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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Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
Headlines of the week
Midstream & Downstream
Risk and reward – improving recovery rates versus exploration
A giant oil supply gap looms. If, as we expect, oil demand peaks at 110 million b/d in 2036, the inexorable decline of fields in production or under development today creates a yawning gap of 50 million b/d by the end of that decade.
How to fill it? It’s the preoccupation of the E&P sector. Harry Paton, Senior Analyst, Global Oil Supply, identifies the contribution from each of the traditional four sources.
1. Reserve growth
An additional 12 million b/d, or 24%, will come from fields already in production or under development. These additional reserves are typically the lowest risk and among the lowest cost, readily tied-in to export infrastructure already in place. Around 90% of these future volumes break even below US$60 per barrel.
2. pre-drill tight oil inventory and conventional pre-FID projects
They will bring another 12 million b/d to the party. That’s up on last year by 1.5 million b/d, reflecting the industry’s success in beefing up the hopper. Nearly all the increase is from the Permian Basin. Tight oil plays in North America now account for over two-thirds of the pre-FID cost curve, though extraction costs increase over time. Conventional oil plays are a smaller part of the pre-FID wedge at 4 million b/d. Brazil deep water is amongst the lowest cost resource anywhere, with breakevens eclipsing the best tight oil plays. Certain mature areas like the North Sea have succeeded in getting lower down the cost curve although volumes are small. Guyana, an emerging low-cost producer, shows how new conventional basins can change the curve.
3. Contingent resource
These existing discoveries could deliver 11 million b/d, or 22%, of future supply. This cohort forms the next generation of pre-FID developments, but each must overcome challenges to achieve commerciality.
Last, but not least, yet-to-find. We calculate new discoveries bring in 16 million b/d, the biggest share and almost one-third of future supply. The number is based on empirical analysis of past discovery rates, future assumptions for exploration spend and prospectivity.
Can yet-to-find deliver this much oil at reasonable cost? It looks more realistic today than in the recent past. Liquids reserves discovered that are potentially commercial was around 5 billion barrels in 2017 and again in 2018, close to the late 2030s ‘ask’. Moreover, exploration is creating value again, and we have argued consistently that more companies should be doing it.
But at the same time, it’s the high-risk option, and usually last in the merit order – exploration is the final top-up to meet demand. There’s a danger that new discoveries – higher cost ones at least – are squeezed out if demand’s not there or new, lower-cost supplies emerge. Tight oil’s rapid growth has disrupted the commercialisation of conventional discoveries this decade and is re-shaping future resource capture strategies.
To sustain portfolios, many companies have shifted away from exclusively relying on exploration to emphasising lower risk opportunities. These mostly revolve around commercialising existing reserves on the books, whether improving recovery rates from fields currently in production (reserves growth) or undeveloped discoveries (contingent resource).
Emerging technology may pose a greater threat to exploration in the future. Evolving technology has always played a central role in boosting expected reserves from known fields. What’s different in 2019 is that the industry is on the cusp of what might be a technological revolution. Advanced seismic imaging, data analytics, machine learning and artificial intelligence, the cloud and supercomputing will shine a light into sub-surface’s dark corners.
Combining these and other new applications to enhance recovery beyond tried-and-tested means could unlock more reserves from existing discoveries – and more quickly than we assume. Equinor is now aspiring to 60% from its operated fields in Norway. Volume-wise, most upside may be in the giant, older, onshore accumulations with low recovery factors (think ExxonMobil and Chevron’s latest Permian upgrades). In contrast, 21st century deepwater projects tend to start with high recovery factors.
If global recovery rates could be increased by a percentage or two from the average of around 30%, reserves growth might contribute another 5 to 6 million b/d in the 2030s. It’s just a scenario, and perhaps makes sweeping assumptions. But it’s one that should keep conventional explorers disciplined and focused only on the best new prospects.
Global oil supply through 2040
Things just keep getting more dire for Venezuela’s PDVSA – once a crown jewel among state energy firms, and now buried under debt and a government in crisis. With new American sanctions weighing down on its operations, PDVSA is buckling. For now, with the support of Russia, China and India, Venezuelan crude keeps flowing. But a ghost from the past has now come back to haunt it.
In 2007, Venezuela embarked on a resource nationalisation programme under then-President Hugo Chavez. It was the largest example of an oil nationalisation drive since Iraq in 1972 or when the government of Saudi Arabia bought out its American partners in ARAMCO back in 1980. The edict then was to have all foreign firms restructure their holdings in Venezuela to favour PDVSA with a majority. Total, Chevron, Statoil (now Equinor) and BP agreed; ExxonMobil and ConocoPhillips refused. Compensation was paid to ExxonMobil and ConocoPhillips, which was considered paltry. So the two American firms took PDVSA to international arbitration, seeking what they considered ‘just value’ for their erstwhile assets. In 2012, ExxonMobil was awarded some US$260 million in two arbitration awards. The dispute with ConocoPhillips took far longer.
In April 2018, the International Chamber of Commerce ruled in favour of ConocoPhillips, granting US$2.1 billion in recovery payments. Hemming and hawing on PDVSA’s part forced ConocoPhillips’ hand, and it began to seize control of terminals and cargo ships in the Caribbean operated by PDVSA or its American subsidiary Citgo. A tense standoff – where PDVSA’s carriers were ordered to return to national waters immediately – was resolved when PDVSA reached a payment agreement in August. As part of the deal, ConocoPhillips agreed to suspend any future disputes over the matter with PDVSA.
The key word being ‘future’. ConocoPhillips has an existing contractual arbitration – also at the ICC – relating to the separate Corocoro project. That decision is also expected to go towards the American firm. But more troubling is that a third dispute has just been settled by the International Centre for Settlement of Investment Disputes tribunal in favour of ConocoPhillips. This action was brought against the government of Venezuela for initiating the nationalisation process, and the ‘unlawful expropriation’ would require a US$8.7 billion payment. Though the action was brought against the government, its coffers are almost entirely stocked by sales of PDVSA crude, essentially placing further burden on an already beleaguered company. A similar action brought about by ExxonMobil resulted in a US$1.4 billion payout; however, that was overturned at the World Bank in 2017.
But it might not end there. The danger (at least on PDVSA’s part) is that these decisions will open up floodgates for any creditors seeking damages against Venezuela. And there are quite a few, including several smaller oil firms and players such as gold miner Crystallex, who is owed US$1.2 billion after the gold industry was nationalised in 2011. If the situation snowballs, there is a very tempting target for creditors to seize – Citgo, PDVSA’s crown jewel that operates downstream in the USA, which remains profitable. And that would be an even bigger disaster for PDVSA, even by current standards.
Infographic: Venezuela oil nationalisation dispute timeline