareholder pays the tax arising on the dividend income depends on the amount of dividend income and salary they receive in the tax year. If less than £2,000 they will not need to report anything or pay any tax. If between £2,000 and £10,000, the shareholder can pay what they owe by: contacting the helpline; asking HMRC to change their tax code – the tax will be taken from their wages or pension or through completion of the ‘Dividends’ section of their tax return, where one is being filed. If over £10,000 they will be required to file a self-assessment tax return and should complete the ‘Dividends’ section with details of the amounts received. US federal income taxation A US holder is subject to US federal income taxation on the gross amount of any dividend paid by the company (including dividends paid but reinvested received under the Global Invest Direct (GID) Dividend Reinvestment Plan for ADS holders) out of its current or accumulated earnings and profits (as determined for US federal income tax purposes). Dividends paid to a non-corporate US holder that constitute qualified dividend income will be taxable to the holder at a preferential rate, provided that the holder has a holding period in the ordinary shares or ADSs of more than 60 days during the 121-day period beginning 60 days before the ex-dividend date and meets other holding period requirements. Dividends paid by the company with respect to the ordinary shares or ADSs will generally be qualified dividend income. For US federal income tax purposes, a dividend must be included in income when the US holder, in the case of ordinary shares, or the Depositary, in the case of ADSs, actually or constructively receives the dividend and will not be eligible for the dividends-received deduction generally allowed to US corporations in respect of dividends received from other US corporations. US ADS holders should consult their own tax As noted above in UK taxation, a US holder will not be subject to UK withholding tax. Accordingly, the receipt of a dividend will not entitle the US holder to a foreign tax credit. The amount of the dividend distribution on the ordinary shares that is paid in pounds sterling will be the US dollar value of the pounds sterling payments made, determined at the spot pounds sterling/US dollar rate on the date the dividend distribution is includible in income, regardless of whether the payment is, in fact, converted into US dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the pounds sterling dividend payment is includible in income to the date the payment is converted into US dollars will be treated as ordinary income or loss and will not be eligible for the preferential tax rate on qualified dividend income. The gain or loss generally will be income or loss from sources within the US for foreign tax credit limitation purposes. Distributions in excess of the company’s earnings and profits, as determined for US federal income tax purposes, will be treated as a return of capital to the extent of the US holder’s basis in the ordinary shares or ADSs and thereafter as capital gain, subject to taxation as described in Taxation of capital gains – US federal income taxation section below. In addition, the taxation of dividends may be subject to the rules for passive foreign investment companies (PFIC), described below under ‘Taxation of capital gains – US federal income taxation’. Distributions made by a PFIC do not constitute qualified dividend income and are not eligible for the preferential tax rate applicable to such income. Taxation of capital gains UK taxation A US holder may be liable for both UK and US tax in respect of a gain on the disposal of ordinary shares or ADSs if the US holder is (1) resident for tax purposes in the United Kingdom at the date of disposal, (2) if he or she has left the UK for a period not exceeding five complete tax years between the year of departure from and the year of return to the UK and acquired the shares before leaving the UK and was resident in the UK in the previous four out of seven tax years before the year of departure, (3) a US domestic corporation resident in the UK by reason of its business being managed or controlled in the UK or (4) a citizen of the US that carries on a trade or profession or vocation in the UK through a branch or agency or a corporation that carries on a trade, profession or vocation in the UK, through a permanent establishment, and that has used, held, or acquired the ordinary shares or ADSs for the purposes of such trade, profession or vocation of such branch, agency or permanent establishment. However, such persons may be entitled to a tax credit against their US federal income tax liability for the amount of UK capital gains tax or UK corporation tax on chargeable gains (as the case may be) that is paid in respect of such gain. Under the Treaty, capital gains on dispositions of ordinary shares or ADSs generally will be subject to tax only in the jurisdiction of residence of the relevant holder as determined under both the laws of the UK and the US and as required by the terms of the Treaty. Under the Treaty, individuals who are residents of either the UK or the US and who have been residents of the other jurisdiction (the US or the UK, as the case may be) at any time during the six years immediately preceding the relevant disposal of ordinary shares or ADSs may be subject to tax with respect to capital gains arising from a disposition of ordinary shares or ADSs of the company not only in the jurisdiction of which the holder is resident at the time of the disposition but also in the other jurisdiction. For gains on or after 23 June 2010, the UK Capital Gains Tax rate will be dependent on the level of an individual’s taxable income. Where total taxable income and gains after all allowable deductions are less than the upper limit of the basic rate income tax band of £37,500 (for 2020/21), the rate of Capital Gains Tax will be 10%. For gains (and any parts of gains) above that limit the rate will be 20%. « See Glossary bp Annual Report and Form 20-F 2020 333 From 6 April 2008, entitlement to the annual exemption is based on an individual’s circumstances (taking into account Domicile status, remittance basis of taxation and number of years in the UK). For individuals who are entitled to the exemption for 2020/21, this has been set at £12,300. Corporation tax on chargeable gains is levied at 19 per cent for companies from 1 April 2017. US federal income taxation A US holder who sells or otherwise disposes of ordinary shares or ADSs will recognize a capital gain or loss for US federal income tax purposes equal to the difference between the US dollar value of the amount realized on the disposition and the US holder’s tax basis, determined in US dollars, in the ordinary shares or ADSs. Any such capital gain or loss generally will be long-term gain or loss, subject to tax at a preferential rate for a non-corporate US holder, if the US holder’s holding period for such ordinary shares or ADSs exceeds one year. The tax basis of shares acquired through reinvested dividends under the GID Dividend Reinvestment Plan for ADS holders) is equal to the fair market value of the stock on the investment date. The holding period for shares acquired under the plan begins the day after the applicable investment date. Gain or loss from the sale or other disposition of ordinary shares or ADSs will generally be income or loss from sources within the US for foreign tax credit limitation purposes. The deductibility of capital losses is subject to limitations. We do not believe that ordinary shares or ADSs will be treated as stock of a passive foreign investment company (PFIC) for US federal income tax purposes, but this conclusion is a factual determination that is made annually and thus is subject to change. If we are treated as a PFIC, unless a US holder elects to be taxed annually on a mark-to-market basis with respect to ordinary shares or ADSs, any gain realized on the sale or other disposition of ordinary shares or ADSs would in general not be treated as capital gain. Instead, a US holder would be treated as if he or she had realized such gain rateably over the holding period for ordinary shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain was allocated, in addition to which an interest charge in respect of the tax attributable to each such year would apply. Certain ‘excess distributions’ would be similarly treated if we were treated as a PFIC. Additional tax considerations Scrip Programme Until the publication of the 2019 third quarter results, the company had an optional Scrip Programme, wherein holders of bp ordinary shares or ADSs could elect to receive any dividends in the form of new fully paid ordinary shares or ADSs of the company instead of cash. Please consult your tax adviser for the consequences to you. UK inheritance tax The Estate Tax Convention applies to inheritance tax. ADSs held by an individual who is domiciled for the purposes of the Estate Tax Convention in the US and is not for the purposes of the Estate Tax Convention a national of the UK will not be subject to UK inheritance tax on the individual’s death or on transfer during the individual’s lifetime unless, among other things, the ADSs are part of the business property of a permanent establishment situated in the UK used for the performance of independent personal services. In the exceptional case where ADSs are subject to both inheritance tax and US federal gift or estate tax, the Estate Tax Convention generally provides for tax payable in the US to be credited against tax payable in the UK or for tax paid in the UK to be credited against tax payable in the US, based on priority rules set forth in the Estate Tax Convention. UK stamp duty and stamp duty reserve tax The statements below relate to what is understood to be the current practice of HM Revenue & Customs in the UK under existing law. Provided that any instrument of transfer is not executed in the UK and remains at all times outside the UK and the transfer does not relate to any matter or thing done or to be done in the UK, no UK stamp duty is payable on the acquisition or transfer of ADSs. Neither will an agreement to transfer ADSs in the form of ADRs give rise to a liability to stamp duty reserve tax. Purchases of ordinary shares, as opposed to ADSs, through the CREST system of paperless share transfers will be subject to stamp duty reserve tax at 0.5%. The charge will arise as soon as there is an agreement for the transfer of the shares (or, in the case of a conditional agreement, when the condition is fulfilled). The stamp duty reserve tax will apply to agreements to transfer ordinary shares even if the agreement is made outside the UK between two non-residents. Purchases of ordinary shares outside the CREST system are subject either to stamp duty at a rate of £5 per £1,000 (or part, unless the stamp duty is less than £5, when no stamp duty is charged), or stamp duty reserve tax at 0.5%. Stamp duty and stamp duty reserve tax are generally the liability of the purchaser. A subsequent transfer of ordinary shares to the Depositary’s nominee will give rise to further stamp duty at the rate of £1.50 per £100 (or part) or stamp duty reserve tax at the rate of 1.5% of the value of the ordinary shares at the time of the transfer. For ADR holders electing to receive ADSs instead of cash, after the 2012 first quarter dividend payment, HM Revenue & Customs no longer seeks to impose 1.5% stamp duty reserve tax on issues of UK shares and securities to non-EU clearance services and depositary receipt systems. Major shareholders The disclosure of certain major and significant shareholdings in the share capital of the company is governed by the Companies Act 2006, the UK Financial Conduct Authority’s Disclosure Guidance and Transparency Rules (DTR) and the US Securities Exchange Act of 1934. Register of members holding bp ordinary shares as at 31 December 2020 Range of holdings Number of ordinary shareholders 52,385 75,742 86,759 10,733 824 674 227,117 Percentage of total ordinary shareholders 23.06 33.35 38.20 4.73 0.36 0.30 100.00 Percentage of total ordinary share capital excluding shares held in treasury 0.01 0.21 1.36 1.10 1.45 95.87 100.00 1-200 201-1,000 1,001-10,000 10,001-100,000 100,001-1,000,000 Over 1,000,000a Totals a Includes JPMorgan Chase Bank, N.A. holding 25.33% of the total ordinary issued share capital (excluding shares held in treasury) as the approved depositary for ADSs, a breakdown of which is shown in the table below. Register of holders of American depositary shares (ADSs) as at 31 December 2020a Range of holdings Number of ADS holders 43,236 19,362 10,198 432 7 1 73,236 Percentage of  total ADS holders 59.04 26.44 13.92 0.59 0.01 0.00 100.00 1-200 201-1,000 1,001-10,000 10,001-100,000 100,001-1,000,000 Over 1,000,000b Totals a One ADS represents six 25 cent ordinary shares. b One holder of ADSs represents 1,056,393 approx. underlying shareholders. As at 31 December 2020 there were also 1,212 preference shareholders. Preference shareholders represented 0.42% and ordinary shareholders represented 99.58% of the total issued nominal share capital of the company (excluding shares held in treasury) as at that date. Percentage of  total ADSs 0.27 1.07 3.06 0.82 0.22 94.56 100.00 As at 31 December 2020, the company had not received any notifications pursuant to DTR5. The company also did not receive any notifications pursuant to DTR5 between 1 January 2021 and 25 February 2021. Under the US Securities Exchange Act of 1934 bp is aware of the following interests as at 25 February 2021: 334 bp Annual Report and Form 20-F 2020 « See Glossary Holder JPMorgan Chase Bank N.A., depositary for ADSs, through its nominee Guaranty Nominees Limited BlackRock, Inc. The Vanguard Group, Inc Holding of ordinary shares Percentage of ordinary share capital excluding shares held in treasury 5,098,817,683 1,514,099,140 763,396,544 25.06 7.69 3.75 The company’s major shareholders do not have different voting rights. The company has also been notified of the following interests in preference shares as at 25 February 2021: Holder The National Farmers Union Mutual Insurance Society Limited Hargreaves Lansdown Asset Management Limited Interactive Investor Share Dealing Services M & G Investment Management Ltd. Canaccord Genuity Group Inc. Halifax Share Dealing Services Holder The National Farmers Union Mutual Insurance Society Limited M & G Investment Management Ltd. Safra Group Canaccord Genuity Group Inc. Holding of 8% cumulative first preference shares Percentage of class 945,000 13.07 698,778 573,177 528,150 504,162 416,661 9.66 7.92 7.30 6.97 5.76 Holding of 9% cumulative second preference shares Percentage of class 987,000 644,450 385,000 306,605 18.03 11.77 7.03 5.60 As at 25 February 2021, the total preference shares in issue comprised only 0.42% of the company’s total issued nominal share capital (excluding shares held in treasury), the rest being ordinary shares. Annual general meeting The 2021 AGM is scheduled to be held on Wednesday 12 May 2021 at 11.00am. A separate notice convening the meeting is distributed to shareholders, which includes an explanation of the items of business to be considered at the meeting. All resolutions for which notice has been given will be decided on a poll. Deloitte LLP have expressed their willingness to continue in office as auditors and a resolution for their reappointment is included in the Notice of bp Annual General Meeting 2021. Memorandum and Articles of Association The following summarizes certain provisions of the company’s Memorandum and Articles of Association and applicable English law. This summary is qualified in its entirety by reference to the UK Companies Act 2006 (the Act) and the company’s Memorandum and Articles of Association. The Memorandum and Articles of Association are available online at bp.com/usefuldocs. The company’s Articles of Association may be amended by a special resolution at a general meeting of the shareholders. At the annual general meeting (AGM) held on 21 May 2018 shareholders voted to adopt new Articles of Association to reflect developments in market practice and to provide clarification and additional flexibility where necessary or appropriate. Objects and purposes Shareholder information bp is a public company limited by shares, incorporated under the name BP p.l.c. and is registered in England and Wales with the registered number 102498. The provisions regulating the operations of the company, known as its ‘objects’, were historically stated in a company’s memorandum. The Act abolished the need to have object provisions and so at the AGM held on 15 April 2010 shareholders approved the removal of its objects clause together with all other provisions of its Memorandum that, by virtue of the Act, are treated as forming part of the company’s Articles of Association. Directors and secretary The business and affairs of bp shall be managed by the directors. The company’s Articles of Association provide that directors may be appointed by the existing directors or by the shareholders in a general meeting. Any person appointed by the directors will hold office only until the next general meeting, notice of which is first given after their appointment and will then be eligible for re-election by the shareholders. A director may be removed by bp as provided for by applicable law and shall vacate office in certain circumstances as set out in the Articles of Association. In addition the company may, by special resolution, remove a director before the expiration of his/her period of office and, subject to the Articles of Association, may by ordinary resolution appoint another person to be a director instead. There is no requirement for a director to retire on reaching any age. The Articles of Association place a general prohibition on a director voting in respect of any contract or arrangement in which the director has a material interest other than by virtue of such director’s interest in shares in the company. However, in the absence of some other material interest not indicated below, a director is entitled to vote and to be counted in a quorum for the purpose of any vote relating to a resolution concerning the following matters: • The giving of security or indemnity with respect to any money lent or obligation taken by the director at the request or benefit of the company or any of its subsidiary undertakings. • Any proposal in which the director is interested, concerning the underwriting of company securities or debentures or the giving of any security to a third party for a debt or obligation of the company or any of its subsidiary undertakings. • Any proposal concerning any other company in which the director is interested, directly or indirectly (whether as an officer or shareholder or otherwise) provided that the director and persons connected with such director are not the holder or holders of 1% or more of the voting interest in the shares of such company. • Any proposal concerning the purchase or maintenance of any insurance policy under which the director may benefit. • Any proposal concerning the giving to the director of any other indemnity which is on substantially the same terms as indemnities given or to be given to all of the other directors or to the funding by the company of his expenditure on defending proceedings or the doing by the company of anything to enable the director to avoid incurring such expenditure where all other directors have been given or are to be given substantially the same arrangements. • Any proposal concerning an arrangement for the benefit of the employees and directors or former employees and former directors of the company or any of its subsidiary undertakings, including but without being limited to a retirement benefits scheme and an employees’ share scheme, which does not accord to any director any privilege or advantage not generally accorded to the employees or former employees to whom the arrangement relates. The Act requires a director of a company who is in any way interested in a contract or proposed contract with the company to declare the nature of the director’s interest at a meeting of the directors of the company. The definition of ‘interest’ includes the interests of spouses, children, companies and trusts. The Act also requires that a director must avoid a situation where a director has, or could have, a direct or indirect interest that conflicts, or possibly may conflict, with the company’s interests. The Act allows directors of public companies to authorize such conflicts where appropriate, if a company’s Articles of Association so permit. bp’s Articles of Association permit the authorization of such conflicts. The directors may exercise all the powers of the company to borrow money, except « See Glossary bp Annual Report and Form 20-F 2020 335 that the amount remaining undischarged of all moneys borrowed by the company shall not, without approval of the shareholders, exceed two times the amount paid up on the share capital plus the aggregate of the amount of the capital and revenue reserves of the company. Variation of the borrowing power of the board may only be affected by amending the Articles of Association. Remuneration of non-executive directors shall be determined in the aggregate by resolution of the shareholders. Remuneration of executive directors is determined by the remuneration committee. This committee is made up of non-executive directors only. There is no requirement of share ownership for a director’s qualification. The Articles of Association provide entitlement to the directors’ pensions and death and disability benefits to the directors’ relations and dependants respectively. The circumstances in which a director’s office will automatically terminate include: when a director ceases to hold an executive office of the company and the directors resolve that he should cease to be a director; if a medical practitioner provides an opinion that a director has become incapable of acting as a director and may remain so incapable for a further three months and the directors resolve that he should cease to be a director; and if all of the other directors vote in favour of a resolution stating that the person should cease to be a director. The company secretary has express powers to delegate any of the powers or discretions conferred on him or her. Dividend rights; other rights to share in company profits; capital calls If recommended by the directors of bp, shareholders of bp may, by resolution, declare dividends but no such dividend may be declared in excess of the amount recommended by the directors. The directors may also pay interim dividends without obtaining shareholder approval. No dividend may be paid other than out of profits available for distribution, as determined under IFRS and the Act. Dividends on ordinary shares are payable only after payment of dividends on bp preference shares. Any dividend unclaimed after a period of 10 years from the date of declaration of such dividend shall be forfeited and reverts to bp. If the company exercises its right to forfeit shares and sells shares belonging to an untraced shareholder then any entitlement to claim dividends or other monies unclaimed in respect of those shares will be for a period of twelve months after the sale. The company may take such steps as the directors decide are appropriate in the circumstances to trace the member entitled and the sale may be made at such time and on such terms as the directors may decide. The directors have the power to declare and pay dividends in any currency provided that a sterling equivalent is announced. It is not the company’s intention to change its current policy of paying dividends in US dollars. At the company’s AGM held on 15 April 2010, shareholders approved the introduction of a Scrip Dividend Programme (Scrip Programme) and to include provisions in the Articles of Association to enable the company to operate the Scrip Programme. The Scrip Programme was renewed at the company’s AGM held on 21 May 2018 for a further three years. The Scrip Programme enables ordinary shareholders and bp ADS holders to elect to receive new fully paid ordinary shares (or bp ADSs in the case of bp ADS holders) instead of cash. The operation of the Scrip Programme is always subject to the directors’ decision to make the scrip offer available in respect of any particular dividend. Should the directors decide not to offer the scrip in respect of any particular dividend, cash will automatically be paid instead. The directors may determine in relation to any scrip dividend plan or programme how the costs of the programme will be met, the minimum number of ordinary shares required in order to be able to participate in the programme and any arrangements to deal with legal and practical difficulties in any particular territory. Apart from shareholders’ rights to share in bp’s profits by dividend (if any is declared or announced), the Articles of Association provide that the directors may set aside: • A special reserve fund out of the balance of profits each year to make up any deficit of cumulative dividend on the bp preference shares. • A general reserve out of the balance of profits each year, which shall be applicable for any purpose to which the profits of the company may properly be applied. This may include capitalization of such sum, pursuant to an ordinary shareholders’ resolution, and distribution to shareholders as if it were distributed by way of a dividend on the ordinary shares or in paying up in full unissued ordinary shares for allotment and distribution as bonus shares. Any such sums so deposited may be distributed in accordance with the manner of distribution of dividends as described above. Holders of shares are not subject to calls on capital by the company, provided that the amounts required to be paid on issue have been paid off. All shares are fully paid. Share transfers and share certificates The directors may permit transfers to be effected other than by an instrument in writing and that share certificates will not be required to be issued by the company if they are not required by law. The company may charge an administrative fee in the event that a shareholder wishes to replace two or more certificates representing shares with a single certificate or wishes to surrender a single certificate and replace it with two or more certificates. All certificates are sent at the member’s risk. Voting rights The Articles of Association of the company provide that voting on resolutions at a shareholders’ meeting will be decided on a poll other than resolutions of a procedural nature, which may be decided on a show of hands. If voting is on a poll, every shareholder who is present in person or by proxy has one vote for every ordinary share held and two votes for every £5 in nominal amount of bp preference shares held. If voting is on a show of hands, each shareholder who is present at the meeting in person or whose duly appointed proxy is present in person will have one vote, regardless of the number of shares held, unless a poll is requested. Shareholders do not have cumulative voting rights. For the purposes of determining which persons are entitled to attend or vote at a shareholders’ meeting and how many votes such persons may cast, the company may specify in the notice of the meeting a time, not more than 48 hours before the time of the meeting, by which a person who holds shares in registered form must be entered on the company’s register of members in order to have the right to attend or vote at the meeting or to appoint a proxy to do so. Holders on record of ordinary shares may appoint a proxy, including a beneficial owner of those shares, to attend, speak and vote on their behalf at any shareholders’ meeting, provided that a duly completed proxy form is received not less than 48 hours (or such shorter time as the directors may determine) before the time of the meeting or adjourned meeting or, where the poll is to be taken after the date of the meeting, not less than 24 hours (or such shorter time as the directors may determine) before the time of the poll. Record holders of bp ADSs are also entitled to attend, speak and vote at any shareholders’ meeting of bp by the appointment by the approved depositary, JPMorgan Chase Bank N.A., of them as proxies in respect of the ordinary shares represented by their ADSs. Each such proxy may also appoint a proxy. Alternatively, holders of bp ADSs are entitled to vote by supplying their voting instructions to the depositary, who will vote the ordinary shares represented by their ADSs in accordance with their instructions. Proxies may be delivered electronically. Corporations who are members of the company may appoint one or more persons to act as their representative or representatives at any shareholders’ meeting provided that the company may require a corporate representative to produce a certified copy of the resolution appointing them before they are permitted to exercise their powers. Matters are transacted at shareholders’ meetings by the proposing and passing of resolutions, of which there are two types: ordinary or special. An ordinary resolution requires the affirmative vote of a majority of the votes of those persons voting at a meeting at which there is a quorum. A special resolution requires the affirmative vote of not less than three quarters of the persons voting at a meeting at which there is a quorum. Any AGM requires 21 clear days’ notice. The notice period for any other general meeting is 14 clear days subject to the company obtaining annual shareholder approval, failing which, a 21 clear day notice period will apply. 336 bp Annual Report and Form 20-F 2020 « See Glossary Shareholder information Disclosure of interests in shares The Act permits a public company to give notice to any person whom the company believes to be or, at any time during the three years prior to the issue of the notice, to have been interested in its voting shares requiring them to disclose certain information with respect to those interests. Failure to supply the information required may lead to disenfranchisement of the relevant shares and a prohibition on their transfer and receipt of dividends and other payments in respect of those shares and any new shares in the company issued in respect of those shares. In this context the term ‘interest’ is widely defined and will generally include an interest of any kind whatsoever in voting shares, including any interest of a holder of bp ADSs. Called-up share capital Details of the allotted, called-up and fully-paid share capital at 31 December 2020 are set out in Financial statements – Note 31. In accordance with institutional investor guidelines, the company deems it appropriate to grant authority to the directors to allot shares and other securities and to disapply pre-emption rights by way of shareholders' resolutions at each AGM in place of authority granted by virtue of the company's Articles of Association. At the AGM on 27 May 2020, authorization was given to the directors to allot shares in the company and to grant rights to subscribe for, or to convert any security into, shares in the company up to an aggregate nominal amount as set out in the Notice of Meeting 2020. These authorities were given for the period until the next AGM in 2021 or 27 August 2021, whichever is the earlier. These authorities are renewed annually at the AGM. Company records and service of notice In relation to notices not covered by the Act, the reference to notice by advertisement in a national newspaper also includes advertisements via other means such as a public announcement. Liquidation rights; redemption provisions In the event of a liquidation of bp, after payment of all liabilities and applicable deductions under UK laws and subject to the payment of secured creditors, the holders of bp preference shares would be entitled to the sum of (1) the capital paid up on such shares plus, (2) accrued and unpaid dividends and (3) a premium equal to the higher of (a) 10% of the capital paid up on the bp preference shares and (b) the excess of the average market price over par value of such shares on the LSE during the previous six months. The remaining assets (if any) would be divided pro rata among the holders of ordinary shares. Without prejudice to any special rights previously conferred on the holders of any class of shares, bp may issue any share with such preferred, deferred or other special rights, or subject to such restrictions as the shareholders by resolution determine (or, in the absence of any such resolutions, by determination of the directors), and may issue shares that are to be or may be redeemed. Variation of rights The rights attached to any class of shares may be varied with the consent in writing of holders of 75% of the shares of that class or on the adoption of a special resolution passed at a separate meeting of the holders of the shares of that class. At every such separate meeting, all of the provisions of the Articles of Association relating to proceedings at a general meeting apply, except that the quorum with respect to a meeting to change the rights attached to the preference shares is 10% or more of the shares of that class, and the quorum to change the rights attached to the ordinary shares is one third or more of the shares of that class. Shareholders’ meetings and notices Shareholders must provide bp with a postal or electronic address in the UK to be entitled to receive notice of shareholders’ meetings. Holders of bp ADSs are entitled to receive notices under the terms of the deposit agreement relating to bp ADSs. The substance and timing of notices are described above under the heading Voting rights. Under the Act, the AGM of shareholders must be held once every year, within each six month period beginning with the day following the company’s accounting reference date. All general meetings shall be held at a time and place determined by the directors. If any shareholders’ meeting is adjourned for lack of quorum, notice of the time and place of the adjourned meeting may be given in any lawful manner, including electronically. Powers exist for action to be taken either before or at the meeting by authorized officers to ensure its orderly conduct and safety of those attending. The directors have power to convene a general meeting which is a hybrid meeting, that is to provide facilities for shareholders to attend a meeting which is being held at a physical place by electronic means as well (but not to convene a purely electronic meeting). The provisions of the Articles of Association in relation to satellite meetings permit facilities being provided by electronic means to allow those persons at each place to participate in the meeting. Limitations on voting and shareholding There are no limitations, either under the laws of the UK or under the company’s Articles of Association, restricting the right of non-resident or foreign owners to hold or vote bp ordinary or preference shares in the company other than limitations that would generally apply to all of the shareholders and limitations applicable to certain countries and persons subject to EU economic sanctions or those sanctions adopted by the UK government which implement resolutions of the Security Council of the United Nations. « See Glossary bp Annual Report and Form 20-F 2020 337 Purchases of equity securities by the issuer and affiliated purchasers In November 2017 bp began a share repurchase or buyback programme (the programme). The sole purpose of the programme was to reduce the issued share capital of the company to offset the ongoing dilutive effect of scrip dividends over time, as announced by the company on 31 October 2017. In January 2020 the share dilution buyback programme had fully offset the impact of scrip dilution since the third quarter 2017. Authorization for the company to make market purchases (as defined in section 693(4) of the Companies Act 2006) of ordinary shares with a nominal value of $0.25 each in the company was renewed at the company’s 2020 AGM covering the period until the date of the company's 2021 AGM or 27 August 2021, whichever is earlier. The maximum number of ordinary shares to be purchased under this authority will not exceed 2,025,610,110 ordinary shares. The shares purchased will be cancelled. The following table provides details of ordinary share purchases made (1) under the programme and (2) by the Employee Share Ownership Plans (ESOPs) and other purchases of ordinary shares and ADSs made to satisfy the requirements of certain employee share-based payment plans. Number of shares purchased by ESOPs or for certain employee share- based plansb Number of shares purchased as part of the buyback programmec Maximun approximate dollar value of shares yet to be purchased under the programme $ million Total number of shares purchaseda Average price paid per share $ 6.47 120,057,464 Nil 120,057,464 2020 January 7 - January 28 February March April May June July August September October November December 2021 January 11 February (to February 26) a All share purchases were of ordinary shares of 25 cents each and/or ADSs (each representing six ordinary shares) and were on/open market transactions. b Transactions represent the purchases of ADSs made to satisfy requirements of certain employee share-based payment plans. c The company announced its intent to commence the programme on 31 October 2017 and announced further details and commencement of the programme on 15 November 2017. The programme Nil Nil Nil Nil Nil Nil Nil Nil Nil Nil Nil 285,552 285,552 3.98 Nil Nil N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A was completed in January 2020. At the AGM on 27 May 2020, authorization was given to the company to repurchase up to 2,025,610,110 ordinary shares, for the period ending on the date of the AGM in 2021 or 27 August 2021, whichever is the earlier. This authorization is renewed annually at the AGM. The total number of ordinary shares repurchased during 2020 under the programme was 120,057,464 at a cost of $776 million (including fees and stamp duty) representing 0.59% of the company’s issued share capital excluding shares held in treasury on 31 December 2020. All ordinary shares repurchased in 2020 under the programme were cancelled in order to reduce the company’s issued share capital. 338 bp Annual Report and Form 20-F 2020 « See Glossary Fees and charges payable by ADS holders The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of the distributable property to pay the fees. The charges of the Depositary payable by investors are as follows: Type of service Depositary actions Fee Shareholder information Depositing or substituting the underlying shares Selling or exercising rights Withdrawing an underlying share Expenses of the Depositary Dividend fees Issuance of ADSs against the deposit of shares, including deposits and issuances in respect of: • Share distributions, stock splits, rights, merger. • Exchange of securities or other transactions or event or other distribution affecting the ADSs or deposited securities. Distribution or sale of securities, the fee being an amount equal to the fee for the execution and delivery of ADSs that would have been charged as a result of the deposit of such securities. Acceptance of ADSs surrendered for withdrawal of deposited securities. Expenses incurred on behalf of holders in connection with: • Stock transfer or other taxes and governmental charges. • Delivery by cable, telex, electronic and facsimile transmission. • Transfer or registration fees, if applicable, for the registration of transfers of underlying shares. • Expenses of the Depositary in connection with the conversion of foreign currency into US dollars (which are paid out of such foreign currency). ADS holders who receive a cash dividend are charged a fee which bp uses to offset the costs associated with administering the ADS programme. Global Invest Direct (GID) Plan New investors and existing ADS holders can buy, sell or reinvest dividends into further bp ADSs by enrolling in bp’s GID Plan, sponsored and administered by the Depositary. $5.00 per 100 ADSs (or portion thereof) evidenced by the new ADSs delivered. $5.00 per 100 ADSs (or portion thereof). $5.00 for each 100 ADSs (or portion thereof) evidenced by the ADSs surrendered. Expenses payable are subject to agreement between the company and the Depositary by billing holders or by deducting charges from one or more cash dividends or other cash distributions. The Deposit Agreement provides that a fee of $0.05 or less per ADS can be charged. The current fee is $0.02 per bp ADS per calendar year (equivalent to $0.005 per bp ADS per quarter per cash distribution). Cost per transaction is $2.00 for recurring, $2.00 for one-time automatic investments, and $5.00 for investment made by check. Dividend reinvestment is 5% of the dividend amount up to a maximum of $5.00. Purchase trading commission is $0.12 per share. Fees and payments made by the Depositary to the issuer The Depositary has agreed to reimburse certain company expenses related to the company’s ADS programme and incurred by the company in connection with the ADS programme arising during the year ended 31 December 2020. The Depositary reimbursed to the company, or paid amounts on the company’s behalf to third parties, or waived its fees and expenses, of $18,936,081.43 for the year ended 31 December 2020. The table below sets out the types of expenses that the Depositary has agreed to reimburse and the fees it has agreed to waive for standard costs associated with the administration of the ADS programme relating to the year ended 31 December 2020. Category of expense reimbursed, waived or paid directly to third parties Amount reimbursed, waived or paid directly to third parties for the year ended 31 December 2020 Fees for delivery and surrender of bp ADSs Dividend feesa Total a Dividend fees are charged to ADS holders who receive a cash distribution, which bp uses to 1,267,682.60 17,668,398.83 18,936,081.43 expenses paid to or on behalf of the company during the 12-month period prior to notice of removal or termination. Documents on display The bp Annual Report and Form 20-F 2020 is available online at bp.com/ annualreport. To obtain a hard copy of bp’s complete audited financial statements, free of charge, UK based shareholders should contact bp Distribution Services by calling +44 (0) 800 037 2172 or by emailing bpdistributionservices@bp.com. If based in the US or Canada shareholders should contact Issuer Direct by calling +1 888 301 2505 or by emailing bpreports@issuerdirect.com. The company is subject to the information requirements of the US Securities Exchange Act of 1934 applicable to foreign private issuers. In accordance with these requirements, the company files its Annual Report and Form 20-F and other related documents with the SEC. The SEC maintains an internet site at www.sec.gov that contains reports and other information regarding issuers, including bp, that file electronically with the SEC. bp's SEC filings are also available at bp.com/sec. bp discloses in this report (see Corporate governance practices (Form 20-F Item 16G) on page 326) significant ways (if any) in which its corporate governance practices differ from those mandated for US companies under NYSE listing standards. offset the costs associated with administering the ADS programme. Under certain circumstances, including removal of the Depositary or termination of the ADR programme by the company, the company is required to repay the Depositary certain amounts reimbursed and/or « See Glossary bp Annual Report and Form 20-F 2020 339 Shareholding administration If you have any queries about the administration of shareholdings, such as change of address, change of ownership, dividend payment options or to change the way you receive your company documents (such as the bp Annual Report and Form 20-F and Notice of bp Annual General Meeting) please contact the bp Registrar or the bp ADS Depositary. Ordinary and preference shareholders The bp Registrar, Link Group, Central Square, 29 Wellington Street, Leeds, LS1 4DL Freephone in UK 0800 701107 From outside the UK +44 (0)371 277 1014 ADS holders bp Shareowner Services PO Box 64504, St Paul, MN 55164-0504, US Toll-free in US and Canada +1 877 638 5672 From outside the US and Canada +1 651 306 4383 2021 shareholder calendara 26 Mar 2021 Fourth quarter interim dividend payment for 2020 27 April 2021 First quarter results announced 7 May 2021 Record date (to be eligible for the first quarter interim dividend) 12 May 2021 Annual general meeting 18 Jun 2021 First quarter interim dividend payment for 2021 2 Jul 2021 8% and 9% preference shares record date 27 Jul 2021 Second quarter results announced 30 Jul 2021 6 Aug 2021 8% and 9% preference shares dividend payment Record date (to be eligible for the second quarter interim dividend) 24 Sep 2021 Second quarter interim dividend payment for 2021 2 Nov 2021 12 Nov 2021 Record date (to be eligible for the third quarter interim Third quarter results announced dividend) 17 Dec 2021 Third quarter interim dividend payment for 2021 a All future dates are provisional and may be subject to change. For the full calendar see bp.com/ financialcalendar. 340 bp Annual Report and Form 20-F 2020 « See Glossary Glossary Abbreviations ADR American depositary receipt. ADS American depositary share. 1 ADS = 6 ordinary shares. Barrel (bbl) 159 litres, 42 US gallons. bcf Billion cubic feet. bcfe Billion cubic feet equivalent. EVP Executive vice president. FPSO Floating production, storage and offloading. GAAP Generally accepted accounting practice. Gas Natural gas. gCO2e/MJ Grams of carbon dioxide equivalent per megajoule of energy. GHG Greenhouse gas. GRI Global Reporting Initiative. GtCO2 Gigatonnes of carbon dioxide. GWh Gigawatt hour. HSSE Health, safety, security and environment. IFRS International Financial Reporting Standards. Kb/d Thousand barrels per day. KPIs Key performance indicators. kt Thousand tonnes. LNG Liquefied natural gas. LPG Liquefied petroleum gas. mb/d Thousand barrels per day. Mbbl Million barrels. mboe/d Thousand barrels of oil equivalent per day. mmb/d Million barrels per day. mmboe/d Million barrels of oil equivalent per day. mmBtu Million British thermal units. mmcf/d Million cubic feet per day. Mte Million tonnes. MteCO2e Million tonnes of CO2 equivalent. Mtpa Million tonnes per annum. NGLs Natural gas liquids. PSA Production-sharing agreement. PTA Purified terephthalic acid. RC Replacement cost. SEC The United States Securities and Exchange Commission. TWh Terawatt hour. SVP Senior vice president. Definitions Unless the context indicates otherwise, the definitions for the following glossary terms are given below. Non-GAAP measures are sometimes referred to as alternative performance measures. CA100+ resolution glossary CA100+ resolution The CA100+ resolution means the special resolution requisitioned by Climate Action 100+ and passed at bp’s 2019 Annual General Meeting, the text of which is set out below. Special resolution: Climate Action 100+ shareholder resolution on climate change disclosures. That in order to promote the long term success of the company, given the recognised risks and opportunities associated with climate change, we as shareholders direct the company to include in its strategic report and/or other corporate reports, as appropriate, for the year ending 2019 onwards, a description of its strategy which the board considers, in good faith, to be consistent with the goals of Articles 2.1(a)(1) and 4.1(2) of the Paris Agreement(3) (the ‘Paris goals’), as well as: (1) Capital expenditure: how the company evaluates the consistency of each new material capex investment, including in the exploration, acquisition or development of oil and gas resources and reserves and other energy sources and technologies, with (a) the Paris goals and separately (b) a range of other outcomes relevant to its strategy. (2) Metrics and targets: the company’s principal metrics and relevant targets or goals over the short, medium and/or long-term, consistent with the Paris goals, together with disclosure of: a. The anticipated levels of investment in (i) oil and gas resources and reserves; and (ii) other energy sources and technologies. b. The company’s targets to promote reductions in its operational greenhouse gas emissions, to be reviewed in line with changing protocols and other relevant factors c. The estimated carbon intensity of the company’s energy products bp Annual Report and Form 20-F 2020 341 and progress on carbon intensity over time. d. Any linkage between the above targets and executive remuneration. (3) Progress reporting: an annual review of progress against (1) and (2) above. Such disclosure and reporting to include the criteria and summaries of the methodology and core assumptions used, and to omit commercially confidential or competitively sensitive information and be prepared at reasonable cost; and provided that nothing in this resolution shall limit the company’s powers to set and vary its strategy, or associated targets or metrics, or to take any action which it believes in good faith, would best promote the long-term success of the company. The Paris goals (1) Article 2.1(a) of the Paris Agreement states the goal of ‘Holding the increase in the global average temperature to well below 2°C above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels, recognizing that this would significantly reduce the risks and impacts of climate change’. (2) Article 4.1 of the Paris Agreement: In order to achieve the long-term temperature goal set out in Article 2, parties aim to reach global peaking of greenhouse gas emissions as soon as possible, recognizing that peaking will take longer for developing country parties, and to undertake rapid reductions thereafter in accordance with best available science, so as to achieve a balance between anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century, on the basis of equity, and in the context of sustainable development and efforts to eradicate poverty. (3) U.N. Framework Convention on Climate Change Conference of Parties, Twenty-First Session, Adoption of the Paris Agreement, U.N. Doc. FCCC/CP/2015/L.9/Rev.1 (Dec. 12, 2015). New material capex investment For the purposes of the 2020 evaluation discussed on pages 28-32, ‘new material capex investment’ means a decision taken by the resource commitment meeting (RCM) in 2020 to incur inorganic or organic investments greater than $250 million that relate to a new project or asset, extending an existing project or asset, or acquiring or increasing a share in a project, asset or entity. There were three investments that met the above criteria in 2020. Material capex evaluation: Paris-consistency quantitative tests. For the purposes of evaluating material capex investments for consistency with the Paris goals, two quantitative tests were applied, see page 32. 1. Operational carbon intensity (CI) The annual average operational GHG emissions (TeCO2e/unit), divided by the relevant unit of output: • per thousand barrels of oil equivalent in Upstream • per utilized equivalent distillation capacity in refining • per thousand tonnes in petrochemicals. Net zero aims and ambition glossary Net zero References to global net zero in the phrase, 'to help the world get to net zero', means achieving '...a balance between anthropogenic emissions by sources and removals by sinks of greenhouse gases...on the basis of equity, and in the context of sustainable development and efforts to eradicate poverty', as set out in Article 4(1) of the Paris Agreement. References to net zero for bp in the context of our ambition and Aims 1 and 2 as set out on page 49 (such as 'be a net zero company by 2050 or sooner'), means achieving a balance between (a) the relevant Scope 1 and 2 emissions (for our Aim 1), or Scope 3 emissions (for our Aim 2), and (b) the aggregate of applicable deductions from qualifying activities such as sinks under our methodology at the applicable time. Emissions from the carbon in our Upstream oil and gas production Estimated CO2 emissions from the combustion of upstream production of crude oil, natural gas and natural gas liquids (NGLs) on a bp equity-share basis based on bp’s net share of production, excluding bp’s share of Rosneft production and assuming that all produced volumes undergo full stoichiometric combustion to CO2. Average emissions intensity of marketed energy products The weighted average GHG emissions per unit of energy delivered (in grams CO2e/MJ), estimated in respect of marketing sales of energy products. GHG emissions are estimated on a lifecycle basis covering production, distribution and use of the relevant products (assuming full stoichiometric combustion of the product to CO2). Methane intensity Methane intensity refers to the amount of methane emissions from bp’s operated upstream oil and gas assets as a percentage of the total gas that goes to market from those operations. Our methodology is aligned with the Oil and Gas Climate Initiative’s (OGCI). Sustainable emissions reductions (SER) SERs result from actions or interventions that have led to ongoing reductions in Scope 1 (direct) and/or Scope 2 (indirect) greenhouse gas (GHG) emissions (carbon dioxide and methane) such that GHG emissions would have been higher in the reporting year if the intervention had not taken place. SERs must meet three criteria: a specific intervention that has reduced GHG emissions, the reduction must be quantifiable and the reduction is expected to be ongoing. Reductions are reportable for a 12- month period from the start of the intervention/action. Adjusted EBIDA Non-GAAP measure. Adjusted EBIDA is defined as underlying replacement cost profit before interest and tax, add back depreciation, depletion and amortization and exploration expenditure written-off (net of non-operating items), less taxation on an underlying RC basis. bp believes that adjusted EBIDA is a useful measure for investors because it is a measure closely tracked by management to evaluate bp’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is profit or loss before interest and tax. Adjusted EBIDA per share is calculated based on the shares in issue at period-end. Adjusted effective tax rate (ETR) Non-GAAP measure. The adjusted ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis excluding the impact of reductions in the rate of the UK North Sea supplementary charge in 2016 by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non- operating items and fair value accounting effects, and certain foreign exchange impacts on the group’s tax charge for the period. Information on underlying RC profit or loss is provided below. bp believes it is helpful to disclose the adjusted ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 348. Associate An entity over which the group has significant influence and that is neither a subsidiary nor a joint arrangement of the group. Significant influence is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies. Bioenergy production Bioenergy production is average thousands of barrels of biofuel production per day during the period covered, net to bp. This includes equivalent ethanol production, bp Bunge biopower for grid export, biogas and refining co-processing and standalone hydrogenated vegetable oil (HVO). 342 bp Annual Report and Form 20-F 2020 Brent A trading classification for North Sea crude oil that serves as a major benchmark price for purchases of oil worldwide. Capital expenditure Total cash capital expenditure as stated in the group cash flow statement. Castrol sales and other operating revenues Castrol sales and other operating revenues, are sales and other operating revenues generated by our Castrol business. Commodity trading contracts bp participates in regional and global commodity trading markets in order to manage, transact and hedge the crude oil, refined products and natural gas that the group either produces or consumes in its manufacturing operations. The range of contracts the group enters into in its commodity trading operations is described below. Using these contracts, in combination with rights to access storage and transportation capacity, allows the group to access advantageous pricing differences between locations, time periods and grades. Exchange-traded commodity derivatives Contracts that are typically in the form of futures and options traded on a recognized exchange, such as Nymex and ICE. Such contracts are traded in standard specifications for the main marker crude oils, such as Brent and West Texas Intermediate; the main product grades, such as gasoline and gasoil; and for natural gas and power. Gains and losses, otherwise referred to as variation margin, are generally settled on a daily basis with the relevant exchange. These contracts are used for the trading and risk management of crude oil, refined products, and natural gas and power. Realized and unrealized gains and losses on exchange-traded commodity derivatives are included in sales and other operating revenues for accounting purposes. Over-the-counter (OTC) contracts Contracts that are typically in the form of forwards, swaps and options. Some of these contracts are traded bilaterally between counterparties or through brokers, others may be cleared by a central clearing counterparty. These contracts can be used both for trading and risk management activities. Realized and unrealized gains and losses on OTC contracts are included in sales and other operating revenues for accounting purposes. Many grades of crude oil bought and sold use standard contracts including US domestic light sweet crude oil, commonly referred to as West Texas Intermediate, and a standard North Sea crude blend – Brent, Forties, Oseberg and Ekofisk (BFOE). Forward contracts are used in connection with the purchase of crude oil supplies for refineries and for marketing and sales of the group’s oil production and refined products. The contracts typically contain standard delivery and settlement terms. These transactions call for physical delivery of oil with consequent operational and price risk. However, various means exist and are used from time to time, to settle obligations under the contracts in cash rather than through physical delivery. Physically settled BFOE contracts delivered by cargo additionally specify a standard volume and tolerance. Gas and power OTC markets are highly developed in North America and the UK, where commodities can be bought and sold for delivery in future periods. These contracts are negotiated between two parties to purchase and sell gas and power at a specified price, with delivery and settlement at a future date. Typically, the contracts specify delivery terms for the underlying commodity. Some of these transactions are not settled physically as they can be net settled by transacting offsetting sale or purchase contracts for the same location and delivery period. The contracts contain standard terms such as delivery point, pricing mechanism, settlement terms and specification of the commodity. Typically, volume, price and term (e.g. daily, monthly and balance of month) are the main variable contract terms. Swaps are typically contractual obligations to exchange cash flows between two parties. A typical swap transaction usually references a floating price and a fixed price with the net difference of the cash flows being settled. Options give the holder the right, but not the obligation, to buy or sell crude, oil products, natural gas or power at a specified price on or before a specific future date. Amounts under these derivative financial instruments are settled at expiry. Typically, netting agreements are used to limit credit exposure and support liquidity. Spot and term contracts Spot contracts are contracts to purchase or sell a commodity at the market price prevailing on or around the delivery date when title to the inventory is taken. Term contracts are contracts to purchase or sell a commodity at regular intervals over an agreed term. Though spot and term contracts may have a standard form, there is no offsetting mechanism in place. As such, these transactions result in physical delivery with operational and price risk. Spot and term contracts typically relate to purchases of crude for a refinery, products for marketing, or third-party natural gas, or sales of the group’s oil production, oil products or gas production to third parties. For accounting purposes, spot and term sales are included in sales and other operating revenues when title passes. Similarly, spot and term purchases are included in purchases for accounting purposes. Consolidation adjustment – UPII Unrealized profit in inventory arising on inter-segment transactions. Convenience gross margin Non-GAAP measure. Convenience gross margin comprises store gross margin as well as other merchandise and service contribution, not considered as retail fuels or store gross margin, received from the retail service stations operated under a bp brand, excluding equity-accounted entities. Convenience, retail fuels and electrification gross margin Non-GAAP measure. Convenience, retail fuels and electrification gross margin is RC profit before interest and tax for Downstream, adjusted for non-operating items and fair value accounting effects to derive underlying RC profit before interest and tax. Downstream underlying RC profit before interest and tax is further adjusted by subtracting underlying RC profit before interest and tax for the petrochemicals, refining and trading and lubricants businesses; adding-back depreciation, depletion and amortization, production and manufacturing, distribution and administration expenses for fuels (excluding refining and trading); subtracting earnings from equity-accounted entities in fuels (excluding refining and trading) and gross margin for aviation, B2B and midstream businesses. Margin share for convenience and electrification is the ratio of convenience and electrification gross margin to total consumer energy (retail fuels and electrification) and convenience gross margin. bp believes it is helpful to disclose the margin share from convenience and electrification because this measure may help investors to understand and evaluate, in the same way as management, our progress against our strategic objectives of redefining convenience and scaling up our next-gen mobility solutions. The nearest GAAP measures of the numerator and denominator are RC profit before interest and tax. A reconciliation to GAAP information is provided on page 318. We are unable to present forward-looking information of the nearest GAAP measures of the numerator and denominator for margin share for convenience and electrification, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to calculate a meaningful comparable GAAP forward-looking financial measure. These items include inventory holding gains or losses, that is difficult to predict in advance in order to include in a GAAP estimate. Cumulative cash costs reductions Non-GAAP measure. Cash costs are a subset of production and manufacturing expenses plus distribution and administration expenses and they exclude costs that are classified as non-operating items. They represent the substantial majority of the remaining expenses in these line items but exclude certain costs that are variable, primarily with volumes (such as freight costs). Management believes that cash costs is a performance measure that provides investors with useful information regarding the company’s financial performance, because it considers these expenses to be the principal operating and overhead expenses that are most directly under their control although they also include certain foreign exchange and commodity price effects. Cumulative cash cost reductions in 2021 compared to 2019, as applicable to the directors’ remuneration usage, are further defined as 2021 exit rate, less agreed portfolio changes compared to 2019 baseline. bp Annual Report and Form 20-F 2020 343 Customer touchpoints Customer touchpoints are the number of retail customer transactions per day on bp forecourts globally. These include transactions involving fuel and/or convenience across all channels of trade. Developed renewables to final investment decision (FID) Total generating capacity for assets developed to FID by all entities where bp has an equity share (proportionate to equity share). If asset is subsequently sold bp will continue to record capacity as developed to FID. If bp equity share increases developed capacity to FID will increase proportionately to share increase for any assets where bp held equity at the point of FID. Divestment proceeds Disposal proceeds as per the group cash flow statement. Dividend yield Sum of the four quarterly dividends announced in respect of the year as a percentage of the year-end share price. Effective tax rate (ETR) on replacement cost (RC) profit or loss Non-GAAP measure. The ETR on RC profit or loss is calculated by dividing taxation on a RC basis by RC profit or loss before tax. Information on RC profit or loss is provided below. bp believes it is helpful to disclose the ETR on RC profit or loss because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 348. Electric vehicle charge points Defined as charge points operated by either bp or a bp joint venture. Fair value accounting effects Non-GAAP adjustments to our IFRS profit or loss. We use derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products. Under IFRS, these inventories are recorded at historical cost. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in the income statement. This is because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness-testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement, from the time the derivative commodity contract is entered into, on a fair value basis using forward prices consistent with the contract maturity. bp enters into physical commodity contracts to meet certain business requirements, such as the purchase of crude for a refinery or the sale of bp’s gas production. Under IFRS these physical contracts are treated as derivatives and are required to be fair valued when they are managed as part of a larger portfolio of similar transactions. Gains and losses arising are recognized in the income statement from the time the derivative commodity contract is entered into. IFRS require that inventory held for trading is recorded at its fair value using period-end spot prices, whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices, resulting in measurement differences. bp enters into contracts for pipelines and other transportation, storage capacity, oil and gas processing and liquefied natural gas (LNG) that, under IFRS, are recorded on an accruals basis. These contracts are risk- managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses. The way that bp manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. bp calculates this difference for consolidated entities by comparing the IFRS result with management’s internal measure of performance. Under management’s internal measure of performance the inventory, transportation and capacity contracts in 344 bp Annual Report and Form 20-F 2020 question are valued based on fair value using relevant forward prices prevailing at the end of the period. The fair values of derivative instruments used to risk manage certain oil, gas and other contracts, are deferred to match with the underlying exposure and the commodity contracts for business requirements are accounted for on an accruals basis. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole. Fair value accounting effects also include changes in the fair value of the near-term portions of LNG contracts that fall within bp’s risk management framework. LNG contracts are not considered derivatives, because there is insufficient market liquidity, and they are therefore accrual accounted under IFRS. However, oil and natural gas derivative financial instruments (used to risk manage the near-term portions of the LNG contracts) are fair valued under IFRS. The fair value accounting effect reduces timing differences between recognition of the derivative financial instruments used to risk manage the LNG contracts and the recognition of the LNG contracts themselves, which therefore gives a better representation of performance in each period. In addition, from 2020 fair value accounting effects include changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. The hybrid bonds which were issued on 17 June 2020 are classified as equity instruments and were recorded in the balance sheet at that date at their USD equivalent issued value. Under IFRS these equity instruments are not remeasured from period to period, and do not qualify for application of hedge accounting. The derivative instruments relating to the hybrid bonds, however, are required to be recorded at fair value with mark to market gains and losses recognized in the income statement. Therefore, measurement differences in relation to the recognition of gains and losses occur. The fair value accounting effect, which is reported in the Other businesses and corporate segment, eliminates the fair value gains and losses of these derivative financial instruments that are recognized in the income statement. We believe that this gives a better representation of performance, by more appropriately reflecting the economic effect of these risk management activities, in each period. Finance debt ratio Finance debt ratio is defined as the ratio of finance debt to the total of finance debt plus total equity. Free cash flow Operating cash flow less net cash used in investing activities and lease liability payments included in financing activities, as presented in the group cash flow statement. Gearing and net debt Non-GAAP measures. Net debt is calculated as finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign currency exchange and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. Gearing is defined as the ratio of net debt to the total of net debt plus total equity. bp believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing enables investors to see how significant net debt is relative to total equity. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. See Financial statements – Note 27 for information on finance debt, which is the nearest equivalent measure to net debt on an IFRS basis. The nearest equivalent GAAP measure to gearing on an IFRS basis is finance debt ratio. We are unable to present reconciliations of forward-looking information for gearing to finance debt ratio, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include fair value asset (liability) of hedges related to finance debt and cash and cash equivalents, that are difficult to predict in advance in order to include in a GAAP estimate. Gearing including leases and net debt including leases Non-GAAP measure. Net debt including leases is calculated as net debt plus lease liabilities, less the net amount of partner receivables and payables relating to leases entered into on behalf of joint operations. Gearing including leases is defined as the ratio of net debt including leases to the total of net debt including leases plus total equity. bp believes these measures provide useful information to investors as they enable investors to understand the impact of the group’s lease portfolio on net debt and gearing. See Financial statements – Note 27 for information on finance debt, which is the nearest equivalent measure to net debt including leases on an IFRS basis. The nearest equivalent GAAP measure to gearing including leases on an IFRS basis is finance debt ratio. Henry Hub A distribution hub on the natural gas pipeline system in Erath, Louisiana, that lends its name to the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange and the over-the-counter swaps traded on Intercontinental Exchange. Hydrocarbons Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels. Inorganic capital expenditure A subset of capital expenditure on a cash basis and is a non-GAAP measure. Inorganic capital expenditure comprises consideration in business combinations and certain other significant investments made by the group. It is reported on a cash basis. bp believes that this measure provides useful information as it allows investors to understand how bp’s management invests funds in projects which expand the group’s activities through acquisition. Further information and a reconciliation to GAAP information is provided on page 303. Inventory holding gains and losses The difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first- in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. See Replacement cost (RC) profit or loss definition below. Joint arrangement An arrangement in which two or more parties have joint control. Joint control Contractually agreed sharing of control over an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Joint operation A joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. Joint venture A joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Liquids Comprises crude oil, condensate and natural gas liquids. For the Upstream segment, it also includes bitumen. LNG portfolio LNG portfolio refers to bp group’s LNG equity production plus additional long-term merchant LNG volumes. LNG train An LNG train is a processing facility used to liquefy and purify natural gas in the formation of LNG. Low carbon energy / low carbon technologies Low carbon (renewable) electricity; bio-energy; electrification; future mobility solutions; carbon capture, use and storage (CCUS); “blue” or “green” hydrogen; and trading in low carbon products. Note that, while there is some overlap, these terms do not mean the same as bp’s strategic focus area of “low carbon electricity and energy”. Low carbon investment / investment in low carbon energy / investment in low carbon Capital expenditure on low carbon energy or technologies. Low carbon and other energy transition activities Low carbon energy / technologies as described above, together with convenience; integrated gas and power; bp Ventures and Launchpad. Major projects Have a bp net investment of at least $250 million, or are considered to be of strategic importance to bp or of a high degree of complexity. Margin share for convenience and electrification Non-GAAP measure. See Convenience, retail fuels and electrification gross margin definition. Non-operating items Charges and credits are included in the financial statements that bp discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed in order to enable investors better to understand and evaluate the group’s reported financial performance. Non-operating items within equity-accounted earnings are reported net of incremental income tax reported by the equity-accounted entity. An analysis of non-operating items by segment and type is shown on page 304. Operating cash flow Net cash provided by (used in) operating activities as stated in the group cash flow statement. When used in the context of a segment rather than the group, the terms refer to the segment’s share thereof. Operating cash flow excluding Gulf of Mexico oil spill payments Non-GAAP measure. It is calculated by excluding post-tax operating cash flows relating to the Gulf of Mexico oil spill from net cash provided by operating activities as reported in the group cash flow statement. bp believes net cash provided by operating activities excluding amounts related to the Gulf of Mexico oil spill is a useful measure as it allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is net cash provided by operating activities. Operating management system (OMS) bp’s OMS helps us manage risks in our operating activities by setting out bp’s principles for good operating practice. It brings together bp requirements on health, safety, security, the environment, social responsibility and operational reliability, as well as related issues, such as maintenance, contractor relations and organizational learning, into a common management system. Organic capital expenditure A subset of capital expenditure on a cash basis and is a non-GAAP measure. Organic capital expenditure comprises capital expenditure less inorganic capital expenditure. bp believes that this measure provides useful information as it allows investors to understand how bp’s management invests funds in developing and maintaining the group’s assets. An analysis of organic capital expenditure by segment and region, and a reconciliation to GAAP information is provided on page 303. We are unable to present reconciliations of forward-looking information for organic capital expenditure to total cash capital expenditure, because without unreasonable efforts, we are unable to forecast accurately the bp Annual Report and Form 20-F 2020 345 adjusting item, inorganic capital expenditure, that is difficult to predict in advance in order to derive the nearest GAAP estimate. shareholders. See Financial statements – Note 5. A reconciliation to GAAP information is provided on page 302. Production-sharing agreement / contract (PSA / PSC) An arrangement through which an oil and gas company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery. Readily marketable inventory (RMI) RMI is inventory held and price risk-managed by our integrated supply and trading function (IST) which could be sold to generate funds if required. It comprises oil and oil products for which liquid markets are available and excludes inventory which is required to meet operational requirements and other inventory which is not price risk-managed. RMI is reported at fair value. Inventory held by the Downstream fuels business for the purpose of sales and marketing, and all inventories relating to the lubricants and petrochemicals businesses, are not included in RMI. bp believes that disclosing the amounts of RMI and paid-up RMI is useful to investors as it enables them to better understand and evaluate the group’s inventories and liquidity position by enabling them to see the level of discretionary inventory held by IST and to see builds or releases of liquid trading inventory. Paid-up RMI excludes RMI which has not yet been paid for. For inventory that is held in storage, a first-in first-out (FIFO) approach is used to determine whether inventory has been paid for or not. Unpaid RMI is RMI which has not yet been paid for by bp. RMI at fair value, Paid-up RMI and Unpaid RMI are non-GAAP measures. A reconciliation of total inventory as reported on the group balance sheet to paid-up RMI is provided on page 349. Realizations Realizations are the result of dividing revenue generated from hydrocarbon sales, excluding revenue generated from purchases made for resale and royalty volumes, by revenue generating hydrocarbon production volumes. Revenue generating hydrocarbon production reflects the bp share of production as adjusted for any production which does not generate revenue. Adjustments may include losses due to shrinkage, amounts consumed during processing, and contractual or regulatory host committed volumes such as royalties. For the Upstream segment, realizations include transfers between businesses. Refining availability Represents Solomon Associates’ operational availability for bp-operated refineries, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory downtime. Refining marker margin (RMM) The average of regional indicator margins weighted for bp’s crude refining capacity in each region. Each regional marker margin is based on product yields and a marker crude oil deemed appropriate for the region. The regional indicator margins may not be representative of the margins achieved by bp in any period because of bp’s particular refinery configurations and crude and product slate. Replacement cost (RC) profit or loss Reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure of profit or loss that is required to be disclosed for each operating segment under IFRS. RC profit or loss for the group is a non-GAAP measure. Management believes this measure is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due to changes in prices as well as changes in underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, bp’s management believes it is helpful to disclose this measure. The nearest equivalent measure on an IFRS basis is profit or loss attributable to bp 346 bp Annual Report and Form 20-F 2020 RC profit or loss per share Non-GAAP measure. Earnings per share is defined in Financial statements – Note 11. RC profit or loss per share is calculated using the same denominator. The numerator used is RC profit or loss attributable to bp shareholders rather than profit or loss attributable to bp shareholders. bp believes it is helpful to disclose the RC profit or loss per share because this measure excludes the impact of price changes on the replacement of inventories and allows for more meaningful comparisons between reporting periods. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to bp shareholders. A reconciliation to GAAP information is provided on page 348. Renewables pipeline Renewable projects satisfying criteria below to the point they can be considered developed to FID : Site based projects have obtained land exclusivity rights, or for PPA based projects an offer has been made to the counterparty, or for auction projects pre-qualification criteria has been met, or for acquisition projects post a binding offer being accepted. Reserves replacement ratio The extent to which the year’s production has been replaced by proved reserves added to our reserve base. The ratio is expressed in oil- equivalent terms and includes changes resulting from discoveries, improved recovery and extensions and revisions to previous estimates, but excludes changes resulting from acquisitions and disposals. Retail sites Retail sites include sites operated by dealers, jobbers, franchisees or brand licensees or joint venture (JV) partners, under the bp brand. These may move to and from the bp brand as their fuel supply agreement or brand licence agreement expires and are renegotiated in the normal course of business. Retail sites are primarily branded bp, ARCO, Amoco, Aral and Thorntons, and also includes sites in India through our Jio-bp JV. Retail sites in growth markets These are retail sites that are either bp branded or co-branded with our partners in China, Mexico and Indonesia and also include sites in India through our Jio-bp JV. Return on average capital employed Non-GAAP measure. Return on average capital employed (ROACE) is underlying replacement cost profit, after adding back non-controlling interest and interest expense net of tax (for 2016 and 2017 interest expense was net of notional tax at an assumed 35%), divided by average capital employed (total equity plus finance debt), excluding cash and cash equivalents and goodwill. Interest expense is finance costs excluding lease interest and the unwinding of the discount on provisions and other payables before tax. bp believes it is helpful to disclose the ROACE because this measure gives an indication of the company's capital efficiency. The nearest GAAP measures of the numerator and denominator are profit or loss for the period attributable to bp shareholders and total equity respectively. The reconciliation of the numerator and denominator is provided on page 349. We are unable to present forward-looking information of the nearest GAAP measures of the numerator and denominator for ROACE, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to calculate a meaningful comparable GAAP forward-looking financial measure. These items include inventory holding gains or losses and interest net of tax, that are difficult to predict in advance in order to include in a GAAP estimate. Strategic convenience sites Strategic convenience sites are retail sites, within the bp portfolio, which both sell bp branded fuel and carry one of the strategic convenience brands (e.g. M&S, Rewe to Go). To be considered a strategic convenience brand the convenience offer should be a strategic differentiator in the market in which it operates. Strategic convenience site count includes sites under a pilot phase. Subsidiary An entity that is controlled by the bp group. Control of an investee exists when an investor is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Surplus cash Surplus cash refers to surplus of sources of cash including operating cash flow, joint venture loan repayments and divestment proceeds, over uses, including leases, Gulf of Mexico oil spill payments, hybrid servicing costs, dividend payments and cash capital expenditure. Tier 1 and tier 2 process safety events Tier 1 events are losses of primary containment from a process of greatest consequence – causing harm to a member of the workforce, damage to equipment from a fire or explosion, a community impact or exceeding defined quantities. Tier 2 events are those of lesser consequence. These represent reported incidents occurring within bp’s operational HSSE reporting boundary. That boundary includes bp’s own operated facilities and certain other locations or situations. Tight oil and gas Natural oil and gas reservoirs locked in hard sandstone rocks with low permeability, making the underground formation extremely tight. Traded electricity Traded electricity refers to sales data for physically delivered electricity. Transition and low carbon investments Capital expenditure on low carbon or other energy transition activities. UK National Balancing Point A virtual trading location for sale, purchase and exchange of UK natural gas. It is the pricing and delivery point for the Intercontinental Exchange natural gas futures contract. Unconventionals Resources found in geographic accumulations over a large area, that usually present additional challenges to development such as low permeability or high viscosity. Examples include shale gas and oil, coalbed methane, gas hydrates and natural bitumen deposits. These typically require specialized extraction technology such as hydraulic fracturing or steam injection. Underlying effective tax rate (ETR) Non-GAAP measure. The underlying ETR is calculated by dividing taxation on an underlying replacement cost (RC) basis by underlying RC profit or loss before tax. Taxation on an underlying RC basis is taxation on a RC basis for the period adjusted for taxation on non-operating items and fair value accounting effects, and certain foreign exchange impacts on the group’s tax charge for the period. Information on underlying RC profit or loss is provided below. bp believes it is helpful to disclose the underlying ETR because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is the ETR on profit or loss for the period. A reconciliation to GAAP information is provided on page 348. We are unable to present reconciliations of forward-looking information for underlying ETR to ETR on profit or loss for the period, because without unreasonable efforts, we are unable to forecast accurately certain adjusting items required to present a meaningful comparable GAAP forward-looking financial measure. These items include the taxation on inventory holding gains and losses, non-operating items and fair value accounting effects, that are difficult to predict in advance in order to include in a GAAP estimate. Underlying production Production after adjusting for acquisitions and divestments and entitlement impacts in our production-sharing agreements (PSAs). 2021 underlying production, when compared with 2020, is production after adjusting for acquisitions and divestments, curtailments, and entitlement impacts in our production-sharing agreements/contracts and technical service contract. Underlying replacement cost (RC) profit or loss Non-GAAP measure. RC profit or loss after adjusting for non-operating items and fair value accounting effects. Fair value accounting effects are non-GAAP adjustments. See pages 304 and 305 for additional information on the non-operating items and fair value accounting effects that are used to arrive at underlying RC profit or loss in order to enable a full understanding of the events and their financial impact. bp believes that underlying RC profit or loss is a useful measure for investors because it is a measure closely tracked by management to evaluate bp’s operating performance and to make financial, strategic and operating decisions and because it may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, year on year, by adjusting for the effects of these non-operating items and fair value accounting effects. The nearest equivalent measure on an IFRS basis for the group is profit or loss for the year attributable to bp shareholders. The nearest equivalent measure on an IFRS basis for segments is RC profit or loss before interest and taxation. A reconciliation to GAAP information is provided on page 302. Underlying replacement cost (RC) profit or loss per share Non-GAAP measure. Earnings per share is defined Financial statements – Note 11. Underlying RC profit or loss per share is calculated using the same denominator. The numerator used is underlying RC profit or loss attributable to bp shareholders rather than profit or loss attributable to bp shareholders. bp believes it is helpful to disclose the underlying RC profit or loss per share because this measure may help investors to understand and evaluate, in the same manner as management, the underlying trends in bp’s operational performance on a comparable basis, period on period. The nearest equivalent measure on an IFRS basis is basic earnings per share based on profit or loss for the period attributable to bp shareholders. A reconciliation to GAAP information is provided on page 348. Upstream plant reliability bp-operated Upstream plant reliability is calculated taking 100% less the ratio of total unplanned plant deferrals divided by installed production capacity. Unplanned plant deferrals are associated with the topside plant and where applicable the subsea equipment (excluding wells and reservoir). Unplanned plant deferrals include breakdowns, which does not include Gulf of Mexico weather related downtime. Upstream unit production costs Upstream unit production costs are calculated as production costs divided by units of production. Production costs do not include ad valorem and severance taxes. Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts disclosed are for bp subsidiaries only and do not include bp’s share of equity-accounted entities. West Texas Intermediate (WTI) A light sweet crude oil, priced at Cushing, Oklahoma, which serves as a benchmark price for purchases of oil in the US. Working capital Movements in inventories and other current and non-current assets and liabilities as stated in the group cash flow statement. Trade marks Trade marks of the bp group appear throughout this report. They include: Aral, ARCO, BP, bp pulse, Castrol, Amoco, Thorntons Trade marks: Amazon Web Services – a trademark of amazon.com, inc REWE to Go – a registered trade mark of REWE. bp Annual Report and Form 20-F 2020 347 Non-GAAP measures reconciliations Reconciliation of basic earnings per ordinary share to RC profit (loss) per share and to underlying RC profit per share Profit (loss) for the yeara Inventory holding (gains) losses, before tax Taxation charge (credit) on inventory holding gains and losses RC profit (loss) for the year Net (favourable) adverse impact of non-operating items and fair value accounting effects, before tax Taxation charge (credit) on non-operating items and fair value accounting effects Underlying RC profit for the year a Profit attributable to bp shareholders. Per ordinary share – cents 2020 (100.42) 14.18 (3.29) (89.53) 2019 19.84 (3.29) 0.77 17.32 2018 46.98 4.01 (0.99) 50.00 2017 17.20 (4.32) 1.14 14.02 2016 0.61 (8.52) 2.58 (5.33) 82.33 40.73 16.93 18.94 35.99 (20.94) (28.14) (8.81) 49.24 (3.23) 63.70 (1.65) 31.31 (16.87) 13.79 Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss and adjusted ETR Taxation (charge) credit Taxation on profit or loss for the year Adjusted for taxation on inventory holding gains and losses Taxation on a RC profit or loss basis Adjusted for taxation on non-operating items and fair value accounting effects, and certain foreign exchange impacts on the group’s tax charge for the period Adjusted for the impact of US tax reform Taxation on an underlying RC basis Adjusted for the impact of the reduction in the rate of the UK North Sea supplementary charge Adjusted taxation Effective tax rate ETR on profit or loss for the year Adjusted for inventory holding gains and losses ETR on RC profit or loss Adjusted for non-operating items and fair value accounting effects, and certain foreign exchange impacts on the group’s tax charge for the period Adjusted for the impact of US tax reform Underlying ETR Adjusted for the impact of the reduction in the rate of the UK North Sea supplementary charge Adjusted ETR 2020 4,159 667 3,492 4,235 — (743) — (743) 2020 17 (1) 16 (30) — (14) — (14) 2019 (3,964) (156) (3,808) 2018 (7,145) 198 (7,343) 2017 (3,712) (225) (3,487) 1,788 — 522 121 1,184 (859) (5,596) (7,986) (3,812) — (5,596) — (7,986) — (3,812) 2019 2018 2017 49 2 51 (15) — 36 — 36 43 (1) 42 (5) 1 38 — 38 52 3 55 (9) (8) 38 — 38 $ million 2016 2,467 (483) 2,950 3,162 — (212) 434 (646) % 2016 107 (31) 76 (69) — 7 16 23 348 bp Annual Report and Form 20-F 2020 « See Glossary Return on average capital employed (ROACE) Profit (loss) for the year attributable to bp shareholders Inventory holding (gains) losses, net of tax Non-operating items and fair value accounting effects, net of tax Underlying RC profit Interest expense, net of taxa Non-controlling interests (NCI) Underlying RC profit attributable to bp shareholders and NCI, excluding interest expense net of tax Total equity Finance debt Capital employed (2020 average $163,332 million) Less: Goodwill Cash and cash equivalents Average capital employed excluding goodwill and cash and cash equivalents ROACE a Calculated on a post-tax basis (for 2017 and earlier interest expense was net of notional tax at an assumed 35%). 2020 (20,305) 2,201 12,414 (5,690) 1,402 (424) (4,712) 2019 2018 2017 4,026 (511) 6,475 9,990 1,744 164 11,898 9,383 603 2,737 12,723 1,583 195 14,501 3,389 (628) 3,405 6,166 924 79 7,169 $ million 2016 115 (1,114) 3,584 2,585 635 57 3,277 85,568 72,664 158,232 12,480 31,111 114,641 124,367 100,708 67,724 168,432 11,868 22,472 134,092 133,050 101,548 65,132 166,680 12,204 22,468 132,008 128,925 100,404 62,574 162,978 11,551 25,586 125,841 122,836 96,843 57,665 154,508 11,194 23,484 119,830 116,333 (3.8) % 8.9 % 11.2 % 5.8 % 2.8 % Readily marketable inventory (RMI) Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by bp's integrated supply and trading function (IST) which could be sold to generate funds if required. Details of RMI balances and a reconciliation to GAAP information is set out below. Further information on RMI, RMI at fair value, paid-up RMI and unpaid RMI is provided on page 345. At 31 December RMI at fair value Paid-up RMI Reconciliation of non-GAAP information At 31 December Reconciliation of total inventory to paid-up RMI Inventories as reported on the group balance sheet Less: (a) inventories which are not oil and oil products and (b) oil and oil product inventories which are not risk- managed by IST RMI on IFRS basis Plus: difference between RMI at fair value and RMI on an IFRS basis RMI at fair value Less: unpaid RMI at fair value Paid-up RMI 2020 6,528 3,365 $ million 2019 6,837 3,217 2020 $ million 2019 16,873 20,880 (10,810) 6,063 465 6,528 (3,163) 3,365 (14,280) 6,600 237 6,837 (3,620) 3,217 The Directors’ report on pages 71-102, 105 (in respect of the remuneration committee report shown in grey only), 127-128, 231-258 and 301-349 was approved by the board and signed on its behalf by Ben J. S. Mathews, company secretary on 22 March 2021. BP p.l.c. Registered in England and Wales No. 102498 « See Glossary bp Annual Report and Form 20-F 2020 349 Signatures The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf. BP p.l.c. (Registrant) /s/ Ben J. S. Mathews Company secretary 22 March 2021 350 bp Annual Report and Form 20-F 2020 Cross reference to Form 20-F A. B. C. D. A. B. C. D. A. B. C. D. E. F. G. A. B. C. D. E. A. B. C. A. B. A. B. C. D. E. F. A. B. C. D. E. F. G. H. I. A. B. C. D. Item 1. Item 2. Item 3. Item 4. Item 4A. Item 5. Item 6. Item 7. Item 8. Item 9. Item 10. Item 11. Item 12. Item 13. Item 14. Item 15. Item 16A. Item 16B. Item 16C. Item 16D. Item 16E. Item 16F. Item 16G. Item 17. Item 18. Item 19. Identity of Directors, Senior Management and Advisors Offer Statistics and Expected Timetable Key Information Selected financial data Capitalization and indebtedness Reasons for the offer and use of proceeds Risk factors Information on the Company History and development of the company Business overview Organizational structure Property, plants and equipment Unresolved Staff Comments Operating and Financial Review and Prospects Operating results Liquidity and capital resources Research and development, patent and licenses Trend information Off-balance sheet arrangements Tabular disclosure of contractual commitments Safe harbor Directors, Senior Management and Employees Directors and senior management Compensation Board practices Employees Share ownership Major Shareholders and Related Party Transactions Major shareholders Related party transactions Interests of experts and counsel Financial Information Consolidated statements and other financial information Significant changes The Offer and Listing Offer and listing details Plan of distribution Markets Selling shareholders Dilution Expenses of the issue Additional Information Share capital Memorandum and articles of association Material contracts Exchange controls Taxation Dividends and paying agents Statements by experts Documents on display Subsidiary information Quantitative and Qualitative Disclosures about Market Risk Description of securities other than equity securities Debt Securities Warrants and Rights Other Securities American Depositary Shares Defaults, Dividend Arrearages and Delinquencies Material Modifications to the Rights of Security Holders and Use of Proceeds Controls and Procedures Audit Committee Financial Expert Code of Ethics Principal Accountant Fees and Services Exemptions from the Listing Standards for Audit Committees Purchases of Equity Securities by the Issuer and Affiliated Purchasers Change in Registrant’s Certifying Accountant Corporate governance Financial Statements Financial Statements Exhibits Page n/a n/a 302, 332 n/a n/a 67-70 8-14, 15-19, 25, 36, 38, 42-47, 108-112, 180-183, 230, 308-311, 318-319, 321-325, 330 33, 38, 42-47, 177-180, 184, 190, 192-195, 308-320 39-41, 45, 189, 190-191, 256-258, 308-321, 326 None 230 8-14, 15-19, 25, 38, 42-47, 67-70, 108-109, 111-112, 192-194, 204, 206-219, 308-325 158-159, 190, 204-225, 304-305 183, 326 8-19, 25, 38, 42-47, 108-109, 111-112, 308-320 180-183, 192-194, 307 307 329-330 74-79 39-41, 103-128, 197-203, 228-229 74-77, 94-99, 105 57-58, 229 57-58, 103-126, 197-203, 228 334-335 192-194, 326 n/a 130-258, 332 n/a 332 n/a 332 n/a n/a n/a n/a 335-337 326 332 332-334 n/a n/a 339 n/a 206-211 n/a n/a n/a 339 None None 154, 326-327 76, 94-99 326 96-97, 229, 327 n/a 338 n/a 326 n/a 155-159 352 bp Annual Report and Form 20-F 2020 351 Information about this report This document constitutes the Annual Report and Accounts in accordance with UK requirements and the Annual Report on Form 20-F in accordance with the US Securities Exchange Act of 1934, for BP p.l.c. for the year ended 31 December 2020. A cross reference to Form 20-F requirements is included on page 351. This document contains the Strategic report on the inside front cover and pages 1-70 and the Directors’ report on pages 71-102, 105 (in part only), 127-128, 231-258 and 301-349. The Strategic report and the Directors’ report together include the management report required by DTR 4.1 of the UK Financial Conduct Authority’s Disclosure Guidance and Transparency Rules. The Directors’ remuneration report is on pages 103-126. The consolidated financial statements of the group are on pages 129-230 and the corresponding reports of the auditor are on pages 130-154. The parent company financial statements of BP p.l.c. are on pages 259-300. The Directors’ statements (comprising the Statement of directors’ responsibilities; Risk management and internal control; Longer-term viability; Going concern; and Fair, balanced and understandable), the independent auditor’s report on the annual report and accounts to the members of BP p.l.c., the parent company financial statements of BP p.l.c. and corresponding auditor’s report and a non-GAAP measure of operating cash flow excluding Gulf of Mexico oil spill payments« in the tables on pages 41, 43 and 46 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC. bp Annual Report and Form 20-F 2020 may be downloaded from bp.com/ annualreport. No material on the bp website, other than the items identified as bp Annual Report and Form 20-F 2020, forms any part of this document. References in this document to other documents on the bp website, such as bp Energy Outlook, bp Sustainability Report, bp Statistical Review of World Energy and bp Technology Outlook are included as an aid to their location and are not incorporated by reference into this document. BP p.l.c. is the parent company of the bp group of companies. The company was incorporated in 1909 in England and Wales and changed its name to BP p.l.c. in 2001. Where we refer to the company, we mean BP p.l.c. The company and each of its subsidiaries« are separate legal entities. Unless otherwise stated or the context otherwise requires, the term “BP” or "bp" and terms such as “we”, “us” and “our” are used in this report for convenience to refer to one or more of the members of the bp group instead of identifying a particular entity or entities. Information in this document reflects 100% of the assets and operations of the company and its subsidiaries that were consolidated at the date or for the periods indicated, including non-controlling interests. The company’s primary share listing is the London Stock Exchange. In the US, the company’s securities are traded on the New York Stock Exchange (NYSE) in the form of ADSs (see page 332 for more details) and in Germany in the form of a global depositary certificate representing bp ordinary shares traded on the Frankfurt, Hamburg and Dusseldorf Stock Exchanges. The term ‘shareholder’ in this report means, unless the context otherwise requires, investors in the equity capital of BP p.l.c., both direct and indirect. As the company's shares, in the form of ADSs, are listed on the NYSE, an Annual Report on Form 20-F is filed with the SEC. Ordinary shares are ordinary fully paid shares in BP p.l.c. of 25 cents each. Preference shares are cumulative first preference shares and cumulative second preference shares in BP p.l.c. of £1 each. Registered office and our worldwide headquarters: BP p.l.c. 1 St James’s Square Our agent in the US: BP America Inc. 501 Westlake Park Boulevard London SW1Y 4PD Houston, Texas 77079 UK US Tel +44 (0)20 7496 4000 Tel +1 281 366 2000 Registered in England and Wales No. 102498. London Stock Exchange symbol ‘BP.’ Exhibits The following documents are filed in the Securities and Exchange Commission (SEC) EDGAR system, as part of this Annual Report on Form 20-F, and can be viewed on the SEC’s website. Exhibit 1 Exhibit 2 Exhibit 4.1 Exhibit 4.4 Memorandum and Articles of Association of BP p.l.c.***† Description of rights of each class of securities registered under Section 12 of the Securities Exchange Act of 1934† The BP Executive Directors’ Incentive Plan**† Director’s Service Agreement for B Looney****† Exhibit 4.7 Director’s Service Contract for M Auchincloss† Exhibit 4.10 Exhibit 8 Exhibit 11 Exhibit 12 Exhibit 13 Exhibit 15.1 Exhibit 15.2 Exhibit 15.3 Exhibit 15.4 Exhibit 15.5 Exhibit 15.6 Exhibit 15.7 Exhibit 15.8 Exhibit 99.1 Exhibit 99.2 Exhibit 101 Exhibit 104 The BP Share Award Plan 2015***† Subsidiaries (included as Note 37 to the Financial Statements) Code of Ethics*† Rule 13a – 14(a) Certifications† Rule 13a – 14(b) Certifications#† Consent of DeGolyer and MacNaughton† Report of DeGolyer and MacNaughton† Consent of Netherland, Sewell & Associates† Report of Netherland, Sewell & Associates† Consent Decree***† Gulf states Settlement Agreement***† Consent of Deloitte LLP† Consent of Ernst & Young LLC regarding opinion in Exhibit 99.1† Consolidated financial statements of Rosneft Oil Company as at and for the years ended 31 December 2020 (unaudited) and 2019† Consolidated financial statements of Rosneft Oil Company as at and for the years ended 31 December 2018 (unaudited) and 2017 (unaudited)† Inline XBRL data files Cover page interactive data file (formatted as Inline XBRL and contained in Exhibit 101) * Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 31 December 2009. ** Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 31 December 2014. *** Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 31 December 2015. **** Incorporated by reference to the company’s Annual Report on Form 20-F for # † the year ended 31 December 2019. Furnished only. Included only in the annual report filed in the Securities and Exchange Commission EDGAR system. The total amount of long-term securities of BP p.l.c. and its subsidiaries under any one instrument does not exceed 10% of their total assets on a consolidated basis. The company agrees to furnish copies of any or all such instruments to the SEC on request. Paper: Nautilus Super White is a premium ecological paper. It is made from 100% post-consumer waste recycled paper and is FSC® (Forest Stewardship Council®) certified. The paper also holds the EU Ecolabel certification. The manufacturing mill also holds ISO 14001 environmental certification. Printed in the UK by Pureprint Group. 352 bp Annual Report and Form 20-F 2020 « See Glossary   Copies You can order bp’s printed publications free of charge from bp.com/annualreport. US and Canada Issuer Direct Toll-free: +1 888 301 2505 bpreports@issuerdirect.com UK and rest of world bp Distribution Services Tel: +44 (0)870 241 3269 bpdistributionservices@bp.com Feedback Your feedback is important to us. You can contact the corporate reporting team at corporatereporting@bp.com b p A n n u a l R e p o r t a n d F o r m 2 0 - F 2 0 2 0 bp’s corporate reporting suite includes information about our financial and operating performance, sustainability performance and also on global energy trends and projections. Annual Report and Form 20-F 2020 Details of our financial and operating performance in print and online. bp.com/annualreport Energy Outlook Provides our projections of future energy trends and factors that could affect them. bp.com/energyoutlook Sustainability Report 2020 Details of our sustainability performance with additional information online. bp.com/sustainability Statistical Review of World Energy 2020 An objective review of key global energy trends. bp.com/statisticalreview Financial and Operating Information 2016-2020 Five-year financial and operating data in PDF and Excel format. bp.com/financialandoperating © BP p.l.c. 2021 

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