Over the past six years BP has delivered around $75 billion of divestments, focused investment to build a distinctive and balanced portfolio, and improved safety, reliability and underlying performance. Group chief executive Bob Dudley and his management team are now setting out plans to 2021, demonstrating how BP plans to deliver growth throughout its businesses over the next five years.
Bob Dudley said: “In six years we have fundamentally reshaped and built a very different BP. We are now stronger and more focused - fully competitive and fit for a fast-changing future.
“We have proven financial discipline, clear plans in action and have built a distinctive portfolio which gives us a strong platform for growth, now and into the future. Striking a balance between short and long-term value, our recent acquisitions and agreements have strengthened this even further.
“We can see growth ahead right across the Group. While always maintaining our discipline on costs and capital, BP is now getting back to growth – today, over the medium term and over the very long term.”
Over the next five years BP expects both of its major operating segments to deliver material growth in operating cash flows while the Group maintains its existing financial frame. In the Upstream, growth is expected to come from a continuing series of major higher-margin project start-ups, while the Downstream expects to deliver strong marketing-led growth, both underpinned by BP’s continued focus on safe and reliable operations, increasing efficiency, simplification and modernisation.
Production ramping up from new Upstream projects is expected to deliver a material improvement in BP’s operating cash flow through the second half of 2017.
BP intends to maintain its existing financial frame throughout the five years to 2021, with organic capital expenditure kept within a range of $15-17 billion a year and the target band for gearing remaining at 20-30%.
Brian Gilvary, BP chief financial officer, said: “Last year we delivered our targeted $7 billion reduction in cash costs a year early, and capital spending was $8.6 billion lower than its peak in 2013 – without damaging our growth pipeline. We will continue that tight focus on costs and capital discipline and seek further improvements throughout the Group.
“We expect this combination of continued cost discipline with the growing cash flow from our core businesses - and the recent portfolio additions - will steadily drive down the cash balance point of the business. Over the next five years we expect this to fall to around $35-40 a barrel for the Group overall.”
Volume and margin growth throughout BP’s businesses are expected to increase returns over the next five years. Assuming a stable price environment and portfolio, BP now expects return on average capital employed (ROACE) for the Group to recover steadily over the next few years and to be over 10% by 2021.
Over the past five years BP’s Upstream segment has begun production from 24 major projects, including six in 2016. Seven projects are expected online during 2017 - making it one of the largest years for commissioning new projects in BP’s history. These projects are on average ahead of schedule and below budget. A further nine projects that are expected to start up through 2018-2021 are already under construction.
The projects coming on line in 2016 and 2017 are on track to deliver 500,000 barrels of oil equivalent a day (boe/d) new production capacity by the end of this year.
The new Upstream projects remain on track to deliver 800,000 boe/d of new production by 2020, as previously guided. On average, the new projects are also expected to have operating cash margins 35% higher than the average of BP’s Upstream portfolio in 2015.
More than 200,000 boe/d of production is expected by the end of the decade from the recent additions to BP’s portfolio – primarily from the ADCO onshore concession.
This strong pipeline means that BP is now confident that Upstream production will grow from 2016 by an average of 5% a year out to 2021. BP Group production, including BP’s share of production from Rosneft, is expected to be around 4 million boe/d by 2021.
With capital investment kept steady and increasingly efficient operations and modernisation driving costs lower, BP now estimates that this growth will enable the Upstream segment to generate $13-14 billion of pre-tax free cash flow by 2021, at oil prices around $55 a barrel.
BP’s Downstream segment has delivered $3 billion sustainable reductions in cash costs since 2014 – halving the refining margin needed for the segment to deliver a pre-tax return of 15%.
In its refining and petrochemicals manufacturing businesses, BP expects the Downstream to deliver further performance improvements by continuing to focus on efficiency and operational performance, improving both competitiveness and resilience to the price and margin environment. Underlying earnings from the manufacturing businesses in 2021 are expected to be $2.5 billion higher than in 2014.
BP also expects significant earnings growth from its Downstream marketing businesses, with underlying earnings in 2021 more than $3 billion higher than in 2014. In lubricants, growth is expected to come from increasing the sales mix of premium lubricants, exposure to growth markets and BP and Castrol’s differentiated offers, brands and technologies. In BP’s fuels marketing activities, particularly retail, growth is expected to come through premium fuels, differentiated convenience partnerships – such as the recent agreement with Woolworths in Australia - and access to growth markets.
Combined with the ongoing focus on simplification and efficiency throughout the segment, BP believes this growth will enable the Downstream to deliver $9-10 billion of pre-tax free cash flow by 2021, with returns of around 20% in 2021.
Beyond the next five years, BP’s strategy also aims to ensure that the company continues to meet the energy demands of a changing world.
BP’s Alternative Energy business – comprising US Wind and Brazilian biofuels – is already the largest operated renewables business among oil and gas peer companies and BP is further optimising and improving efficiency to deliver incremental growth. In Wind BP is upgrading some of its existing turbines and, in biofuels, has debottlenecked manufacturing sites to increase production.
BP is also exploring new business models and technologies which may potentially develop into options for material businesses in the future, with investment into venturing in areas such as low-carbon, digital and mobility to incubate and grow options for the future.
BP press office, London: +44 (0)20 7496 4076, [email protected]
In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’), BP is providing the following cautionary statement. This press release contains certain forward-looking statements concerning expectations that Upstream and Downstream pre-tax cash flow will reach $13-14 billion (at an oil price of $55 per barrel) and $9-10 billion, respectively in 2021; plans and expectations to maintain organic capital spending at $15-16 billion per year and gearing between 20% and 30%; plans and expectations to start up 7 projects 2017 and 9 projects between 2018 and 2021; expectations to reach an oil price cash balance point at around $35-40 per barrel over the next five years; expectations that return on average capital employed will exceed 10% in 2021; expectations that Upstream growth will come from higher-margin project start-ups and Downstream growth will come from marketing; expectations that production ramp-up from new Upstream projects will deliver improvement in operating cash flow through the second half of 2017; expectations that Upstream projects coming on line in 2016 and 2017 will add approximately 500 thousand barrels per day of new oil equivalent production in 2017 and 800 thousand barrels per day of new oil equivalent production by 2020; expectations that new Upstream projects will average approximately 35% better margins than the 2015 portfolio; expectations that Upstream additions will add more than 200 thousand barrels per day of oil equivalent production by the end of the decade primarily from the ADCO onshore concession and Zohr in Egypt; expectations that Upstream production will grow at an average of 5% per year to 2021; expectations that BP Group production will be 4 million boe/d by 2021; expectations that underlying earnings from the Downstream manufacturing businesses in 2021 will be $2.5 billion higher than in 2014; expectations that underlying earnings of BP’s Downstream marketing business will be $3 billion higher in 2021 than in 2014; expectations that the Downstream lubricants business will grow due to product mix and differentiated offers, brands and technologies; and expectations that the Downstream fuels business will grow due to sales of premium fuels, convenience partnerships such as the agreement with Woolworths in Australia and access to growth markets. Actual results may differ from those expressed in such statements, depending on a variety of factors including changes in public expectations and other changes to business conditions; the timing, quantum and nature of divestments; the receipt of relevant third-party and/or regulatory approvals; future levels of industry product supply; demand and pricing; OPEC quota restrictions; PSA effects; operational problems; regulatory or legal actions; economic and financial 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; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors, trading partners and others; natural disasters and adverse weather conditions; wars and acts of terrorism, cyber-attacks or sabotage; and other factors discussed under “Principal risks and uncertainties” in our Stock Exchange Announcement for the period ended 30 June 2016 and under "Risk factors" in our Annual Report and Form 20-F 2015.
This press release contains references to non-proved resources and production outlooks based on non-proved resources that the SEC's rules prohibit us from including in our filings with the SEC. U.S. investors are urged to consider closely the disclosures in our Form 20-F, SEC File No. 1-06262. This form is available on our website at www.bp.com. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or by logging on to their website at www.sec.gov
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A month ago, the world witnessed something never thought possible – negative oil prices. A perfect storm of events – the Covid-19 lockdowns, the resulting effect on demand, an ongoing oil supply glut, a worrying shortage of storage space and (crucially) the expiry of the NYMEX WTI benchmark contract for May, resulted in US crude oil prices falling as low as -US$37/b. Dragging other North American crude markers like Louisiana Light and Western Canadian Select along with it, the unique situation meant that crude sellers were paying buyers to take the crude off their hands before the May contract expired, or risk being stuck with crude and nowhere to store it. This was seen as an emblem of the dire circumstances the oil industry was in, and although prices did recover to a more normal US$10-15/b level after the benchmark contract switched over to June, there was immense worry that the situation would repeat itself.
Thankfully, it has not.
On May 19, trade in the NYMEX WTI contract for June delivery was retired and ticked over into a new benchmark for July delivery. Instead of a repeat of the meltdown, the WTI contract rose by US$1.53 to reach US$33.49/b, closing the gap with Brent that traded at US$35.75b. In the space of a month, US crude prices essentially swung up by US$70/b. What happened?
The first reason is that the market has learnt its lesson. The meltdown in April came because of an overleveraged market tempted by low crude oil prices in hope of selling those cargoes on later at a profit. That sort of strategic trading works fine in a normal situation, but against an abnormal situation of rapidly-shrinking storage space saw contract holders hold out until the last minute then frantically dumping their contracts to avoid having to take physical delivery. Bruised by this – and probably embarrassed as well – it seems the market has taken precautions to avoid a recurrence. Settling contracts early was one mechanism. Funds and institutions have also reduced their positions, diminishing the amount of contracts that need to be settled. The structural bottleneck that precipitated the crash was largely eliminated.
The second is that the US oil complex has adjusted itself quickly. Some 2 mmb/d of crude production has been (temporarily) idled, reducing supply. The gradual removal of lockdowns in some US states, despite medical advisories, has also recovered some demand. This week, crude draws in Cushing, Oklahoma rose for the second consecutive week, reaching a record figure of 5.6 million barrels. That increase in demand and the parallel easing of constrained storage space meant that last month’s panic was not repeated. The situation is also similar worldwide. With China now almost at full capacity again and lockdowns gradually removed in other parts of the world, the global crude marker Brent also rose to a 2-month high. The new OPEC+ supply deal seems to be working, especially with Saudi Arabia making an additional voluntary cut of 1 mmb/d. The oil world is now moving rapidly towards a new normal.
How long will this last? Assuming that the Covid-19 pandemic is contained by Q3 2020, then oil prices could conceivably return to their previous support level of US$50/b. That is a big assumption, however. The Covid-19 situation is still fragile, with major risks of additional waves. In China and South Korea, where the pandemic had largely been contained, recent detection of isolated new clusters prompted strict localised lockdowns. There is also worry that the US is jumping the gun in easing restrictions. In Russia and Brazil – countries where the advice to enforce strict lockdowns was ignored as early warning signs crept in – the number of cases and deaths is still rising rapidly. Brazil is a particular worry, as President Jair Bolosnaro is a Covid-19 skeptic and is still encouraging normal behaviour in spite of the accelerating health crisis there. On the flip side, crude output may not respond to the increase in demand as easily, as many clusters of Covid-19 outbreaks have been detected in key crude producing facilities worldwide. Despite this, some US shale producers have already restarted their rigs, spurred on by a need to service their high levels of debt. US pipeline giant Energy Transfer LP has already reported that many drillers in the Permian have resumed production, citing prices in the high-US$20/b level as sufficient to cover its costs.
The recovery is ongoing. But what is likely to happen is an erratic recovery, with intermittent bouts of mini-booms and mini-busts. Consultancy IHS Markit Energy Advisory envisions a choppy recovery with ‘stop-and-go rallies’ over 2020 – particularly in the winter flu season – heading towards a normalisation only in 2021. It predicts that the market will only recover to pre-Covid 19 levels in the second half of 2021, and a smooth path towards that only after a vaccine is developed and made available, which will be late 2020 at the earliest. The oil market has moved from certain doom to cautious optimism in the space of a month. But it will take far longer for the entire industry to regain its verve without any caveats.
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Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020
As mitigation efforts to contain the 2019 novel coronavirus disease (COVID-19) pandemic continue to lead to rapid declines in petroleum consumption around the world, the production of liquid fuels globally has changed more slowly, leading to record increases in the amount of crude oil and other petroleum liquids placed into storage in recent months. In its May Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) expects global inventory builds will be largest in the first half of 2020. EIA estimates that inventory builds rose at a rate of 6.6 million barrels per day (b/d) in the first quarter and will increase by 11.5 million b/d in the second quarter because of widespread travel limitations and sharp reductions in economic activity.
After the first half of 2020, EIA expects global liquid fuels consumption to increase, leading to inventory draws for at least six consecutive quarters and ultimately putting upward pressure on crude oil prices that are currently at their lowest levels in 20 years.
As with the March and April STEO, EIA’s forecast reductions in global oil demand arise from three main drivers: lower economic growth, less air travel, and other declines in demand not captured by these two categories, largely related to reductions in travel because of stay-at-home orders. Based on incoming economic data and updated assessments of lockdowns and stay-at-home orders across dozens of countries, EIA has further lowered its forecasts for global oil demand in 2020 in the May STEO. The STEO is based on macroeconomic projections by Oxford Economics (for countries other than the United States) and by IHS Markit (for the United States).
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020
In the May STEO, EIA forecasts global liquid fuels consumption will average 92.6 million b/d in 2020, down 8.1 million b/d from 2019. EIA forecasts both economic growth and global consumption of liquid fuels to increase in 2021 but remain lower than 2019 levels. Any lasting behavioral changes to patterns in transportation and other forms of oil consumption once COVID-19 mitigation efforts end, however, present considerable uncertainty to the increase in consumption of liquid fuels, even if gross domestic product (GDP) growth increases.
Members of the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) agreed to new production cuts in early April that will remain in place throughout the STEO forecast period ending in 2021. EIA assumes OPEC members will mostly adhere to announced cuts during the first two months of the agreement (May and June) and that production compliance will relax later in the forecast period as stated production cuts are reduced and global oil demand begins growing.
EIA forecasts OPEC crude oil production will fall to less than 24.1 million b/d in June, a 6.3 million b/d decline from April, when OPEC production increased following an inconclusive meeting in March. If OPEC production declines to less than 24.1 million b/d, it would be the group’s lowest level of production since March 1995. The forecast for June OPEC production does not account for the additional voluntary cuts announced by Saudi Arabia’s Energy Ministry on May 11.
EIA expects OPEC production will begin increasing in July 2020 in response to rising global oil demand and prices. From that point, EIA expects a gradual increase in OPEC crude oil production through the remainder of the forecast and for production to rise to an average of 28.5 million b/d during the second half of 2021.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020
EIA forecasts the supply of non-OPEC petroleum and other liquid fuels will decline by 2.4 million b/d in 2020 compared with 2019. The steep decline reflects lower forecast oil prices in the second quarter as well as the newly implemented production cuts from non-OPEC participants in the OPEC+ agreement. EIA expects the largest non-OPEC production declines in 2020 to occur in Russia, the United States, and Canada.