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Last Updated: March 2, 2017
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  • Cash flow growing materially:
  • Upstream $13-14 billion pre-tax free cash flow in 2021
  • Downstream $9-10 billion pre-tax free cash flow in 2021 

  • Continuing discipline in capital and costs: 
  • Financial frame maintained to 2021, organic capital spending $15-17 billion a year, gearing 20-30%

  • Rising production from new Upstream major projects:
  • 6 projects began production in 2016; 7 projects to come online in 2017; 9 projects now under construction expected onstream 2018-21 
  • Upstream production expected to grow by average of 5% a year from 2016 to 2021

  • Cash balance point for BP expected to fall to around $35-40/barrel in 2021

BP today updates the financial community on details of its strategy and, in particular, medium-term plans for the next five years, based on oil prices similar to where they are today. Following a presentation today in London, BP management teams will this week travel to London, Edinburgh, New York, Dallas, Houston, Paris and Frankfurt to update investors.

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.

Upstream

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.

Downstream

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.

New business models

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.

Notes to editors

  • The presentation to the financial community can be seen via www.bp.com/investors
  • The December 2016 agreement with Woolworths in Australia is subject to regulatory approval

Further information

BP press office, London: +44 (0)20 7496 4076, [email protected]

Cautionary statement

In order to utilize the ‘safe harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’), BP is providing the following cautionary statement. This 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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Upcoming OPEC Meeting: What to Expect

A month ago, crude oil prices were riding a wave, comfortably trading in the mid-US$70/b range and trending towards the US$80 mark as the oil world fretted about the expiration of US waivers on Iranian crude exports. Talk among OPEC members ahead of the crucial June 25 meeting of OPEC and its OPEC+ allies in Vienna turned to winding down its own supply deal.

That narrative has now changed. With Russian Finance Minister Anton Siluanov suggesting that there was a risk that oil prices could fall as low as US$30/b and the Saudi Arabia-Russia alliance preparing for a US$40/b oil scenario, it looks more and more likely that the production deal will be extended to the end of 2019. This was already discussed in a pre-conference meeting in April where Saudi Arabia appeared to have swayed a recalcitrant Russia into provisionally extending the deal, even if Russia itself wasn’t in adherence.

That the suggestion that oil prices were heading for a drastic drop was coming from Russia is an eye-opener. The major oil producer has been dragging its feet over meeting its commitments on the current supply deal; it was seen as capitalising on Saudi Arabia and its close allies’ pullback over February and March. That Russia eventually reached adherence in May was not through intention but accident – contamination of crude at the major Druzhba pipeline which caused a high ripple effect across European refineries surrounding the Baltic. Russia also is shielded from low crude prices due its diversified economy – the Russian budget uses US$40/b oil prices as a baseline, while Saudi Arabia needs a far higher US$85/b to balance its books. It is quite evident why Saudi Arabia has already seemingly whipped OPEC into extending the production deal beyond June. Russia has been far more reserved – perhaps worried about US crude encroaching on its market share – but Energy Minister Alexander Novak and the government is now seemingly onboard.

Part of this has to do with the macroeconomic environment. With the US extending its trade fracas with China and opening up several new fronts (with Mexico, India and Turkey, even if the Mexican tariff standoff blew over), the global economy is jittery. A recession or at least, a slowdown seems likely. And when the world economy slows down, the demand for oil slows down too. With the US pumping as much oil as it can, a return to wanton production risks oil prices crashing once again as they have done twice in the last decade. All the bluster Russia can muster fades if demand collapses – which is a zero sum game that benefits no one.

Also on the menu in Vienna is the thorny issue of Iran. Besieged by American sanctions and at odds with fellow OPEC members, Iran is crucial to any decision that will be made at the bi-annual meeting. Iranian Oil Minister Bijan Zanganeh, has stated that Iran has no intention of departing the group despite ‘being treated like an enemy (by some members)’. No names were mentioned, but the targets were evident – Iran’s bitter rival Saudi Arabia, and its sidekicks the UAE and Kuwait. Saudi King Salman bin Abulaziz has recently accused Iran of being the ‘greatest threat’ to global oil supplies after suspected Iranian-backed attacks in infrastructure in the Persian Gulf. With such tensions in the air, the Iranian issue is one that cannot be avoided in Vienna and could scupper any potential deal if politics trumps economics within the group. In the meantime, global crude prices continue to fall; OPEC and OPEC+ have to capability to change this trend, but the question is: will it happen on June 25?

Expectations at the 176th OPEC Conference

  • 25 June 2019, Vienna, Austria
  • Extension of current OPEC+ supply deal from end-June 2019 to end-December 2019
June, 12 2019
SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

Global liquid fuels

  • Brent crude oil spot prices averaged $71 per barrel (b) in May, largely unchanged from April 2019 and almost $6/b lower than the price in May of last year. However, Brent prices fell sharply in recent weeks, reaching $62/b on June 5. EIA forecasts Brent spot prices will average $67/b in 2019, $3/b lower than the forecast in last month’s STEO, and remain at $67/b in 2020. EIA’s lower 2019 Brent price path reflects rising uncertainty about global oil demand growth.
  • EIA forecasts global oil inventories will decline by 0.3 million barrels per day (b/d) in 2019 and then increase by 0.3 million b/d in 2020. Although global liquid fuels demand outpaces supply in 2019 in EIA’s forecast, global liquid fuels supply is forecast to rise by 2.0 million b/d in 2020, with 1.4 million of that growth coming from the United States. Global oil demand rises by 1.4 million b/d in 2020 in the forecast, up from expected growth of 1.2 million b/d in 2019.
  • Annual U.S. crude oil production reached a record 11.0 million b/d in 2018. EIA forecasts that U.S. production will increase by 1.4 million b/d in 2019 and by 0.9 million b/d in 2020, with 2020 production averaging 13.3 million b/d. Despite EIA’s expectation for slowing growth, the 2019 forecast would be the second-largest annual growth on record (following 1.6 million b/d in 2018), and the 2020 forecast would be the fifth-largest growth on record.
  • For the 2019 summer driving season, which runs from April through September, EIA forecasts that U.S. regular gasoline retail prices will average $2.76 per gallon (gal), down from an average of $2.85/gal last summer. The lower forecast gasoline prices primarily reflect EIA’s expectation of lower crude oil prices this summer.

U.S. residential electricity price

West Texas Intermediate (WTI) crude oil price

World liquid fuels production and consumption balance


Natural gas

  • The Henry Hub natural gas spot price averaged $2.64/million British thermal units (MMBtu) in May, almost unchanged from April. EIA expects strong growth in U.S. natural gas production to put downward pressure on prices in 2019. EIA expects Henry Hub natural gas spot prices will average $2.77/MMBtu in 2019, down 38 cents/MMBtu from 2018. EIA expects natural gas prices in 2020 will again average $2.77/MMBtu.
  • EIA forecasts that U.S. dry natural gas production will average 90.6 billion cubic feet per day (Bcf/d) in 2019, up 7.2 Bcf/d from 2018. EIA expects natural gas production will continue to grow in 2020, albeit at a slower rate, averaging 91.8 Bcf/d next year.
  • U.S. natural gas exports averaged 9.9 Bcf/d in 2018, and EIA forecasts that they will rise by 2.5 Bcf/d in 2019 and by 2.9 Bcf/d in 2020. Rising exports reflect increases in liquefied natural gas exports as new facilities come online. Rising natural gas exports are also the result of an expected increase in pipeline exports to Mexico.
  • EIA estimates that natural gas inventories ended March at 1.2 trillion cubic feet (Tcf), 15% lower than levels from a year earlier and 28% lower than the five-year (2014–18) average. EIA forecasts that natural gas storage injections will outpace the previous five-year average during the 2019 April-through-October injection season and that inventories will reach almost 3.8 Tcf at the end of October, which would be 17% higher than October 2018 levels and about equal to the five-year average.

Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants to rise from 35% in 2018 to 37% in 2019 and to 38% in 2020. EIA forecasts that the share of generation from coal will average 24% in 2019 and 23% in 2020, down from 27% in 2018. The forecast nuclear share of generation falls from 20% in 2019 to 19% in 2020, reflecting the retirement of some nuclear reactors. Hydropower averages a 7% share of total generation in the forecast for 2019 and 2020, similar to 2018. Wind, solar, and other nonhydropower renewables together provided 10% of U.S. generation in 2018. EIA expects they will provide 11% in 2019 and 13% in 2020.
  • EIA forecasts that renewable fuels, including wind, solar, and hydropower, will collectively produce 18% of U.S. electricity in 2019 and almost 20% in 2020. EIA expects that annual generation from wind will surpass hydropower generation for the first time in 2019 to become the leading source of renewable electricity generation and maintain that position in 2020.
  • EIA forecasts that U.S. coal consumption, which reached a 39-year low of 687 million metric tons (MMst) in 2018, will fall to 602 MMst in 2019 and to 567 MMst in 2020. The falling consumption reflects lower demand for coal in the electric power sector.
  • After rising by 2.7% in 2018, EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions will decline by 2.0% in 2019 and by 0.9% in 2020. EIA expects U.S. CO2 emissions will fall in 2019 and in 2020 because its forecast assumes that temperatures will return to near normal, and because the forecast share of electricity generated from natural gas and renewables increases while the forecast share generated from coal, which produces more CO2 emissions, decreases. Energy-related CO2 emissions are sensitive to weather, economic growth, energy prices, and fuel mix.

U.S. natural gas prices


U.S. residential electricity price

West Texas Intermediate (WTI) crude oil price

June, 12 2019
Sempra Energy ships first liquefied natural gas cargo from Cameron LNG export facility

U.S. LNG export capacity

Source: U.S. Energy Information Administration, U.S. liquefaction capacity database

On May 31, 2019, Sempra Energy, the majority owner of the Cameron liquefied natural gas (LNG) export facility, announced that the company had shipped its first cargo of LNG, becoming the fourth such facility in the United States to enter service since 2016. Upon completion of Phase 1 of the Cameron LNG project, U.S. baseload operational LNG-export capacity increased to about 4.8 billion cubic feet per day (Bcf/d).

Cameron LNG’s export facility is located in Hackberry, Louisiana, next to the company’s existing LNG-import terminal. Phase 1 of the project includes three liquefaction units—referred to as trains—that will export a projected 12 million tons per year of LNG exports, or about 1.7 Bcf/d.

Train 1 is currently producing LNG, and the first LNG shipment departed the facility aboard the ship Marvel Crane. The facility will continue to ship commissioning cargos until it receives approval from the Federal Energy Regulatory Commission to begin commercial shipments. Commissioning cargos refer to pre-commercial cargo loaded while export facility operations are still undergoing final testing and inspection. Trains 2 and 3 are expected to come online in the first and second quarters of 2020, according to Sempra Energy’s first-quarter 2019 earnings call.

Cameron LNG has regulatory approval to expand the facility through two additional phases, which involve the construction of two additional liquefaction units that would increase the facility’s LNG capacity to about 3.5 Bcf/d. These additional phases do not have final investment decisions.

Cameron LNG secured an authorization from the U.S. Department of Energy to export LNG to Free Trade Agreement (FTA) countries as well as to countries with which the United States does not have Free Trade Agreements (non-FTA countries). A considerable portion of the LNG shipments is expected to fulfill long-term contracts in Asian countries, similar to other LNG-export facilities located in the Gulf of Mexico region.

Cameron LNG will be the fourth U.S. LNG-export facility placed into service since February 2016. LNG exports rose steadily in 2016 and 2017 as liquefaction trains at the Sabine Pass LNG-export facility entered service, with additional increases through 2018 as units entered service at Cove Point LNG and Corpus Christi LNG. Monthly exports of LNG exports reached more than 4.0 Bcf/d for the first time in January 2019.

U.S. LNG exports

Source: U.S. Energy Information Administration, Natural Gas Monthly

Currently, two additional liquefaction facilities are being commissioned in the United States—the Elba Island LNG in Georgia and the Freeport LNG in Texas. Elba Island LNG consists of 10 modular liquefaction trains, each with a capacity of 0.03 Bcf/d. The first train at Elba Island is expected to be placed into service in mid-2019, and the remaining nine trains will be commissioned sequentially during the following months. Freeport LNG consists of three liquefaction trains with a combined baseload capacity of 2.0 Bcf/d. The first train is expected to be placed in service during the third quarter of 2019.

EIA’s database of liquefaction facilities contains a complete list and status of U.S. liquefaction facilities.

June, 12 2019