Africa, with its wealth of natural resources and fast-growing population, may have a significant impact on international energy markets over the next 25 years. The International Energy Outlook 2018 (IEO2018) analyzed uncertainty associated with future energy demand growth in Africa by examining a sensitivity case in which a faster rate of economic growth in Africa—compared with the IEO2018 Reference case—results in greater energy consumption and a larger manufacturing sector through 2040.
The IEO2018 Reference case projects that real African gross domestic product (GDP) will grow at an average rate of 3.8% per year from 2015 to 2040, and the IEO2018 Africa High Growth case projects an average growth rate of 5.0% per year over the same period. In these cases, Africa’s energy consumption is projected to grow from 23 quadrillion British thermal units (Btu) in 2015 to 35 quadrillion Btu in the IEO2018 Reference case and to 44 quadrillion Btu in the Africa High Growth case. Energy consumed in the industrial sector (manufacturing, construction, mining, and agriculture) accounts for most of the difference between cases.
Within the industrial sector, non energy-intensive manufacturing—pharmaceuticals and electrical equipment, for example—sees the largest increase in energy consumption. Energy consumption for non energy-intensive manufacturing in 2040 is 7.9 quadrillion Btu in the IEO2018 Reference case and 10.9 quadrillion Btu in the Africa High Growth case. The energy-intensive manufacturing sector’s energy consumption increases by 1.0 quadrillion Btu, and non manufacturing energy consumption increases by 0.5 quadrillion Btu.
A higher rate of GDP growth in the Africa High Growth case leads to African manufacturing growing as a share of the economy and the services share shrinking relative to the IEO2018 Reference case. The manufacturing sector accounts for 19% of total output in the IEO2018 Reference case in 2040, with services accounting for 47%. In the IEO2018 Africa High Growth case, however, the manufacturing share of Africa’s economy in 2040 rises to 24%, and the services share drops to 37%.
Even though GDP and energy consumption both grow in Africa in the IEO2018 Reference case, energy consumption per capita declines between 2015 and 2040. Africa’s population growth rate is higher than its energy consumption growth rate, underscoring the difficulties the continent will have in meeting its energy needs. In the Africa High Growth case, however, energy consumption rises from 19 million Btu per person to 22 million Btu per person between 2015 and 2040, compared with a decline to 17 million Btu per person in the IEO2018 Reference case over that period.
Although energy consumption per capita in 2040 in the Africa High Growth case is 25% higher than it is in the IEO2018 Reference case,the African value is still lower than in many countries. African energy consumption per capita in 2040 is projected to be one-half of the level in India, one-fourth of the level in Brazil, and one-tenth of the level in Russia in the IEO2018 Africa High Growth case.
The net effect of the Africa High Growth case on the rest of the world, because of trade and global supply chains, shows limited impacts on other countries—either positive or negative—in terms of output. The biggest effect is on non energy-intensive manufacturing in Eurasian countries, where output is 3% lower in the Africa High Growth case. This slight drop occurs because Africa’s availability of low cost labor gives it a competitive advantage in manufacturing.
Principal contributors: Vipin Arora, Ilan Gmach, George Pantazopoulos
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The Permian is in desperate need of pipelines. That much is true. There is so much shale liquids sloshing underneath the Permian formation in Texas and New Mexico, that even though it has already upended global crude market and turned the USA into the world’s largest crude producer, there is still so much of it trapped inland, unable to make the 800km journey to the Gulf Coast that would take them to the big wider world.
The stakes are high. Even though the US is poised to reach some 12 mmb/d of crude oil production next year – more than half of that coming from shale oil formations – it could be producing a lot more. This has already caused the Brent-WTI spread to widen to a constant US$10/b since mid-2018 – when the Permian’s pipeline bottlenecks first became critical – from an average of US$4/b prior to that. It is even more dramatic in the Permian itself, where crude is selling at a US$10-16/b discount to Houston WTI, with trends pointing to the spread going as wide as US$20/b soon. Estimates suggest that a record 3,722 wells were drilled in the Permian this year but never opened because the oil could not be brought to market. This is part of the reason why the US active rig count hasn’t increased as much as would have been expected when crude prices were trending towards US$80/b – there’s no point in drilling if you can’t sell.
Assistance is on the way. Between now and 2020, estimates suggest that some 2.6 mmb/d of pipeline capacity across several projects will come onstream, with an additional 1 mmb/d in the planning stages. Add this to the existing 3.1 mmb/d of takeaway capacity (and 300,000 b/d of local refining) and Permian shale oil output currently dammed away by a wall of fixed capacity could double in size when freed to make it to market.
And more pipelines keep getting announced. In the last two weeks, Jupiter Energy Group announced a 90-day open season seeking binding commitments for a planned 1 mmb/d, 1050km long Jupiter Pipeline – which could connect the Permian to all three of Texas’ deepwater ports, Houston, Corpus Christi and Brownsville. Plains All American is launching its 500,000 b/d Sunrise Pipeline, connecting the Permian to Cushing, Oklahoma. Wolf Midstream has also launched an open season, seeking interest for its 120,000 b/d Red Wolf Crude Connector branch, connecting to its existing terminal and infrastructure in Colorado City.
Current estimates suggest that Permian output numbered around 3.5 mmb/d in October. At maximum capacity, that’s still about 100,000 b/d of shale oil trapped inland. As planned pipelines come online over the next two years, that trickle could turn into a flood. Consider this. Even at the current maxing out of Permian infrastructure, the US is already on the cusp on 12 mmb/d crude production. By 2021, it could go as high as 15 mmb/d – crude prices, permitting, of course.
As recently reported in the WSJ; “For years, the companies behind the U.S. oil-and-gas boom, including Noble Energy Inc. and Whiting Petroleum Corp. have promised shareholders they have thousands of prospective wells they can drill profitably even at $40 a barrel. Some have even said they can generate returns on investment of 30%. But most shale drillers haven’t made much, if any, money at those prices. From 2012 to 2017, the 30 biggest shale producers lost more than $50 billion. Last year, when oil prices averaged about $50 a barrel, the group as a whole was barely in the black, with profits of about $1.7 billion, or roughly 1.3% of revenue, according to FactSet.”
The immense growth experienced in the Permian has consequences for the entire oil supply chain, from refining balances – shale oil is more suitable for lighter ends like gasoline, but the world is heading for a gasoline glut and is more interested in cracking gasoil for the IMO’s strict marine fuels sulphur levels coming up in 2020 – to geopolitics, by diminishing OPEC’s power and particularly Saudi Arabia’s role as a swing producer. For now, the walls keeping a Permian flood in are still standing. In two years, they won’t, with new pipeline infrastructure in place. And so the oil world has two years to prepare for the coming tsunami, but only if crude prices stay on course.
Recent Announced Permian Pipeline Projects
Headline crude prices for the week beginning 3 December 2018 – Brent: US$61/b; WTI: US$52/b
Headlines of the week
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