FORESIGHT Climate & Energy Autumn/Winter 2020

17.12.2020 - 28.04.2021

FORESIGHT — 11 Climate & Energy

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Danish heating cleans up its act

Hydrogen trains tracking hot

Heavy industry to carbon light

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Electrification is the way to decarbonisation

FORESIGHT Climate & Energy AUTUMN / WINTER 2020

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We now know we can secure the energy we need from zero carbon sources. Decarbonisation of the world’s economy is no longer the insurmountable challenge facing mankind that it was just a few years ago. Electrification is the key.

Electricity is an energy carrier that enables all sources of energy to be clean at their point of use. For this reason alone, electrification of energy use is a good idea. Electricity, however, is only as clean as the energy source from which it is generated, which can be dirty or clean.

When energy is harnessed from the power of water flowing, the wind blowing or heat radiating from the sun and converted to electricity, the world’s decarbonisation goals are brought within reach.

Clean electrification of the global economy requires lots more electricity from renewable sources of energy. As well as providing light and powering appliances, green electricity must charge our cars, heat our buildings, and energise industrial processes heavily dependent on fossil fuel. More demand for electricity requires more of our power systems and more of the transmission and distribution wires designed for a previous age of centralised fossil fuel generation. The capacity of the wires must be boosted and power systems far better interconnected. Joined up and robust power systems are capable of absorbing shocks that destabilise the delicate balance of supply and demand in smaller, weaker systems.

Heating indoor spaces can be done cheaply and cleanly in urban areas using heating networks served by renewable energy. Denmark has shown the way. The scale of change needed is not to be underestimated, but even a country with challenges the size of those in the UK can decarbonise its heating and lower its cost, given sufficient political will to do so.

Electricity will also be needed to power electrolysers to produce hydrogen, a process that is entirely free of carbon emissions, as is its use. Hydrogen fuel cells hold potential to decarbonise heavy transport and hydrogen may replace fossil fuels in some industrial processes.

Hydrogen trains are showing great promise and a few are in commercial operation. A consensus is emerging that these are the best applications for hydrogen and talk of using it in power and heating systems is a distraction.

The most carbon intensive use of fossil fuel is in heavy industry.

Full electrification of cement and steel manufacturing, the two biggest sinners, would require new processes, innovations that may come up short for total decarbonisation. They are industries that need serious government help, not protection..

If nothing else, our deep dive into electrification is a positive story of human ingenuity at work. No longer is decarbonisation an aspiration impossible to achieve. Through electrification it can be done.

David Weston EDITOR-IN-CHIEF

CONTENT

THE BIG PICTURE

GRID INFRASTRUCTURE

CLEAN HEATING

TRANSPORT

FOSSIL FUEL CAN BE LEFT IN THE GROUND

THE MISSING LINKS OF THE EUROPEAN ENERGY TRANSITION

HOW TO DECARBONISE THE BUILDING STOCK IN BRITAIN

CHARGING AHEAD

Interconnection gaps in Europe's power systems must be closed to deliver carbon free electrification

Gas and oil fired heating appliances in each and every building have no place in a net-zero world

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BLUEPRINT FOR INNOVATIVE TRANSMISSION

DECARBONISED HEAT WITHIN A DECADE IN DENMARK

Offshore wind farm connections combined with power system interconnectors boost transmission efficiency, cutting cost

Heat pumps running on renewables electricity embedded in urban heating networks demonstrate efficient electrification of space heating

The ecological destruction caused by fossil fuel extraction, exemplified by the Alberta tar sands, no longer has to continue PAGE 8

UP FRONT ELECTRIFICATION FOR DECARBONISATION

Renewable energy is now affordable, making electrification of energy supply the best option for decarbonisation PAGE 10

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BETTER GRID POLICY VITAL FOR FULL SCALE ELECTRIFICATION

The case for rolling out vast public charging networks suffers under close examination PAGE 46

WHY HYDROGEN TRAINS ARE TRACKING HOT

It could be the railways that spearhead green hydrogen’s breakthrough in the electrification of energy supply PAGE 54

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Public opposition is the biggest obstacle in Europe to building transmission infrastructure

CEMENT & STEEL HEAVY INDUSTRY TO CARBON LIGHT

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Full electrification of cement and steel manufacturing would require new processes that may not transpire to achieve total decarbonisation

FEDERAL GREEN GRID VISION GONE MISSING IN AMERICA

Lack of sufficient transmission capacity is a mighty roadblock

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FORESIGHT

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The Big Picture If the Canadian province of Alberta was a country in its own right, it would be the fifth largest oil producing economy in the world. Most of the oil comes from its tar sands, pictured, a jarring example of the ecological destruction caused by fossil fuel extraction. It need not continue. The rise of affordable renewable energy has made clean electrification of the energy needs of mankind entirely possible, both directly and indirectly through production of hydrogen. Fossil fuels can be left in the ground, doing no harm.

PHOTO Russ Heinl

UP FRONT Generating electricity from the sun and the wind has become so cheap that despite the extra expense their variable supply incurs for power system management, their cost is undercutting that of fossil fuel. It is the affordability of renewables that makes direct and indirect electrification of heating, transportation and some industrial processes possible.

Ridding the world of carbon pollution is no longer a pipedream, but a job to get done

Electrification for decarbonisation

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Time is of the essence, with less than 100 years left to avert climate catastrophe: the world cannot be allowed to warm more than 2°C above pre-industrial temperatures. Projections by energy analysts differ in detail, but in broad terms electrification of energy use will need to at least double by 2050, up from 2025% in 2020. Necessity is the mother of invention and already human ingenuity has risen to the challenge.

The technologies to affordably decarbonise the world through electrification are already at our disposal.

“By 2050, an astounding 17,000 gigawatts (GW) of installed solar and wind capacity will be generating 62% of the world’s electricity needs,” says Norwegian energy advisory firm DNV GL, a global quality assurance and risk management provider. This is 14 times today’s 1.25 TW capacity of wind and solar. The growth in renewable energy capacity will be driven by increased electricity demand as electrification of transportation and heating ramps up along with deFORESIGHT

Trending The part played by electricity in meeting energy demand is set to dominate the stage by 2050, or even well before if this graphic from the perspective of late summer 2020 proves to be a conservative view TEXT David Weston

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lectrification of the global economy will be the cheapest and cleanest way of getting the world off its dependence for energy on the combustion of fossil fuels, says the International Energy Agency (IEA), an inter-governmental advisory body. Electricity can carry the energy captured from renewable sources like the wind and the sun directly to its point of use. Indirectly, through the process of electrolysis, renewables electricity can create a secondary energy carrier, hydrogen gas. Hydrogen can be combusted without pollution for industrial processes that require extremely high temperatures hard for electricity to sustain and for energy uses that cannot be powered from the grid or using batteries, such as some forms of transportation.

What cannot be electrified, directly or indirectly, will be reliant on bio-fuels, the combustion of which does not upset the world’s fine ecological balance in the way that burning fossil fuels has done.

King coal loses its throne to renewables electricity World final energy demand in radical transition

Units: joule/year 500

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SOURCE DNV GL

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mand for green hydrogen. Solar and wind will be the cheapest source of generation and that will be “irrespective of the vital shift” to a future with no more carbon emitted than the world can sustain, DNV GL adds.

In its Energy Transition Outlook 2020 report, DNV GL says electricity in 2019 met 20% of the world’s final energy demand. By 2050, the share of electricity will be 41% of final energy demand. Electricity will meet more demand for energy than any other single technology by mid-century, DNV GL says. Demand for electricity will double from 24 petawatt-hours a year (PWh/year) to 48 PWh/year by 2050, demonstrating the growing role of electricity as the main source of energy in the ongoing decarbonisation of the economy. It will also be the catalyst to produce other fuels like hydrogen and ammonia for the transport and heavy industry sectors, says DNV GL. The projections are grounded in realism. Nobody claims electricity can be used to meet every type of FORESIGHT

2050

energy demand. “You can get to a fully decarbonised scenario without fully electrifying everything. Certainly between electricity and hydrogen, that’s where the future is going to be. There’s a lot that needs to be electrified but it’s not the complete answer,” says Dave Jones from Ember, a UK climate think tank.

Even European trade body Eurelectric, concedes that point. “We believe the future is electric, that means first of all it’s a bright and exciting future. It’s also one that is much more electric, it’s not all electric,” says Eurelectric’s Kristian Ruby. He believes direct electrification—replacing the use of heat energy with electrical energy—will mean that electricity makes up 50-60% of final energy consumption in Europe. Indirect electrification—using electricity to produce other fuels like hydrogen—will be “a significant part” of the rest. “That is a very different world to the one we have today where we’re talking more 20-25% of total final energy consumption. There’s a signifi11

UP FRONT

cant ramp up that we need to handle in the next few years,” Ruby says.

“By 2030, the European Commission assesses that the share of electricity in total final energy consumption needs to be around 30%. But that’s also a significant lift. It means millions of electric cars on the roads by 2030, it means millions of heat pumps installed in buildings across Europe and a higher uptake of electricity in industrial processes. So we need to see that start happening also with a view to scale it later,” he adds.

In another projection, electricity would provide around 45% of final energy demand by 2050, according to BloombergNEF, the new energy finance and research division of news agency Bloomberg, in its pathway to keep global warming to well below 2°C from its New Energy Outlook report for 2020. This share is up from around 20% today. Meanwhile, hydrogen could provide up to 25% of final energy, up from less than 0.001% today. “The remaining 30% is a combination of existing bioenergy, as well as residual oil and gas use in aviation and shipping, and coal in industry where neither direct electric technology nor hydrogen act as a substitute,” BloombergNEF says.

The IEA says broadening the use of electricity into more areas of the economy is the “single largest contributor to reaching net-zero emissions” in its Energy Technology Perspectives report from September 2020. Ramping up renewable technology so that electricity is carbon free is just one part of the challenge.

“Efficiently integrating vast volumes of variable generation adds complexity to power systems and will require significant investment in grid infrastructure, more intelligent grid operation, energy markets closer to being real-time, and extensive utilisation of flexibility options,” DNV GL’s Ditlev Engel wrote in the report.

RENEWABLES APLENTY While not everything can be powered by electricity, what can be electrified can use a combination of solar, wind and other renewables, supported by much more flexible power systems and more use of energy storage. There is no shortage of resource. Fundamentally, a single 52,000 kilometre-square area of the UK’s North Sea covered by large wind turbines with rated capacities of 12-13 MW could produce 600 TWh of electricity a year—more than covering the UK’s current electricity demand. Tesla’s Elon Musk says an area of 160 square kilometres—roughly the size of Liechtenstein—covered in solar panels could, theoretically, provide all of the United States’ electricity.

An October 2020 report by independent think tank RethinkX—co-founded by Stanford University lecturer and futurist Tony Seba—highlights the ways 12

in which a combination of solar, wind and batteries (SWB) can provide the US with all the electricity required. It also believes its findings can be replicated elsewhere in the world. The report likens the rise of renewables and battery storage to that of information technology. “Just as computers and the Internet slashed the marginal cost of information and opened the door to hundreds of new business models that collectively have had a transformative impact upon the global economy, so too will SWB slash the marginal cost of electricity and create a plethora of opportunities for innovation and entrepreneurship. What happened in the world of bits is now poised to happen in the world of electrons,” the report states.

POLICY FRAMEWORKS

The IEA sees biofuels and continued combustion of some fossil fuels, but with carbon capture, utilisation and storage (CCUS) meeting energy demand that cannot be electrified, either directly or indirectly. “Quicker progress towards net-zero emissions will depend on faster innovation in electrification, hydrogen, bioenergy and CCUS,” it says. A third of cumulative emissions reduction in the next three decades will: “Stem from technologies that are not commercially available today,” the IEA adds.

Broadening the use of electricity... is the single largest contributor to reaching net-zero emissions

Significant research and development support from governments and lawmakers is needed, also to help new technologies find a route to market. “It’s really for policymakers to understand that landscape and some of the barriers to innovation and the market,” says Ember’s Jones.

Eurelectric’s Ruby advocates a focus on speeding up permitting procedures that will allow new projects, infrastructure and technologies to be built. “We have a power system [in Europe] of about 1000 GW today and over the next ten years we need to build 500 GW. Permitting procedures take on average somewhere between four and six years and can easily take more. So you can imagine if we decide to revolutionise the system today and we need to talk about that and do the assessments and permitting for six years then there is not a lot of time to build.”• FORESIGHT

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ELECTRICITY INFRASTRUCTURE No matter how much wind and solar power is generated, the energy transition cannot be achieved without a built-for-purpose electricity infrastructure. Gaps in the interconnections of Europe’s grid network and lack of capacity on the wires where it is needed most will halt green electrification of energy. Power system operators have a plan. The issue is implementation

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he stated goals of Europe’s energy transition—32% renewables by 2030 and 50% by 2040—are on shaky ground without radical expansion, robust interconnection and redevelopment of the continent’s electricity transmission highways and distribution networks. The existing grid system is inadequate for the task ahead. At the rate of network upgrades seen to date, the EU would struggle to get even halfway to its goals, no matter how much new wind and solar capacity is built. The grid is not designed to deal with the transition from a limited number of large power stations with controllable output to a system reliant on variable input from many thousands of smaller and dispersed units.

The more the power systems of Europe are robustly linked to one another, the more the supply of electricity can be based on variable energy sources, like solar and wind, without compromising security of supply. Indeed, the broader the supplier base, the more secure the system becomes. What is required is completion of plans for 35 GW of cross-border grid 14

investment by 2025, a further 50 GW by 2030 and another 43 GW by 2040, according to the European Network of Transition System Operators for Electricity (ENTSO-E). Its job is to co-ordinate the cross-border power system operations, system development and electricity market activities of 42 electricity transmission system operators (TSOs) across 35 countries.

GERMAN ISSUE Germany’s location in the middle of the European continent makes its grid investment fundamental to achieving ENTSO-E’s plans. But development of the country’s electricity infrastructure is failing to keep up with the growth of wind and solar capacity. Transmission bottlenecks, both internally and across its national borders, are an increasing problem for the further growth of renewable energy.

Over the continent as a whole, transmission of wind power south from the windy locations of northern Europe, on land and offshore, is hampered by lack of sufficient network capacity, as is the transFORESIGHT

Bottleneck Congested links in the transmission wires interconnecting power systems are raising the cost of renewable energy and hindering its uptake

TEXT Drew Robb and David Weston ILLUSTRATION Hvass & Hannibal

The vital missing links of the European energy transition

ELECTRICIT Y INFRASTRUCTURE

mission of solar electricity to Europe’s industrial heartlands from the sunny south, including from Italy, Spain, Portugal and even North Africa across the Mediterranean Sea.

THE PLANS ENTSO-E’s 2030 plan seeks to shore up the connections between Germany and Poland, Switzerland and Austria, as well as those across the Belgium-France border, Spain-France, between Turkey and Southeast Europe and various Italian connections. By 2040, connections across the France-Spain border are to be further beefed up as well as those crossing the Portugal-Spain border, helping to better connect the poorly linked Iberian peninsula to the rest of European the grid. Improvements across French borders to Switzerland and the UK are also in the works. Northsouth power flows will be improved from the Nordic countries and south through continental Europe, Ireland will be better connected to the UK, the UK to the mainland and Italy with the rest of Europe.

Some of the new wires involve connecting offshore wind resources to land in a more coordinated way than to date. The 22.1 GW of installed offshore wind capacity at the end of 2020 is expected to rise to 60 GW by 2030 and in November 2020 the EU announced an offshore wind goal of 300 GW by 2050, to be complemented by a further 40 GW of other ocean energies such as wave and tidal projects.

By the end of 2020 a second high voltage line between the UK and France, the 1 GW Interconnexion France-Angleterre 2 (IFA2), is due to be fully operational. The 240 kilometre undersea high-voltage cable could be joined by six further high voltage direct current (HVDC) interconnectors by 2024, if all goes according to plan.

ON THE CONTINENT In Germany, some transmission is slowly getting built.

The 150 kilometre Mittelachse power line in Schleswig-Holstein became operational in late 2020. Dutch and German transmission operator TenneT has also made some progress on small grid expansion projects in that region over the past year. A new power line between Wilhelmshaven and Conneforde in Lower Saxony was commissioned in October 2020.

Transmission bottlenecks, both internally and across its national borders, are an increasing problem for the further growth of renewable energy

SOUTH AND NORTH A longer term vision for Europe to increase its renewable energy pool is to tap into the solar potential of North African countries such as Morocco and Tunisia where solar irradiation is as much as 20% higher than southern Spain and Italy. Existing interconnections with Morocco and Spain, with a capacity of 1.4 GW, are mainly used to export European power to Africa because lack of transmission capacity prevents it being sent north. Proposals to improve trans-Mediterranean connections to load centres in the heart of Europe include connections through the islands of Sicily and Cyprus. The Cyprus cable would connect Greece with Egypt.

In Europe’s north, longer term plans are for the UK to export abundant offshore wind power to the continent. But energy consultancy Cornwall Insight does not see it being feasible until the 2040s.

Meantime, interconnection development will greatly expand transmission capacity, introducing more flexibility for balancing supply and demand on both sides of the North Sea. With 16 GW of additional interconnection to be operational by 2025 and another 25 GW by 2030, transmission capacity between the UK, Scandinavia and France is set to double.

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In addition, transmission system operators Amprion (Germany) and Elia Group (Belgium) have been collaborating on HVDC projects. The Aachen Liège Electricity Grid Overlay (ALEGrO) interconnector also came online in late 2020. A 90 kilometre, 1 GW link, it is the first HVDC power bridge between Germany and Belgium, boosting security of supply to citizens in both countries and smoothing the ups and downs of demand for electricity and the variable delivery of it from renewable energy sources of generation.

Elsewhere, however, progress on major interconnectors is ponderous, including high-priority connections for offshore wind projects in the North Sea, which are still a decade away. TenneT has completed the Borssele alpha and Borssele beta connections to transfer 1.4 GW of offshore wind in the Dutch North Sea to the country’s grid. But, a further three of Tennet’s connection projects—BalWin and LanWin in the German North Sea and IJmuiden Ver in the Dutch North Sea for a total of 9.5 GW of transmission capacity—are not due to be wrapped up until 2030. The slow progress either delays offshore wind projects proposed around these connections, or forces the developers to find temporary alternatives.

FORESIGHT

ELECTRICITY INFRASTRUCTURE

An interconnected Europe Completed and proposed transmission projects backed by the EU

of total power generation came from renewable energy and 30.6% from wind and solar sources alone.

This scenario was repeated across Europe, with power system operators learning-while-doing on how to maintain security of supply while managing the ups and downs of both new demand patterns and much higher proportions of the supply mix based on variable generation. Balancing the two is a challenge.

To help keep the Italian grid secure, operator Terna tapped into existing flexibility resources—mainly natural gas plants, hydroelectric power, pumped hydro storage and grid interconnectors. Italy exported power during hours of excess renewables production and imported during the evening ramp-up as its solar photovoltaic plants stopped producing. The operational changes brought about by the pandemic sharpened Italian focus on how system operations will change as Italy gets closer to its goal of 60.5% electricity from renewables by 2030, with 37.1% from variable renewables.

Andrea Marchisio of Italian energy consultancy Elemens, expects batteries will be one essential element to increasing the strength of Italy’s power system, particularly given the prevalence of small distributed solar photovoltaic (PV) capacity in the country. Local storage of PV energy in batteries can help batteries can help avert the need to build out the grid or construct additional power generating capacity, he notes.

SOURCE European Comission

REPLACEMENT INERTIA

Ongoing Completed

PANDEMIC LESSONS As the covid-19 pandemic swept across the globe, the knock-on effect it had on grid management highlighted where grids need to improve. Economic and industrial activity slumped for weeks on end as national lockdowns restricted the movement of people in an attempt to halt the spread of the virus for uptake of renewable energy. In Italy, on a day when demand for electricity was 36% below the 2019 average, 47.6% FORESIGHT

The uptake of renewables requires the adoption of solutions for a range of technical challenges, none of which have proved to be insurmountable. Among them has been finding ways to maintain power system inertia as renewable energy replaces centralised thermal power plants. The huge rotating turbines in thermal power stations cushion sudden changes in frequency caused by changes in demand. Without it, grid stability is weakened.

US engineering firm GE installed two synchronous condensers and flywheel units for Italian grid operator Terna at the Brindisi substation in southern Italy. Each unit supplies 1750 MW of inertia to provide grid stability. Similarly, in South Wales, Germany’s Siemens Energy is building a rotating grid stabilisation technology, which is basically a form of electronic synchronous condenser and a flywheel. The UK’s TSO, National Grid, also intends to line up synthetic inertia tools by 2025 to enable it to remove gas generating plants from the grid. In the north of Scotland, two rotating stabiliser synchronous machines are being installed. The same methodology has been adopted in Denmark, which with well over 50% of electricity supplied from variable renewables, tends to be further ahead with power system innovations. • 17

ELECTRICITY INFRASTRUCTURE A new transmission line across the Baltic Sea shows that a more integrated European power network is not only steadily evolving, but that innovative approaches to infrastructure design can bring down the cost of the energy transition. A new interconnection between Denmark and Germany that takes in offshore wind farms gives a glimpse of a much more connected electricity future

Blueprint for innovative transmission

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the so-called continental Europe synchronous area.

“Constructing the back-to-back converter on land is economically beneficial and allows for easier maintenance compared to the installation on an offshore platform,” Energinet notes.

The two TSOs had originally planned to install converter stations within Denmark, Germany and offshore, in a multi-terminal solution, says Hanne Storm Edlefsen, area manager at Energinet. The call for tenders to provide and install the hardware, however, called the feasibility of the configuration into question. The system was redesigned to be a mostly AC solution with back-to-back converters in Germany. Use of back-to-back converters is not uncommon where asynchronous systems are connected, such as the Lithuania-Poland link and the Mexico-United States link.

Energinet expects capacity utilisation of the interconnector to be similar to that achieved for the 600 MW Kontek onshore link between the same grid bidding zones in Denmark and Germany, which has been in operation since 1996 and is due to be replaced. According to the European Network of Transmission System Operators for Electricity (ENTSO-E), in 2017 FORESIGHT

Grid planning Transmission operators are developing new designs for interconnectors that improve integration of clean electricity TEXT David Weston ILLUSTRATION Hvass & Hannibal

D

ubbed the Combined Grid Solution (CGS), an interconnection that links the German and Danish power systems, boosting the reliability of supply to customers in both countries, also takes in two offshore wind farms: Krieger’s Flak at 600 MW in Danish waters and Baltic 2 at 288 MW in German seas. With the wind projects separated by just 30 kilometres, the transmission system operators (TSOs) on each side of the border, Energinet in Denmark and 50Hertz in Germany, saw an opportunity to link the electrical infrastructure of the two projects, provide new flexibility to the region’s grid systems, and better utilise the capacity of the cables involved. The benefits are lower costs resulting in cheaper electricity.

The Combined Grid Solution was made possible by use of a back-to-back converter, located in northern Germany. It supports the connection of the asynchronous current power grids of eastern Denmark and Germany, despite their different technical attributes.

The first of two voltage source converters transforms the alternative current (AC) from the Nordic system into direct current before the second converter transforms it back to alternating current but now matching

ELECTRICIT Y INFRASTRUCTURE

the Kontek link had an available technical capacity of 85.8%. In total, 2.6 TWh of electricity, roughly 48.5% of the technical capacity, was exported from Denmark to Germany with 0.9 TWh going in the other direction. Had the offshore wind farms been connected to shore with dedicated cables, the links would only have been used to their full capacity during hours when the wind turbines produce at full capacity.

Repurposing the wind farm-only cables to double-up as system interconnectors greatly boosts use of their capacity, improving overall cost efficiency.

The transfer of electricity along the connection is controlled by a so-called Master Controller for Interconnector Operation (MIO), which Storm Edlefsen describes as the brain of the operation. It receives information from Energinet and 50Hertz to decide how best to distribute the power across the whole network to help keep demand and supply in balance on both grids.

As well as increasing the interconnection capacity between the two nations, the link also benefits the wind projects, providing them with two markets in which to sell their output without the need for a parallel interconnector alongside export cables to Denmark and Germany. “If we had done it in the old-fashioned way you would only have one place to send the renewable power,” Storm Edlefsen adds.

Increasing volumes of variable renewable generation on the grid require more dynamic balancing of supply and demand than in the past. Additional transmission capacity, both in-country and cross-border, helps the balancing task. “The more interconnectors you have, the better connected you are to other countries with other production patterns, then it is easier,” Storm Edlefsen says. Denmark is already well connected with its Nordic neighbours, meaning it can take advantage of the combination of Norwegian hydropower and Finnish nuclear along with its renewables generation.

Decarbonisation of energy is raising electricity demand as transport, heating and cooling are electrified to gain access to renewable energy, necessitating more transmission capacity. “We see in the future, with more and more renewables, areas where we have to do more to build out the grid,” says Storm Edlefsen.

HUB AND SPOKE The CGS link is also the first of its kind to combine both generation and interconnection into a single system but, for cross-water links, it could become the norm. “I know that there are some plans in other countries where they are looking at this. But this was the first version and we are already trying to improve things,” says Storm Edlefsen. Energinet sees the Krieger’s Flak interconnection leading to larger, more 20

complicated networks of energy islands, combining the generation of several offshore wind projects before exporting the power to numerous markets.

“The whole concept is that you make an artificial platform, maybe it is an island but could also be a caisson, or even just a platform,” Storm Edlefson explains. “You have the spokes from the wind production around these new offshore artificial islands. The spokes are the lines into the island from the wind production. This creates a near-shore environment far out at sea where there is a lot of wind potential and nobody can see it. Then, you have the interconnections going into different countries also like Krieger’s Flak.”

While the energy islands sound complicated, Storm Edlefson insists much of the technology is already available, especially once the Krieger’s Flak project is fully completed. “The most difficult thing is actually to get people on board and coordinate across governments and countries on the build-out. It is not a huge technological leap that we have to take.”

We see in the future, with more and more renewables, areas where we have to do more to build out the grid

Although rapid development of much more interconnection is required for an electrified Europe, completion of major grid infrastructure projects can take up to 12 years. “It is not because we are that slow,” says Storm Edlefson. “It’s because it is a bottom-up approach.” Currently, TSOs begin the development of new links before discussions between national governments. With 2030 renewables targets looming, however, along with the transmission capacity required to reach them, TSOs are trying to engage governments earlier. “We are trying to do a topdown approach where we have the ministers and the governments meeting [to reach] an agreement. At the same time, we are working from the Energinet side with the TSOs to show whether the [business] case is good or not. This should hopefully make the timing at the beginning of projects like this shorter.

“The whole governmental issues with authorities giving permits, looking into environmental issues and so on, all these things need to be thorough, of course they do, because these are difficult projects environmentally. But this could also be done more in parallel and not sequentially,” Storm Edlefson says. • FORESIGHT

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ELECTRICITY INFRASTRUCTURE Without a European grid up to the task of not only meeting more demand for electricity, but also assimilating it from distributed renewables, green electrification of heating and transport is stymied from the start. Decarbonisation requires new infrastructure, yet the public is having none of it. Winning over the people to grid expansion needs to be a political priority, while a more immediate fix is to make the existing wires work better

T

here is no way around it. From Ireland to Italy, Europe’s decarbonisation goals will not be met without significantly more grid investment, both in distribution and transmission networks. Leveraging those investments may be more of a political, than a regulatory or even a financial issue.

Ireland is aiming for 70% of its electricity to come from renewable energy sources by 2030, requiring up to 9.2 GW of new power capacity, primarily wind and solar, equivalent to about 80% of the country’s total generating capacity today. “Such a major expansion requires an exceptionally large investment in the Irish electricity industry and not only in the generation facilities themselves,” states the Irish Academy of Engineering (IAE) in an October 2020 briefing paper on the future of the country’s electricity transmission network.

Warning that 2030 goals could be endangered without large-scale investments in the network, the academy also notes that Ireland has faced increased

22

public resistance to transmission projects over the past few decades. One key piece of planned infrastructure, a 150 kilometre north-south interconnector cable first proposed in 2005, is still in the permitting process. It and other planned projects are bedevilled by objections from concerned citizens.

Public opposition is the single biggest obstacle to building the necessary transmission infrastructure and that in turn is a political issue, believes Don Moore, chair of the IAE’s energy and climate change committee. “We don’t think this is a matter that can be left to power companies or to grid companies anymore. The government has to take the lead. Politicians are reluctant to stick their neck out for things like this, but they have to convince the public that, if it wants decarbonisation—and people say they do— this is a price that needs to be paid. It can’t be done without infrastructure.”

Ireland is not alone in the need to scale up renewables generation and grid infrastructure and in facing FORESIGHT

Policy priority Cohesive collaboration on transmission infrastructure policy across Europe can unlock greater electrification potential

TEXT Heather O’Brian ILLUSTRATION Hvass & Hannibal

Better grid policy for full scale electrification

ELECTRICIT Y INFRASTRUCTURE

difficulty doing so. Eurelectric, an electricity industry trade association, estimates solar capacity in Europe will need to nearly triple and wind capacity to double by 2030 to reach emission reduction goals. Required investments in transmission and distribution grids, including their optimisation and digitalisation, are estimated in a range of €60 billion to €110 billion, every year.

Yet the lengthy permitting processes for energy infrastructure seen across Europe are hampering the deployment of both new generating capacity and electricity grids, increasing the cost of development and worsening investment cases, Eurelectric warns in a recent appeal to policymakers to streamline the authorisation process.

GERMAN BOTTLENECKS Germany’s central location in the middle of the European power network make its grid problems those of its neighbours, too. In a report on the German power market released in January 2020, think tank Agora Energiewende highlighted the slow progress of the country’s grid expansion, with only 1150 kilometres of the 7700 kilometres that lawmakers had resolved to build to meet 2030 goals installed by the end of 2019.

On the other hand, “significant progress” was made in awarding new permits, with an additional 1000 kilometres in projects authorised and progress made in the completion of cross-border interconnectors. Beefing up links between power systems enables additional electricity exchange with neighbours, says Agora Energiewende, facilitating the integration of renewables and underpinning security of supply.

As Germany works to bolster its grid, integrating renewable energy has proved to be a complex endeavour. Wind energy capacity is concentrated in the north, on land and offshore, while much of demand lies in the south. Yet deployment of new grid infrastructure to take the power south has struggled to keep pace with the growth in wind generation. The mismatch has resulted in frequent transmission constraints, says Andreas Jahn of the Regulatory Assistance Project, an energy system advisory body.

Manon van Beek, the CEO of TenneT, the transmission system operator (TSO) for the Netherlands and part of Germany, has acknowledged that grid constraints in northern parts of both countries have at times forced the TSO to reduce electricity generation from wind farms while at the same time it is ramping up fossil fuel generation in the south, increasing carbon dioxide emissions.

TenneT expects to face challenges with grid bottlenecks until the needed expansions are in place, in particular the 700 kilometre, 4 GW north-south SuedLink to run between Schleswig-Holstein in north24

ern Germany and Bavaria and Baden-Württember in the south. It is billed as the backbone of the European energy transition. SuedLink was initially slated for completion in 2022 but from the perspective of 2020 is not expected to be finished until the end of 2026.

PUBLIC PAYS FOR OPPOSITION The project was revised to use underground cables after a December 2015 German government decision that they should be favoured over overhead lines to avoid public protests. Underground cables are more expensive. The estimated cost to the public for SuedLink ballooned to up to €10 billion from an initial €3 billion to €4 billion, but it is now less likely to trigger widespread protest and the added problem that brings of opposition from local politicians.

Politicians have to convince the public that this is a price that needs to be paid. It can’t be done without infrastructure

“It’s a balancing act,” says Moore of IAE. “The more expensive cost of underground cables will be reflected in the price of electricity and at the end of the day, you also want to have a competitive price for energy.”

Paul Wilczek, head of distribution and market facilitation at Eurelectric, stresses the importance of an approach based on dialogue. “Explain why you are building this power line and why, for example, it can’t or perhaps can be an underground line. In some cases, there could be underground solutions found and in other cases it might be too complicated or too expensive.”

THE POWER OF DIALOGUE While SuedLink will not be operational for several years, TenneT highlights recent progress in bringing new grid infrastructure online, including the commissioning in October 2020 of the 150 kilometre Mittelachse power line in Schleswig-Holstein. Public meetings with TenneT and representatives of national and regional governments on the one hand and stakeholders including local residents, landowners and environmental associations on the other are increasingly translating into greater acceptance of grid expansion, the company says, noting that the energy FORESIGHT

ELECTRICITY INFRASTRUCTURE

The benefits of maximising capacity on existing wires Foreseen evolution of power flow in a French north-south transmission corridor

120%

DIRECTION north → south

Line loading factor (%)

80% DIRECTION south → north

40%

0%

-40%

SOURCE WindEurope

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-120%

2035

2020

Line use range by 2035

transition is supported by the vast majority of Dutch and Germans. In the face of Germany’s ambitious grid expansion goals, TenneT stresses it needs the support of politicians at all levels.

Policy alternatives may also exist to new grid infrastructure, but neither are they necessarily easy to implement. Jahn of RAP notes that one possible and widely discussed solution to easing bottlenecks in Germany is the introduction of two or more bidding zones for electricity purchases in the country.

Germany has so far considered its single bidding zone to be a national asset, but with electricity changing hands at a single price on the wholesale electricity market, prices do not reflect scarcity due to the lack of transmission infrastructure. As a result there is no incentive for large power consumers to relocate closer to generation sources. In other words, to move north from south.

FORESIGHT

Current line use range

INCENTIVISE GRID OPTIMISATION The slow pace of deployment of new grid infrastructure and the urgency of the energy transition means lawmakers should focus on grid optimisation technologies as a no-regrets solution available here and now, argues trade association WindEurope. “Whilst grid expansion is crucial and needs to accelerate, grid optimisation and timely solutions must be addressed first,” it argues in a policy paper published in November 2020. “We should be exploring ways to maximise the use of the existing grid while complying with safety and security rules. The transmission grid—existing and under development—must more than ever be utilised to its maximum potential until new transmission assets are built.”

The association believes TSO investment in grid optimisation should match investment in new grid developments and can be facilitated through regula25

ELECTRICIT Y INFRASTRUCTURE

tory frameworks. Making the existing grid capable of delivering more electricity is a short-to-medium-term solution that leads to savings in total costs, both capital expenditure and operating expenditure, and complements traditional long-term investment in electricity infrastructure.

KEY REGULATION IN REVISION Key to pan-European policy on power grid assets is the Trans-European Networks for Energy (TEN-E) regulation, which identifies cross-border energy infrastructure priorities in Europe and so-called “projects of common interest” (PCIs) needed to deliver on those priorities. The regulation covers wide territory that includes what sort of infrastructure should be considered a priority in Europe, the criteria for financing them through the Connected Europe Facility (CEF), streamlining permitting for priority projects and increasing public acceptance through public consultation.

TEN-E was enacted by the European Union in 2013, before the adoption of the Paris Agreement to hold average global temperature increases to well under 2°C compared with pre-industrial levels. The regulation is, in 2020, going through a revision process to align it to Europe’s Green Deal and that agreement’s objective for the EU as a whole to produce no more emissions than it offsets by 2050, known as “climate neutrality”. Following a consultation process earlier this year, the European administration aims to present a legislative proposal for the revision of the regulation by end 2020.

Lina Strandvåg Nagell, sustainable economy coordinator at climate pressure group Bellona, describes TEN-E as “a very important tool in facilitating interconnectedness” of power systems in Europe. It is difficult to assess the regulation’s contribution to Europe achieving its 2020 emission reduction targets, but that was never its intended objective at the start.

“When TEN-E was created it was focused on security of supply,” she notes.

As it now stands, TEN-E encompasses so-called “priority corridors” in electricity, gas and oil. While oil is widely expected to cease being considered a priority in a new TEN-E regulation, the debate is open over gas. Although gas companies are lobbying for gas projects to still qualify as PCIs, Nagell sees no need for further gas investments on a security of supply basis and no room for subsidising natural gas with public funds.

“Some people argue that gas infrastructure could be useful because you could repurpose it for hydrogen, for example, but if you are going to base an investment decision on this you would also need to incorporate the cost of retrofitting, the delay in emis26

sions reductions and the risks of stranded assets and investment lock-in,” she says. “Gas will not be competitive in a cost-benefit analysis that includes the climate impact.”

DISTRIBUTION NETWORKS TOO Aside from incorporating the climate impact of infrastructure, there is also a push for a revised TEN-E to take into account the changing nature of power grids. “We are progressively moving from a highly centralised to a dual system in which decentralised structures are increasingly important,” says Renewables Grid Initiative, a collaboration between European TSOs and non-government organisations (NGOs), in its response to the TEN-E consultation process.

“Facilitating interactions and synergies across the voltage levels is an element which must be taken into account by the revised TEN-E.”

Gas will not be competitive in a cost-benefit analysis that includes the climate impact

Distribution networks will be increasingly important for absorbing higher shares of renewables electricity. Most solar and wind installations connect to the network at the level of the distribution grid, as will most electrified road transport and newly electrified heating technology, says Wilczek of Eurelectric.

“The European Union and instruments like TEN-E have addressed high-voltage lines but we now need to look more at medium and low-voltage lines,” he says.

To that end, Eurelectric and E.DSO, the European association of electricity distribution system operators, are now evaluating the investment needs for lower voltage networks.

“Power transmission lines have never been pretty, but they used to be associated with economic progress,” notes Ireland’s Moore. Politicians must find a way to better highlight the benefits communities can gain from cutting emissions as well as work to mitigate the negative impacts that may be associated with new electricity infrastructure. With the public on board, plans can proceed, investment can flow, jobs will follow and all can enjoy the benefits of a green energy economy. • FORESIGHT

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ELECTRICITY INFRASTRUCTURE As the United States legislates for higher shares of renewables, the development of its straggling and disjointed grid network to match its clean energy ambitions is lagging behind.

A market orientated approach to modernising its power system infrastructure will only achieve so much without much more regulatory support from federal and state level authorities

Federal green grid vision gone missing in America

A

merica’s electricity network could be considered the oldest trans-continental grid in the world. Coast-to-coast electrification took place in the US well in advance of Europe. Many lines in operation are more than 90 years old, while the bulk of the network has been in use for half a century.

PJM Interconnection, a regional transmission organisation (RTO) serving 13 states in eastern America has assets that date back many decades. Two-thirds of its infrastructure is more than 40 years old, while the other third has passed the half-century mark. Some local lines at voltages below 230 kV are approaching 90 years old.

The US transmission grid is also as big as it is old.

Hundreds of thousands of miles of high voltage power lines and millions of miles of low voltage distribution cables connect thousands of power stations to hundreds of millions of electricity consumers. There are more than 161,000 kilometres of transmission wires of 345 kV or greater. It would be tempting to assume that installation of new transmission lines as market 28

demand drives growth is just an accepted way of life in the US. Unfortunately for the growth of renewable energy, that is not the case. Massive hurdles block the construction of a few high voltage super-highways, preventing the establishment of a nationwide macro grid to get renewables generation to demand centres and to ease the task of balancing their variable supply by opening access to power from a wider geographical area.

The demise in 2019 of Clean Line Energy, a private US transmission infrastructure developer, serves as a cautionary tale on how reliance on market forces can backfire. Led by wind industry veteran Michael Skelly, Clean Line had ambitions to develop five long distance, high voltage transmission lines to carry over 16.5 GW of renewable generation across the United States. Of its five projects, three were sold to renewable energy project developers, a fourth was shelved, and a fifth was blocked by legislators in Iowa. Clean Line Energy had received $100 million from investors, showing that money is not the answer to everything.

FORESIGHT

Make transmission great again New transmission capacity being built in the US has slowed

Completed Transmission (miles/year)

SOURCE Wires Group / Scott Madden

5000

4000

3000

2000

1000

0 2009

2010

2011

2012

2013

≤ 230 kV

2014

345 kV

The US, despite the number and length of the wires criss-crossing the country, does not have a single interlinked electricity grid. PJM is part of the Eastern Interconnection grid, one of three major transmission system areas. The Eastern Interconnect stretches from the Atlantic coast to the Rocky Mountains. The Western Interconnect serves the other side of the Rockies, and the Electric Reliability Council of Texas (ERCOT) serves much of huge and sprawling Texas.

LABYRINTH WITHOUT STRENGTH Each system operates independently, with no synchronisation of power flows between them. Alternating current (AC) power from one has to be converted to direct current (DC), transferred to the neighbouring interconnection before being converted back to AC. These compartmentalised, inflexible and poorly linked power systems are now struggling to deal with the demands of traditional thermal generation, let alone the increasing levels of variable renewables.

The fragmentation runs deeper still. The company FORESIGHT

2015

2016

2017

2018

≥ 500 kV

selling power can be a non-profit municipal utility, a member-owned cooperative, an investor-owned utility or a power marketer. Functions such as interconnection oversight, balancing supply and demand, transmission, distribution, generation, and obtaining permits for system upgrades must negotiate a maze of local, state and federal authorisation instances.

Such a labyrinth of players also stands in the way of a renewables-rich grid. Fifteen states between the Rocky Mountains and the Mississippi River account for 88% of the nation’s wind potential and 56% of its solar potential. That same region is home to only 30% of expected 2050 electricity demand.

A grid with a predominantly renewable future must be capable of freeing up those wind and solar riches. “We need to improve America’s outdated and siloed electricity transmission system both to compete effectively in the 21st century economy and to properly tackle the climate crisis,” says Greg Wetstone from the American Council on Renewable Energy (ACORE), a non-profit organisation.

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ELECTRICIT Y INFRASTRUCTURE

Interconnected world The larger and more connected a grid network the better it can absorbs shocks that would unbalance an isolated power system

Some regional and state-level progress has been made in improving the fragmented US grid, with ERCOT recognised as a leader by example. The combination in Texas of a state government mandate and a market approach to getting new wires built opened the floodgates for wind generation. Texas designated priority renewable energy zones (CREZ) as transmission corridors to bring low cost wind from the west to population centres in the east. Having established a route to market for the wind generation, it invited competitive bids for provision of the wires. In all, nearly 6000 kilometres of new transmission was built in short order at a cost of $7 billion, capable of carrying 20 GW. That rapidly made Texas the US market leader in wind development. As a state it hosts 30

more than 29 GW of wind generating capacity, more than most entire countries have achieved, with the exception of China, Germany, and India.

The Midcontinent Independent System Operator (MISO), an RTO covering 15 Midwest states and part of Canada, is also making headway with upgrading its grid. MISO provides open access transmission service and high voltage transmission monitoring. It organised a Multi-Value Projects (MVPs) process and allocates funding to new infrastructure by assessing costs based on multiple values rather than one—the traditional approach that tends to throttle transmission funding in the rest of the country. MVPs took into account reliability, public policy needs such as state renewable energy goals, and regional economic value FORESIGHT

ELECTRICITY INFRASTRUCTURE

to fully assess the value of new transmission, opening the way for investment that was likely to yield a return. By broadening the scope for cost recovery for transmission line development, the approach resulted in an expansion of the grid network that has helped with the distribution of generation from this renewables-rich region.

The Western Interconnect hopes to add high voltage lines linking windy Wyoming and sunny Southwestern states, such as New Mexico, to population centres. The proposed TransWest Express Transmission Project would provide 3 GW of transmission capacity to deliver Wyoming wind generation to Arizona, Nevada, and southern California. But completion of the 1175 kilometre, 500 kV link is far from certain, stymied by wrangling over permitting between federal, state, local and native land jurisdictions. Enormous distances and mountainous terrain add further barriers. Militant local groups intent on stopping infrastructure projects around their towns, regardless of whether it is an oil pipeline or a wind transmission corridor, add to the litany of problems.

Such a labyrinth of players stands in the way of a renewables-rich grid

Within the Eastern Interconnect area, efforts to secure 80% of electricity from wind and solar generation by 2050 are underway, including tapping into offshore wind capacity planned off the Atlantic Ocean coastline. But generation from offshore wind projects will hit a transmission bottleneck unless investment in grid upgrades can be unlocked. Offshore areas have been leased for 29 GW of wind development along the east coast alone. New York has further issued a solicitation for 2.5 GW of offshore wind capacity and has legislated 70% clean electricity by 2030 and 100% by 2040. New Jersey plans a comparable amount of offshore wind and wants 50% of its electricity from wind power by 2030, while other coastal states have impressive wind power ambitions.

Connecticut targets 100% by 2040; Maryland 50% by 2030; and Maine wants 100% of its electricity from renewable sources by 2050.

If the almost 30 GW of offshore wind comes online, the current grid can accommodate less than a quarter of that at best. Lack of transmission is a FORESIGHT

mighty roadblock in the path of the states’ ambitions.

Overall, there are plans to build about 214 GW of new generation in the US in the next five years, 80% of which will come from renewables. Without a major shift in the transmission picture, much of that power will have nowhere to go.

Under the Administration of Donald Trump, little help has been on offer from the Federal Energy Regulatory Commission, which regulates interstate power affairs. New orders to specifically direct it to facilitate transmission of renewable energy across America may be forthcoming from a government under the presidency of Joe Biden.

BREAKTHROUGH EFFORTS Multiple pieces of the power grid puzzle must fall into place to improve the situation, even when ignoring the political and human elements of the problem. Just making the right decisions on what wires to string up and where is a sizable challenge. Transmitting electrical energy at higher voltages not only reduces line losses, but can also reduce public opposition. A single 765 kV line on a 60-metre-wide right-of-way carries the same amount of power as 15,138 kV lines requiring a land corridor 450 metres wide causing fewer permitting headaches per MW of power transmitted.

A federal instead of a state approach would make economic sense and likely speed grid modernisation.

Advocacy groups ACORE and Americans for a Clean Energy Grid (ACEG) have launched the Macro Grid Initiative to build support for a nationwide, high voltage direct current (HVDC) network, optimised for the best wind and solar resources. HVDC line losses are 3.5% for each 1000 kilometres traversed, compared to 6.7% or more for AC lines at similar voltage levels, more than making up for the 1% of the AC to DC and back again converter station losses. An HVDC backbone for the US can be likened to the freeway system that criss-crosses every state and often rings major cities. That road network took federal government initiative backed by billions of dollars over many decades.

An alternative to immediate major investment in new transmission would see existing lines upgraded to higher transfer capacities, achievable using improved conductors or increasing voltage rating. Flow controllers could also be used to route power to less congested parts of the network, a relatively cheap option that is easily installed. In heavily populated areas likely to resist “reconductoring”, or HVDC efforts, avoiding the permitting barrier can be a faster route to getting more renewable energy on the grid, but it is a limited and short term solution. Upgrading substations to the latest standards and adding capacitor banks can also boost the transfer capacity of existing 31

ELECTRICIT Y INFRASTRUCTURE

lines. The cost of such improvements to the existing system comes in at millions of dollars, an easier pill to swallow for utilities, both investor owned and municipally owned, than development of multi-billion dollar HVDC lines.

A digital solution, called Dynamic Line Rating (DLR) technology, uses real time monitoring to constantly calculate line rating variations (tension levels) on transmission lines. Pacificorp, a utility based in Oregon, gained around 100 MW of additional transmission capacity from using DLR. While the gains would be greater with a new transmission line, so would the cost. For comparison, a new 230 kV line would cost $50-to-$75 million and would have to jump through numerous approval hoops over many years, while Pacificorp secured its additional capacity for a modest cost of around $1 million.

While HVDC may solve delivery of bulk power from massive wind and solar farms, the grid also needs to adapt to the growth of distributed energy resources (DERs). DERs feed into local distribution networks reducing demand on the high voltage transmission network. Yet traditional rules and restrictions often make it difficult for DER to access the grid. Financial barriers either prevent their creation or limit their ability to be compensated for any power they make available to the grid beyond their own needs.

A new microgrid testbed known as DERConnect is using a $39 million grant from the National Science Foundation to validate autonomous grid operation technologies to optimise the use of DERs. The project encompasses an energy storage testing facility as well as more than 2500 DERs already existing on the University of California microgrid at the San Diego campus, a number of buildings, and 300 electric vehicle charging stations. It is just one of many initiatives attempting to increase the viability of DERs and evolve a smarter grid. But again, legislative barriers and utility resistance stand in the way of distribution-transmission systems becoming better coordinated so DERs can play a role in balancing load and meeting demand as well as reducing demand on the wider grid.

LESSONS LEARNED The United States’ market oriented approach to development of its power infrastructure works at regional and state level to control the cost of new build. But the piecemeal strategy stands in contrast to Europe’s increasingly holistic planning of a fully interlinked continental grid. Similar planning may be required at federal level in the US if the country is to reap the full advantages of its vast renewable energy resources, both to clean up its energy use and to reduce the cost of doing so. Wind energy development, often man32

dated by law, but with increasing frequency selected as the cheapest option for meeting demand, could be the driver for transmission build-out, though progress is likely to be slow without regulatory support.

“Just as the Eisenhower interstate highway system unleashed US manufacturing in the 20th Century, a strong grid will deliver massive economic and public health benefits for all Americans in the 21st Century,” says Rob Gramlich at ACEG. States continue to set ambitious mandates for renewable energy and targets for when their energy consumption releases no more carbon emissions than they can offset by other means. Yet the number of kilometres of transmission capacity built has been in steep decline since the completion of the CREZ lines in Texas in 2013 and 2014.

A strong grid will deliver massive economic and public health benefits for all Americans

The laws driving CREZ construction in Texas were passed in 2005 but it took years to lobby that legislation into reality and a decade to build. Similar Western Renewable Energy Zones (WREZ) were conceived in 2008 to facilitate high voltage construction, but nothing ever materialised. The TransWest HVDC line has been on the drawing board since 2005, unable to make it from paper to reality. Progress has been made but it will take years for the 600 kV line from Southern Wyoming to Nevada and California to traverse its 200-kilometre path. With luck, construction commencement will not be delayed beyond late 2021—its current estimate.

Federal intervention into the transmission network appears more likely under the presidency of Joe Biden, where climate change mitigation through development of renewable energy is high on the agenda. On top of efforts at state level, one possible tool for the new administration is the issuance of an investment tax credit that would make investment in transmission a tax haven for corporations, doing for grid development what tax credits have done to drive wind and solar installations. Even so, without a strong political lead that gets the public behind grid modernisation, a long and rocky road lies ahead. Unless people understand the benefits that major grid upgrades will bring to them and their offspring, towns, county, state, and community activists are likely to contest every inch of progress. • FORESIGHT

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CLEAN HEATING Space heating of buildings is a major source of carbon emissions. That need not be the case.

Decarbonisation of heating requires switching from systems and appliances that combust fossil fuels to those that rely on renewable energy. Nowhere is the switch more challenging to achieve for existing building stock than in the UK. If it can be done there, it can be done anywhere

T

he UK has made great strides in sourcing electricity from renewable energy sources, but it is a laggard when it comes to decarbonising of its heating sector. A bold new vision—featuring district heating, the electrification of heating with heat pumps and investments to increase the energy efficiency of buildings—will not be easy nor cheap to implement, but could allow the UK to make up lost ground. Betting on hydrogen to clean up heating, however, is likely to prove to be a costly distraction if the UK is serious about reaching its 2050 target for net zero emissions.

In the UK, 85% of homes are heated by natural gas and the proportion of gas-fired home furnaces, known as boilers in Britain, keeps growing. Some 1.7 million gas boilers were installed in UK households in 2019, up 1.8% from a year earlier, when only 27,000 heat pumps were added. At that rate, the UK Energy Research Centre (UKERC)—a group of academic institutions—says it would take over 700 years to reach the 19 million heat pumps the Committee on Climate Change (CCC), a public body that advises the government on emissions targets, has indicated will be necessary to meet the UK’s binding net zero emission target for 2050.

34

Heat pumps, which transfer heat from air, water or ground sources using electricity, have the potential to deliver immediate carbon emissions savings of 60-70% compared to conventional electric heating and 55-65% when compared to an efficient gas boiler, figures that can rise when combined with energy efficiency measures to reduce space heating demand, the UK-based non-profit Carbon Trust found in a report released in August 2020 on the opportunities and obstacles to retrofitting existing London homes with heat pumps. As the UK grid continues to decarbonise, heat pumps are seen enabling roughly 90-100% carbon dioxide emissions reduction by 2050, it said.

AN IMMEDIATE FIX “Heat pumps are now the only readily available net zero carbon solution for heating at scale,” says Will Rivers of Carbon Trust, who stresses that the time to start taking action is now. “We are only 30 years away from 2050 and social housing, for example, invests with a 30-year time horizon.” What makes heat pumps particularly attractive is the prospect that the electricity they use will eventually be from an entirely renewable energy source as the UK power sector FORESIGHT

Housework Collective heating of dense city housing through heating networks is cheaper, cleaner and less trouble for property owners. The energy needed can also come from offshore wind power

TEXT Heather O’Brian PHOTO Gleren Meneghin

How to decarbonise the building stock in Britain

FORESIGHT

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CLEAN HEATING

It's a gas Gas boilers dominate the UK’s heating system

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Gasboiler Heat pumps

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shifts from fossil fuels to supply from mainly solar and wind resources, particularly offshore wind.

Heat pumps vary in size from smaller versions for individual buildings to multi-megawatt units for district heating networks in which insulated pipes transport hot water for heating. Heat pumps use less energy to produce the same amount of heat than either gas or electric boilers. The coefficient of performance (COP) for a building heat pump is about three, meaning every unit of energy used to power the heat pump will yield three units of heat energy.

Richard Lowes of Exeter University concurs that the “technologically sensible solution” to decarbonising heating in the UK is heat pumps. “We know how to produce low-carbon electricity and there are not many alternatives for heating. There is biomass but there is not so much of that available and there are big questions about its sustainability. There is also solar thermal, but that will not do much for you in the UK in the winter.”

WHAT ABOUT HYDROGEN? The problem about electrifying heat is that it will be “difficult and costly,” adds Lowes, with major invest36

Night storage heater District heating Energy savings Other

ments needed both for heat pumps and energy efficiency measures. “So we have rapidly seen this idea develop of using hydrogen in the gas grid, which is worrisome because it has never been tried before but has nonetheless risen up the political agenda quickly.”

Not only is it an unproven technology, but hydrogen also looks to be a much more expensive option and could be a greater source of pressure on the electricity grid than the electrification of heating. Heating a house with green hydrogen—which uses renewable energy electricity to power electrolysers that split water into hydrogen and oxygen—would require five times more electricity than doing so with a heat pump, says Jan Rosenow of the Regulatory Assistance Project (RAP), a global think tank on power system strategy.

Hydrogen can also be won from a methane source like natural gas, but the required process, “Results in hefty conversion losses and a big problem with carbon capture and storage”, says Lowes. The use of hydrogen for heating is largely being pushed by gas companies. They have, “Seen hydrogen as the best way to keep the gas grid largely as it is while giving politicians a cover to say they have a long-term plan,” says Paul Voss, managing director of Euroheat & PowFORESIGHT

SOURCE UK Energy Research Centre

24%

CLEAN HEATING

er, an advocacy group. “It would be ridiculously expensive and there are better uses for hydrogen than heating your living room.”

It is possible that stored hydrogen could be used to meet peak heat demand, or be combusted for electricity if a power system reliant on a high share of renewable energy was failing to meet demand, but the prevailing view is that its main role should be reserved for use in hard-to-electrify industrial and transport sectors.

INEFFICIENT BUILDINGS The CCC has said all new buildings in the UK should be required to have a low-carbon heating solution by 2025 and a natural push towards heat pumps and electrification of heating is expected along with the construction of energy-efficient buildings. But with up to 80% of UK homes built today likely to still be in use in 2050, decarbonisation efforts will fall short unless the inefficiency of older buildings is tackled.

“Whatever decarbonisation route we take, we need to massively reduce heat demand,” says Rivers of the Carbon Trust. The UK’s housing stock poses a “considerable threat” to the country’s net zero plans, energy company Engie warned in October 2020 as it unveiled a new low-carbon housing retrofit programme. A study from smart thermostat provider Tado released in February 2020 showed UK homes lost heat up to three times as fast as their European neighbours.

Heat pumps are now the only readily available net zero carbon solution for heating at scale

Research from the UKERC has shown that improving energy efficiency of buildings has potential for cost-effective savings by 2035 equivalent to a 25% reduction in demand. Since some of the housing stock will be more difficult to decarbonise, the Carbon Trust argues that deep retrofits will be necessary in some buildings to make up for others where the possibility of efficiency improvements is limited. Cheap gas means energy efficiency measures are less important from an economic standpoint.

Electricity prices in the UK are about triple that of gas but some electricity suppliers offer lower rates for off-peak hours, which consumers with energy efficient houses that retain heat can take advantage of by pre-heating, improving the business case for FORESIGHT

heat pumps and contributing to the flexibility of the power system, helping to flatten peaks in demand that would otherwise be met by relatively expensive stored energy or a fossil fuel source. The business case for heat pumps could also be bolstered by changing a tax system which favours the consumption of gas over electricity.

The UK government has taken some steps to support building retrofits, such as a €3.3 billion green investment package launched in summer 2020, which includes a €2.2 billion green homes grant to support household energy efficiency measures and heat pumps.

Yet Rosenow says government indecision over the use of hydrogen or heat pumps has meant that policy support for the electrification of heating has fallen short. He also highlights the significant practical obstacles to installing heat pumps. “You cannot just take out a gas boiler and in a few hours replace it with a heat pump,” he says. The UK heat pump market is immature, installers are often inexperienced and the upfront costs of a household heating pump are high.

“And if you have a really inefficient house, you cannot run the heat pump efficiently,” Rosenow adds.

HEAT NETWORKS Dave Andrews, an energy consultant, believes district heating should be the UK’s absolute priority, citing the impact a massive shift to individual heat pumps could have on peak winter power loads, the resulting need for investments in grid infrastructure, and difficulties retrofitting old UK homes. “District heating is inherently cheaper than anything else,” says Andrews. He envisions the UK’s expanding fleet of offshore wind farms powering district heating networks that are equipped with megawatt-class heat pumps.

Michael King, a district heating expert, notes that the COP of the large heat pumps used in district heating networks is roughly double that of household heat pumps, with one unit of input energy yielding six. Another advantage of district heating is the possibility for large volumes of thermal storage, for example in giant hot water tanks, providing flexibility in the energy system at a small fraction of the cost for battery storage.

District heating also allows for flexibility in the heating source, which can evolve over time and can encompass eve-ything from electrification to combined heat-and power plants running on hydrogen, notes Rachel Lee of renewable energy and sustainability consultancy 350 Strategy. She believes they should be the favoured option for cities and built-up areas, although individual heat pumps will be needed in areas where houses are further apart due to heat losses when hot water is transported over longer distances.

37

CLEAN HEATING

Big gap between reality and ambition Deployment of heat pumps in the UK

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District heating currently only represents a niche of the UK’s entire heating market, with estimates in the range of 2-4% of the total. CCC expects about 18% of UK heat will need to come from heat networks by 2050 if the UK is to meet its carbon targets cost effectively.

The Greater London government anticipates 25% of the heat and power used by the city will be generated through localised decentralised energy systems by 2025 and considers the development of decentralised heating and cooling networks to be a priority.

One innovative example is the Bunhill 2 District Heating facility in Islington, developed by Danish firm Ramboll, which uses waste heat from the London Underground train network alongside heat pumps to provide heating and hot water to 1350 homes. In Glasgow, the Queen’s Quay regeneration housing project in Clydebank features Scotland’s first large water source heat pump project, in which two, 2.65 megawatt heat pumps will extract heat from the River Clyde and feed it into a district heating network providing heating and hot water for the surrounding development. The system also has back-up boilers and a thermal storage system for periods of high demand.

38

2034

2048

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5x Current deployment rate

FINANCIAL INCENTIVES One of the most difficult problems for heat networks can be financing. “A lot of this is about persuading banks that this is not a high-risk investment, that once people are connected to the network they are quite unlikely to disconnect,” says Lee. She suggests one solution for improving the investment framework could be the introduction of incentives, such as the UK’s Contracts-for-Difference system that underpins the market for sales of electricity from renewable energy.

Securing upfront demand for heat networks can be facilitated by heat planning, which in turn eases financing, says King. Progress on this front can be seen in Scotland, where every municipality will be required to prepare a 20-year Local Heating and Energy Efficiency Strategy detailing how it intends to meet heat needs. King says district heating is a no-regrets option, but stresses that no matter how the UK chooses to decarbonise its heat, getting off gas will not be easy. “I think that people need to understand that this is going to be hard. You have to decide which is the least difficult route for decarbonisation and will deliver net zero at the lowest cost.” • FORESIGHT

SOURCE UK Energy Research Centre

Million heat pumps installed

20

WE DESIGN THE CITIES OF TOMORROW

WITH THE WASTE OF TODAY

THE DENMARK PAVILION

OL TOKYO 2021 DESIGNED BY LENDAGER UPCYCLED PLASTIC SOLUTIONS BY RE-PLASTIC Visualization | Josep Villanueva Studio

Contact | re-plastic.dk

CLEAN HEATING Denmark has led the way on decarbonisation of heating, with a rapid transition away from fossil fuels aided by its large scale adoption of heating networks over the past 40 years.

Instead of exchanging individual heating appliances in every home and commercial building, the Danes are centrally converting their heat networks to renewable energy, saving citizens a pile of money in the process

D

enmark has a head start in eliminating fossil fuels from its heating, with twothirds of households served by district heating networks, which cover over half the country’s entire heating needs and source about 60% of their heat from carbon-neutral energy sources. Coal and natural-gas fired combined heat-andpower (CHP) is on its way out along with individual oil and gas furnaces in homes. On their way in are biomass CHP, with the emphasis on heat, and heat pumps.

The Danish energy and utilities sector is targeting an over 95% reduction in emissions compared to 1990 levels by 2030, with heating to be a major contributor in achieving that goal. Denmark’s overall aim for the same time span is a 70% reduction in emissions.

The phasing out of coal in CHP should lead to a reduction of six million tonnes of carbon emissions, while replacing oil and gas in individual heating systems and natural gas and oil in district heating is set

40

to cut emissions by a further four million and one million tonnes, respectively, according to a roadmap from the Danish government’s “climate partnership” with the energy and utilities sector. By 2030, the continuing transition to renewables and further energy efficiency improvements should reduce emissions from the energy sector to one million tonnes annually, from 32 million tonnes in 1990, representing half all Denmark’s projected cuts.

“Many utilities already replaced coal in CHP plants with biomass,” says Steen Schelle Jensen, a heating and cooling specialist at Kamstrup, a provider of energy solutions. “The next step is electrification and sector coupling.” Decarbonisation is made easier by the country’s extensive district heating network. “It is an advantage because if you want to change something you only need to do it one place instead of in every single house,” points out Per Alex Sørensen of sustainable energy consultancy PlanEnergi.

While the increased use of heat pumps in district FORESIGHT

Child's play District heating is the easy and cheap option for cosy-kids in kindergartens in Denmark, both ancient and modern (pictured) Architects: COBE Photo: Rasmus Hjortshøj - COAST

TEXT Heather O’Brian PHOTO Rasmus Hjortshøj - COAST

Decarbonised heat within a decade in Denmark

FORESIGHT

41

CLEAN HEATING

Danish heating cleans up Renewable energy is increasingly keeping Danish homes warm

100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 2013

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heating, individual heating systems, and industry will contribute to a reduction in anticipated overall Danish energy use in 2030, the sector roadmap also sees them boosting demand for electricity by about nine terawatt hours (TWh) in the same period. Heat pumps run on electricity to transfer heat from air, water or the ground to an indoor space. but use far less energy to produce the same amount of heat as traditional heating appliances.

ELECTRIC BOILERS AND HEAT PUMPS Birger Lauersen of the Danish District Heating Association says its members are increasingly investing in electricity, both with electric boilers that are “quite cheap and relatively easy” to put into place and heat 42

2015

pumps, which are more efficient but “a bit trickier” and require access to a heat source whether from the ambient heat in air outdoors, from seawater, or low-temperature industrial waste heat, none of which could be efficiently exploited in the days before heat pumps. The big heat pumps used in district heating are largely bespoke solutions, Lauersen says, and adopt different solutions to the site-specific technical challenges of upgrading heat to a temperature at which it can be used in a network.

Lauersen says the decarbonisation of heat in Denmark will lead to the expansion of district heating to some of the 375,000 households still using gas and 75,000 households using oil boilers. Denmark has about 2.7 million households. “District heating is a FORESIGHT

SOURCE Danish Energy Agency

2012

CLEAN HEATING

large-scale solution with benefits of scale, including flexibility, but it is not feasible everywhere. Individual heat pumps are more suitable in areas with low heat density,” he says.

One element of flexibility in district heating is that it allows for the use of multiple heat sources—including solar thermal, geothermal, biomass and industrial waste heat—while household heat pumps are bound to electricity. For district heating, the first priority is to use direct heat from a renewable resource, but when supply of renewables-generated electricity exceeds grid demand for it, meaning prices are low, it can make sense to use electricity directly, says Jensen.

That flexibility can also help to facilitate power system operation, where supply and demand for electricity must always be in balance. When Danish wind turbines are turning in the middle of the night and demand and prices dip, their output can be channelled to heating water stored in the district heating system.

Heat is easier and cheaper to store than power.

TAX INCENTIVES To encourage the use of heat pumps in both district heating and for individual households, the government has slashed electricity taxes for heating and raised those on fossil fuels. As the Danish heat pump market becomes more competitive, Schelle Jensen says some district heating suppliers have begun leasing heat pumps to customers outside a heating network, covering the upfront costs. The government has also begun subsidising the purchase of heat pumps for people living outside the district heating catchment area.

Heat is easier and cheaper to store than power

Several smaller Danish towns have begun to gain experience with the use of heat pumps in their district heating, says Martin Lundrup of energy industry trade body Dansk Energi. “We need to learn more about using heat pumps in larger cities,” he says and particularly incorporating them into the district heating system.

Some larger projects are now in the planning stage. Most recently, the heating supply company in the coastal town of Esbjerg has started the process to install a 50 MW heat pump, along with a 60 MW wood chip fired boiler and 30 MW electrical boiler to reFORESIGHT

place heat delivered from the existing coal-fired power station, to be retired in 2023. Esbjerg, with a population of 115,000 is the fifth largest town in Denmark.

BIOMASS COMES CLEAN Biomass, including wood pellets and straw, has been the main driver for taking fossil fuels out of Danish heating, a fuel choice encouraged by changes to energy taxation. Danish lawmakers also recently agreed a further tightening of sustainability requirements for biomass fuel.

“There has been an increase in biomass imports and that led to the consideration that we should be using our own resources rather than taking them from other countries,” explains Marie Münster, a professor in energy system modelling at the Technical University of Denmark. “There were also concerns about how to ensure that biomass is climate neutral.” Although trees and other biomass sources are renewable when consistently replanted, their combustion releases CO2 that takes decades to be reabsorbed in nature’s circular economy. Moreover, the transport of biomass over long distances contributes further to emissions unless the fuel used is from a renewable source.

In the short-term, many CHP owners will continue to source biomass that meets the new sustainability requirements, but in the long-term its role may diminish significantly, she says, depending on the future price of sustainable biomass and the potential use of carbon capture and storage (CCS) in biomass-fired CHP plants to prevent release of any emissions.

SOLAR AND GEOTHERMAL Denmark is the global leader in solar thermal, but that market leading position still only allows it to satisfy about 2% of heating requirements, much of it by channelling utility scale solar heat into local heating networks. While solar is expected to play a supporting rather than a leading role in supplying heating, its impact could grow. Solar thermal facilities now cover about 1.6 million square meters and potential capacity is placed at about eight million square metres.

The next frontier for district heating in Denmark may be underground, in geothermal energy, which due to the relatively low temperature of the resource available in Denmark would need to be used with heat pumps. Denmark’s second largest city after Copenhagen, Aarhus, has teamed up with AP Møller Holding, which controls Danish shipping group AP Moller-Maersk, to explore plans for supplying 100,000 households with geothermal heat. Aalborg, the fourth largest city, is also looking to use geothermal energy. AP Møller Holding estimates that up to 30% of Danish district heating could be provided by geothermal energy.

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CLEAN HEATING

The potential for capturing the vast volumes of heat emitted from Denmark’s data centres is largely untapped

Data centres, a major and growing consumer of Danish electricity, are also a potential source of heat.

Earlier this year, Facebook’s data centre in Odense began supplying low-temperature heat to the local district heating operator, which uses a heat pump to raise the temperature of water heated by servers on the site to a level that can be used in the energy system. The high reliability of electricity supply in Denmark, the 50% renewable energy content of that supply and the country’s suitable ambient climate temperatures has made it a favoured location for data centres. Google and Apple have also set up data centres in the country.

The potential for capturing the vast volumes of heat emitted from Denmark’s data centres is largely untapped as yet, says PlanEnergi’s Sørensen. Data centres are huge and there is a lot of excess heat, he says. “But using it is often more complicated because the data centres are located near the electricity grid but far away from cities.” Solutions include using liquid cooling for servers rather than air cooling, which would deliver heat at a temperature that could be more easily used in district heating.

Looking to the future, the use of electricity to produce hydrogen gas, or a hydrogen-based product, is in some quarters being regarded as a new heat source.

Converting electricity to a storable fuel is widely referred to as Power-to-X and combustion of hydrogen for energy produces no emissions at its point of use.

If hydrogen is derived through electrolysis and the electricity used is from a renewable source, the gas becomes a clean fuel which could be used in district heating. The cost of the entire process, however, has many experts saying that hydrogen should be reserved as an option for sectors that are hard to electrify, such as heavy transport and industries reliant on very high temperature heat.

Equally, the role of biogas in heating is also expected to be limited, although it may play a part in the short term in some individual households where 44

the cost of heat pump replacements is high and in replacing some natural gas in district heating. “Biogas is fairly expensive and should not be used for heating in the long term but instead for transport and some industrial processes that are hard to electrify,” says Lundrup.

HEATING A SMALL PROBLEM In June 2020, 171 of the 179 lawmakers making up the Danish parliament passed the Climate Act that ushered in the 70% emission target for 2030. Changes to energy taxation and new sustainable biomass criteria are also the result of a shared vision stretching across the political spectrum. Cross-party agreement on fundamental principles is normal in Denmark and once policies become law, targets such as decarbonisation of heating are usually met. “Since the 1970s, there has been a broad consensus on energy and the climate crisis, which helps provide a predictable environment in which to invest,” says Lauersen.

Münster expects the hardest part of decarbonisation in Denmark will involve the transport, industrial and agricultural sectors, rather than heating. “We are hoping heating will be a small problem. To a large extent, there are already policies in place to decarbonise it.” • FORESIGHT

Next era A new generation of Danish children will come of age used to open space living and play in comfortable indoor environments made possible by ample supplies of affordable heating delivered through district heating networks in winter and by cooling networks in summer Architects: COBE Photo: Rasmus Hjortshøj - COAST

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46

FORESIGHT

TEXT Ros Davidson PHOTO Zhang Kaiyv & Knut Troim

TRANSPORT Three concerns are said to be hindering the uptake of electric passenger cars—high purchase cost, fear of a flat battery, and lack of charging infrastructure. But cost has fallen, the range of car batteries now rivals that of a full tank of fuel and recharging a depleted battery when the need arises is proving to be easier than expected

Charging ahead T

he electrification of road transport will be essential to averting climate disaster. Transport is responsible for more than 15% of annual global emissions and in countries such as the US and UK, it contributes more climate emissions than the entire electricity generation sector, notes Amanda Myers, a policy analyst at Energy Innovation, a US research and analysis firm. Worldwide, transport as a sector has the fastest growing emissions, she says.

The roll-out of electrical vehicles (EVs) is accelerating. In China and Europe by 2025 they will account for between 13% and 20% of all new vehicle sales, growing to almost 70% in both regions by 2040, says Ryan Fisher of BloombergNEF, the new energy finance arm of New York research and media company Bloomberg. In the US, the share of EVs in vehicle sales is progressing more slowly, a reflection of less strict fuel economy regulations and car model availability, but EV deployment will catch up with that of other major economies in the 2030s, he says.

Beijing China has the world’s largest EV market, and over half the world’s public chargers FORESIGHT

EVs are expected to reach price parity with those propelled by internal combustion engines by mid-decade, faster than earlier predictions because of plummeting battery prices. This leaves two further barriers to their uptake: the fear of a battery running out mid journey and a perceived potential lack of sufficient charging infrastructure, notes Jean-Christoph Heyne of Siemens’ Future Grids business unit.

For full e-mobility, charging an EV must become as easy as charging a smartphone, argues Heyne. “It is chicken and egg,” he says, especially for people living in large cities without the convenience of a private parking space with an electricity outlet. They have to rely on public charging infrastructure. “If it is not there, you will think twice before buying an e-vehicle,” he says.

Reference to public charging includes charge points along freeways and other major roads, at the kerb side on urban streets, at workplaces and in municipal or shopping centre car parks, or at hotels, restaurants and airports. Although some of these locations are technically “private” they are often included in the definition of public charging points.

47

TRANSPORT

Home charging will go a long way to meeting demand. Some 90% of US EV charging is at home as early EV adopters often have a private parking place. Yet, home charging will not cover all demand longer term.

Chris Nelder, a manager on the mobility practice at the Rocky Mountain Institute (RMI), a clean energy think tank, notes that even in the US, with its extensive areas of light population, a third to 40% of homes are in multi-unit buildings that may not provide parking areas where charging points could be located. In California—the country’s largest EV market—about half the population lives in such buildings.

HOME CHARGING FOR NOW Longer-term most EVs will continue to be charged at home. The International Energy Agency (IEA), in its Global EV Outlook 2020: Entering the decade of electric drive, says that of the roughly 7.3 million chargers worldwide in 2019, about 6.5 million were charged at homes and workplaces. “Convenience, cost-effectiveness and a variety of support policies (such as preferential rates, equipment purchase incentives, and rebates) are the main drivers for the prevalence of private charging,” the report concluded.

In America over 90% of the charge points and over 70% of all the required electric energy for electric vehicles are likely to come from home charging for the foreseeable future, agrees the International Council on Clean Transportation (ICCT) in its January 2019 white paper, Quantifying the Electric Vehicle Charging Gap across US Markets. But it sees the use of public and workplace charging growing more rapidly. The US EV market is expected to grow from about one million vehicles in late 2018 to three million-plus on US roads by the end of 2025.

Meanwhile, for those who cannot charge at home or are driving long journeys, the current availability of public charging is likely to be sufficient for the time being. Most of the time, drivers do not go far on a daily basis and the range of the newest EVs on a single charge has also now reached almost 650 kilometres.

RMI’s Nelder says before owning an EV, drivers often overly worry about charging but once they own one they realise they do not have to charge as often as expected. Yet he stresses that predicting how charging will evolve even in the medium-term is difficult.

He views most forecasts of public charging as conservative. “As long as EVs remain as 2% of [US car] sales, we are not going to know for a while,” he says.

PUBLIC CHARGING TO GROW For EVs to become a vehicle for the masses and not just a second commuter car, some market forecasters argue that mature public-charging infrastructure must come first. They say home chargers will deliver 48

43% of EV energy demand, with other types of charging, including at workplaces and at depots for trucks and buses comprising the balance.

Ultra-fast chargers, acting like today’s refuelling stations for ICE vehicles, are most likely to be found on major through-routes. They can serve a much larger number of cars than either a slower public charger or home charger, but make serious demands on local grid capacity. BloombergNEF forecasts ultra-fast chargers delivering 30% of the power used for transport globally by 2040, although it predicts they will make up just 4% of chargers globally: 12 million chargers out of 280 million.

Home charging goes a long way to meeting the demand but it will not be enough

The infrastructure for electric-vehicle hook-ups is expanding. In 2019, publicly accessible chargers accounted for 12% of global light-duty vehicle chargers, most of which are slower chargers. Globally, the number of publicly accessible chargers, slow and fast, increased by 60% in 2019 compared with 2018, higher than the electric light-duty vehicle stock growth, says the IEA. However, market analysts believe the pace of deployment needs to increase. The ICCT found that across the 100 most populous US metropolitan areas, more than 195,000 non-residential electric vehicle charging points will be needed by 2025, more than quadruple the 2017 total. Public charging infrastructure deployment, including at workplaces, will have to grow at about 20% per year to meet the 2025 targets, according to its forecast.

Transport & Environment (T&E), a European advocacy group for the EV industry, says that around three million public charging points will be needed in the EU and UK for 44 million electric vehicles by 2030. In many cities in western Europe, charge points are already standard in underground parking beneath residential and office buildings. In January 2020, the region had around 185,000 charge points.

To reach 44 million requires a 15-fold increase and private and public investment of some €20 billion, according to T&E. Yet that is just 3% of the EU’s annual spend on road infrastructure. “Not an unthinkable sum,” notes T&E. FORESIGHT

TRANSPORT

Public charge points for batteries a business of flat returns Positive cashflow from public charging networks takes years to establish

$(k)

$250

IRR: -$5 Payback period: >10 years

Y5: First positive cash flow

$125

$0

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-$250

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Cities can streamline permitting, building codes, and zoning to accelerate residential, parking garage, right-of-way, and kerb-side charging, says the ICCT. In the US, individual states can offer tax rebates and, through cost-sharing, support charging providers as they improve business models, its report says. China requires that new residential and office buildings are readied for installation of charging infrastructure, notes Siemens’ Heyne. Utility involvement is also key, where efforts for utility funded charging infrastructure are imminent in many marketplaces, adds ICCT.

DRIVING MORE DEMAND A 2020 RMI report, Reducing EV Charging Infrastructure Costs, found that in a market such as the US, soft costs—including permitting delays, complex utility interconnection processes, compliance with a balkanised framework of regulations, and re-engineering projects based on incorrect information—are often FORESIGHT

Opex

Net cash flows

more significant cost drivers than the actual hardware. Installation costs are a much larger share of the total cost of installing EV chargers in the US than in Europe, RMI’s Nelder says.

Yet momentum in the provision of public charging is growing. Germany is speeding up construction of a national network of public charging points. With billions of euros of public investment, it is targeting a million high-speed public chargers by 2030, or a charging point ten minutes from every home to help boost demand for EVs and ease range anxiety. All petrol stations will be required to offer charging.

According to ICCT, Germany intends to invest more than €3 billion in the charging infrastructure for cars and trucks by 2023. As part of a covid-19 recovery stimulus package, the government has announced an additional €500 million for expanding private charging.

In the UK, Project Rapid aims to help the govern49

TRANSPORT

50

FORESIGHT

TRANSPORT

Easy driver Norway has roughly 11,500 publicly available charge points

ment meet its goal of six rapid chargers at every service area on a motorway by 2023, with 6000 across the whole network by 2035, notes Russell Fowler, EV senior project manager at the UK’s National Grid. Motorways and electricity transmission lines often run along the same infrastructure corridors, he points out. The UK government’s national budget from March 2020 earmarked at least €550 million to support the roll out of rapid charging hubs, by the end of which all EV drivers would be less than 50 kilometres from a charger.

In California, more than 80% of residents are already within a 15 minute drive of a charger supplied

by EVgo, says the company, owner of the America's largest publicly accessible fast-charging network. California has pledged to ban all sales of new petrol-powered vehicles by 2035, a decision it took in September 2020. The US might have fewer than half as many chargers as the EU, but that could rapidly change if further states follow California’s example.

CHINA LEADS China, the world’s largest EV market, has 52% of the world’s public chargers and 82% of the public fast chargers, says the IEA. Of the 1.3 million chargers serving China’s 3.1 million EVs, 500-600,000 are public, according to Zhe Wang with RMI’s China transport initiative. Charging at home in China is often impossible because of a lack of sufficient chargers connected with residential buildings, notes Wang.

Norway’s EV association is advocating charging at home, because it is cheapest and requires fewest grid upgrades

The central Chinese government recently announced a post-covid infrastructure deployment plan that some observers say could lead to some 60 million public and private EV chargers installed by 2030.

Wang estimates 20-30 million as more realistic.

Public charging is easy in China. Drivers typically pay using a QR code, or they have an account. As of 2020, private companies TELD New Energy and Star Charge operate more than 29% and 24% of the public chargers, respectively. The national utility State Grid FORESIGHT

is third with 17%. In China, RMI has found that users such as taxis and drivers for ride sharing companies and logistics vehicles clearly prefer fast charging, even if it degrades a battery more than does slow charging, with extra longer-term cost resulting.

The payback for installing a charging point is three to four years in China, says RMI. Land is a tight constraint, more so than the grid, Wang says. In some cases, cities are even slowing down approval of charging points because of competition for land.

NORWAY GOES FOR HOME CHARGING Elsewhere, Norway has the highest penetration of EVs globally even if China has the greatest number.

In the first half of 2020, EVs made up almost 50% of Norway’s new passenger car purchases, according to the Norwegian EV association. Of the 2.7 million passenger cars on the road, about 290,000 are fully electric. The association has found that 75% of charging is done at home. It is estimated Norway’s home charging points approximately equal the number of EVs, and it has roughly 11,500 publicly available charge points, including those that are semi-private and charge only Teslas, says the association’s Petter Haugneland.

The association is advocating that as much charging as possible should be done at home, because it is cheapest and requires fewest grid upgrades. Fast charging at a public charge point would be supplemental, says Haugneland.

Starting in 2017, the Norwegian government partly financed installation of two fast chargers for every 50 kilometres on most roads. Financial support was up to 40%, except in extremely remote areas where it could be as high as 100% as there was little commercial interest.

Charging parks—with up to 50 charge points— have been found to be effective, with some already developed in major cities, says the association. Future plans include adding banks of second-hand EV batteries in containers to these parks. Charging the batteries with off-peak renewables generation, when it may sell for a lower price, would help cover the cost of buying and running the containers. The stored power could serve to reduce the sudden demand on the grid if the park becomes full, suggests Haugneland.

The installation of fast chargers has been successful. In the summer of 2020, Norway’s away-fromhome charging infrastructure passed a major test when an estimated 50% of Norway’s EV owners said they would holiday at home using their EV, a higher proportion than usual because of covid-induced foreign travel restrictions. Some charging stations had queues, but few people ran out of a charge on the open road. • 51

TRANSPORT

BUSINESS MODELS FOR CHARGING uch is the prevalence of chargers in public locations that providers are failing to profit from them, including in countries where electric vehicles make up a high proportion of new car sales By 2028 as much as $55.7 billion in cumulative global investment over a decade will be needed to install 48.4 million socalled Level 2 residential chargers, 4.9 million Level 2 public chargers and 560,000 fast public chargers reliant on a direct current cable, Northeast Group, a Washington-based research firm, estimated in 2018. Level 2 chargers are 240 volts and take several hours to fully charge a vehicle from scratch.

How to make public charging profitable is taxing many early movers in the field. The sector is so far mostly investor-based, with a high prevalence of equity and venture-capital funding for start-ups. In some cases, big players have moved in and bought start-ups. In 2019, a subsidiary of energy firm Royal Dutch Shell bought Los Angeles-based firm Greenlots, which offers software and services for EV infrastructure.

According to research released in November 2020 by EY, a global provider of business advisory services, reaching break-even may typically take five years for a public charging point, while positive returns may not come until year ten.

EY identified four revenue and two cost levers to boost profitability. Financially rewarding flexible charging at times that keep costs low for the electricity supplier can add 8% to the return. Advertising, such as on a charging pole, may add 7%.

As a cost lever, allowing different companies to invest in sub-components of the operation, such as having fractional ownership, may add 5%. And having neutral hosts, such as the owner of land where the charger is located, sharing revenues, can add 12%. Together these six levers could bring positive cash flow as early as year two, with a 5-25% increase in returns, says EY’s Thierry Mortier.

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The carbon content of electricity used for electrolysis has a strong bearing on the carbon emissions associated with the resulting hydrogen An indication of market optimism came when US company ChargePoint in September 2020 announced it will go public via a special-purpose acquisition company, Switchback Energy Acquisition Corporation, with a $2.4 billion market valuation. ChargePoint is involved in the largest online network of independently owned EV charging stations and operates in 14 countries selling hardware and maintenance and supporting software to site hosts. It does not front capital for the installation site or profit from electricity sold.

The model has been most successful with slower charging, which is cheaper, says BloombergNEF’s Fisher. Competitors in its home market, EVgo, Electrify FORESIGHT

America and Tesla, are scouting the best locations and are, in contrast, fronting capital for faster charging, he says.

Electrify America, part of the Volkswagen Group in America, has one of the largest fast charging networks. It is in the early stages of investing more than $2 billion over a decade in zero-emission vehicle infrastructure, access and education in the US. The company was established as part of the settlement after VW’s Dieselgate emissions scandal in 2015. DC chargers convert AC power from the grid to DC, then deliver the DC power directly to the battery more quickly than AC charging.

Another model at an “early but promising” stage in China and, to a lesser degree, in India are large fast-charging hubs of roughly 100 public chargers with a high voltage DC connection to the grid and built in coordination with a large deployment of vehicles, notes Clay Stranger with the Rocky Mountain Institute, an energy transition think tank. RMI has found generally that a fast charger needs to be used 20% of the time to be commercially viable and that such hubs can see a 7080% use. Public transport can connect the hubs with work sites such as major IT campuses. In India ride-sharing companies Ola and Uber are also partnering in them. •

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TRANSPORT Hydrogen suffers from an abundance of hype, particularly about what it can be used for in the energy transition. Wild claims for the application of hydrogen, with little basis in current science and commercial reality, have worked to obscure the realistic opportunities for putting truly clean hydrogen to work here and now. Beneath the noise, however, hydrogen trains have been catching on. They will only be as clean as the process used to produce the hydrogen, but renewable energy is standing by, ready and willing

H

ydrogen, a clean fuel at its point of use, has for many decades held tantalising promise for the decarbonisation of energy. But hydrogen does not occur naturally in its own right. It has to be produced from another state and is only as clean as the method used for that process. The financial and technical challenges of producing truly clean hydrogen, which can be done using electricity from a renewable source of energy, have until recently kept its promise out of reach. That is now changing.

Of all the much vaunted claims for the application of electrolytic hydrogen in the energy transition, two are now bearing up under close examination thanks to technology advances. The first is replacement of the vast quantities of “dirty hydrogen” used in petroleum refinement, metal treatment and fertiliser production, plus the potential replacement of fossil fuels used in industrial processes requiring extremely high temperatures. The second is to provide motive power for heavy commercial transport. The growing number of hydrogen powered trains in commercial use suggests they currently tick more boxes than hydrogen powered trucks employed in long distance road haulage.

Hydrogen trains have a bright future. They are already running in Britain and Germany and there are plans for more in Japan, Italy and elsewhere. Al-

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though railway electrification is the preferred option on a route to zero carbon, it is expensive. Case studies for Norway, the Netherlands, Britain and elsewhere suggest hydrogen can be an economic option. Battery powered trains are also being considered, but they tend to be outbid by hydrogen.

The environmental advantages of rail over road transport are clear. “High capacity urban rail requires, on average, less than a tenth of the energy needed per kilometre travelled compared with passenger cars,” states a joint International Energy Agency/International Union of Railways Report.

Work is underway to reduce the carbon footprint of all forms of transport, but the potential for trains to be zero carbon perhaps holds out most promise. The railways of Switzerland are almost zero carbon as the rail system is 100% electrified with around 98% of the electricity coming from carbon-free sources, hydro and nuclear.

Power systems the world over are aiming to reduce the carbon content of their electricity and railway owners are raising their electrification ambitions. Rail electrification, however, is costly and it may be difficult to justify the expense of installing the required infrastructure for lightly-used lines. Alternatives to electrification are flywheels, batteries and hydrogen fuel cells. The first option is only suitable for short FORESIGHT

Expert author David Milborrow is an energy consultant with an extra curricular interest in trains.

Taking advantage of this fortuitous mix of expertise, FORESIGHT asked him to take a deep dive into hydrogen powered trains and assess their commercial potential

TEXT David Milborrow PHOTO Johannes Hofmann

Why hydrogen trains are tracking hot

FORESIGHT

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ELECTRIFICATION

100

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was a drawback, but the latest designs have provision for connecting to a medium (750 V) or high voltage (11 kV or above) power supply which enables faster charging. The principal advantage of trains running on battery power over electric or hydrogen trains is that they are cheaper.

When compared with batteries, hydrogen delivers a better range, lighter trains and takes up less volume on board. The weight of a battery powered train does not change during its journey, but the weight of a hydrogen powered train reduces, albeit slightly, as the journey progresses and the hydrogen store is depleted.

The economic advantages, but limited range, of battery electric trains means they are likely to be deployed mainly on branch lines, typically up to 100 kilometres in length, that are relatively lightly loaded.

Hydrogen fuel cell trains are more versatile and in the

DENMARK

UK

GERMANY

FRANCE

INDIA

ITALY

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Percentage of route miles electrified

SWEDEN

BATTERY OR HYDROGEN Battery powered trains have been around for some time and have operated in Germany, New Zealand, Ireland and the UK. Their limitations were (and still are) their limited range and their extra weight. Until recently, the time needed to charge the batteries

Electrification of railway route miles in selected countries

SWITZERLAND

Direct rail electrification is a preferred option as railways move towards low carbon operations. The scope for electrification is considerable. Only about a quarter of the world’s railways are electrified (chart).

The problem with electrification is its cost. The required catenary high-voltage cable infrastructure typically costs around €5 million per kilometre of double track railway fully installed; some estimates are twice that, some less. Electrification of a single-track railway would cost less, but single track lines invariably carry less traffic, making the economic case more difficult to justify.

In a theoretical example of the economic challenge of rail electrification, a 100 kilometre route would cost around €500 million to electrify and annual repayments to cover this sum would be about €40 million, perhaps less if the project was funded by a public sector utility prepared to accept a lower return. If the line was lightly used and carried 20 trains a day (ten in each direction), each train would need to pay a fee of around €5500 solely to repay the investment. If the trains were full, that might translate to an acceptable premium per passenger, but not if they were lightly loaded. The picture changes if the line is busier, with 120 trains bringing the premium down to about €920 a train.

A lower cost electrification approach uses conductor rails adjacent to the running rails, but these have a number of limitations, including the issue of safety, and are only considered suitable for urban transport systems. High voltage systems, with the power delivered by overhead cables, is now the preferred option, worldwide, for all mainline railway systems.

It is against this backdrop that numerous studies have been carried out recently to examine the viability of other potentially zero carbon propulsion modes.

So far, so good

SOURCE Eurostat and national sources

journeys, but the concept is proven and a prototype has been operating successfully for several years in the UK. The caveat is that the electricity source responsible for energising the flywheel should be carbon-free. The same caveat applies to the electricity used to generate hydrogen or to charge batteries, otherwise the transport is not carbon-free. Trains running on hydrogen appear to be an attractive option for several types of service and development of both battery and hydrogen trains is proceeding rapidly.

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Dirty and clean train economics Cost of propulsion options, different distances and trains

Total cost, €/train-km

27.5

21.2 18.5

22.6 19.9

12.4

13.7

9.3

SOURCE: FCJU

4.8 5.0 4.5 5.3

FRANCE

Diesel

SPAIN

Hydrogen

NETHERLANDS

Electric

Battery

UK a mixture of the two has been identified as the best option by Network Rail, the track operator. In a report from September 2020, Traction Decarbonisation Network Strategy, the track operator identifies potential for another 11,700 track miles to be electrified directly, 900 track miles to be used by hydrogen powered trains and 400 track miles to be used by battery-driven trains. A further 400 track miles could possibly be used by hydrogen trains in cases where the economic preferences were less clear-cut.

A “track mile” refers to the total length of the track, meaning that a ten kilometre double track section would have a track mileage of 20 kilometres.

Since the maximum range of battery powered trains is generally a little over 100 kilometres, it is unsurprising that a major 2019 study by the Hydrogen and Fuel Cells Joint Undertaking (FCJU) in Brussels, FORESIGHT

Study of the Use of Fuel Cells and Hydrogen in the Railways Environment, concluded: “Fuel cell hydrogen trains make economic sense above all when they are used on longer and non-electrified routes of over 100 kilometres.”

The principal disadvantages of hydrogen are its high fuel cost, the need to set up infrastructure to deliver the gas, and issues of safety raised by its volatility. Economic appraisals that include all the relevant costs associated with the fuel and its delivery can reveal when and if hydrogen trains can be competitive with other options, but the cost of gas explosions causing large scale damage to property and multiple injuries to people is harder to quantify.

The FCJU calculated the total costs of operating a number of routes and looked at both multiple unit trains (power unit and fuel on board the coaches) and the use of locomotive-hauled trains for longer routes.

The comparative cost of the different propulsion technologies in three countries on the European continent was influenced by the length of the route and the cost of electricity in each country. The routes examined were the Montrejeau-Luchon 140 kilometre line in France, already partially electrified, a 165 kilometre stretch running from Aragon in Spain to across the border into France and a 300 kilometre line linking Groningen and Friesland in the Netherlands.

While diesel trains were cheapest in all three countries, hydrogen trains were the next cheapest in the Netherlands and Spain, but not in France where they were beaten by battery trains. Electrification was the most costly option in France and Spain, but on the longer Dutch route was cheaper than batteries (chart left).

The French and Spanish routes are lightly used, but the Dutch route has a more intensive service (mostly hourly) and so it is perhaps not surprising that electrification emerges as the cheapest option, about 10% cheaper than using hydrogen trains. The Spanish route favours fuel cell trains at just over half the cost of electric trains. On the lightly-used French route, battery emerges as the cheapest option—about 10% cheaper than the hydrogen alternative.

The FCJU study also looked at the prospects for locomotive-hauled trains on longer routes in Estonia, Germany and Sweden. Route lengths varied between 210 and 720 kilometres. In each case diesel traction remained the cheapest option, but hydrogen was slightly cheaper than electrification for cross-border traffic between Russia and Estonia and it was significantly cheaper in the Swedish case (Kalmar-Linkoping).

Another study, the Techno-Economic Analysis of Freight Railway Electrification by Overhead Line, Hydrogen and Batteries, from 2020, examined the case for hydrogen trains for freight on two lines, one in Norway, the other in the United States. The Nordland 57

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line in Norway is 731 kilometre long and runs from Trondheim to Bodø in the far north with about 300 train movements. The US route, a 2883 kilometre stretch from Kansas City to Los Angeles, has about four times that number. The study concluded that fuel cell trains delivered the cheapest option on the Norwegian line, but not on the American line, where electrification came out as the cheaper option. The result again indicates that electrification demands a high intensity of services to enable the initial capital outlay to be recouped when spread over a large number of train movements. Even if the electricity used to charge batteries or generate hydrogen is not carbon-free, trains adopting either propulsion method are quieter than diesel trains and produce no harmful emissions along their routes.

ON THE MARKET TODAY The world’s first hydrogen-powered trains entered service in Germany in September 2018, with two pre-production two-car units, which have been operating in the north of the country on a route between Cuxhaven and Buxtehude ever since. The train is based on a design of diesel multiple unit that has been operating for several years. It has been re-engineered to accommodate the components necessary for it to run on hydrogen. The Coadia “iLint” has a 200 kW fuel cell and a 225 kW lithium-ion battery that stores surplus fuel cell energy and absorbs regenerative energy when braking. Roof tanks store 99 kilograms of hydrogen at a pressure of 350 bar. Alstom, the train manufacturer, claims the hydrogen train has a similar weight to the diesel version. The hydrogen consump58

tion, at around 0.2 kg/km, is slightly less than that assumed in the FCJU study. The maximum speed is 140 km/h and the range is 600 kilometres.

Several regional rail operators in Germany have placed orders for the trains following the successful operation of the prototypes and the Dutch rail operator supervised an intensive test programme in spring 2020. The transport authority for the Frankfurt region has ordered 27 trains for delivery in 2022 and construction of a refuelling facility started in October 2020. A trial began in Austria in September 2020 that could lead to an order for further trains.

In Britain, the first mainline hydrogen train, Hydroflex, made its first demonstration trips between Long Marston and Evesham in central England in late September 2020. The venture belongs to rolling stock operator Porterbrook in conjunction with Birmingham university. The train has been converted from a four-car electric multiple unit. In a sign of developing competition in the market, Alstom has also announced its intention to convert another electric multiple unit for hydrogen operation.

Other manufacturers are also developing fuel cell trains and Swiss rolling stock manufacturer Stadler Rail will supply a Flirt train to the US in 2024 for operation in San Bernardino County, California. Further activity is reported in Japan and China.

TRUCKS, SHIPS AND PLANES Hydrogen fuel cells can also be used to propel ships, trucks and even aeroplanes with demonstrations of how to go about it at various stages. British company ZeroAvia claimed it completed the world’s first hyFORESIGHT

Green skies ZeroAvia says it completed the world’s first hydrogen fuel-cellpowered flight in September 2020

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drogen fuel-cell-powered flight of a commercial grade aircraft in September 2020. The six-seater plane used for the flight is for the time being the largest hydrogen-powered aircraft in the world, says ZeroAvia. It completed a circuit around the aerodrome at Cranfield in England, where the company is based. The next step is a 400 kilometre flight to the island of Orkney off northern Scotland.

Anglo-French company Airbus is a hydrogen flight believer. “Hydrogen is one of the most promising zero-emission technologies to reduce aviation’s climate impact. This is why we consider hydrogen to be an important technology pathway to achieve our ambition of bringing a zero-emission commercial aircraft to market by 2035,” states the company.

The shipping industry lays claim to another “world first” for hydrogen in the shape of a ferry set to undergo testing at the European Marine Energy Centre in Scotland’s Orkney Islands. Initially, the ferry’s hydrogen fuel cells will power its auxiliary engines, but the aim is for it to run solely on hydrogen.

The project has a strong claim to being truly green as its hydrogen is derived through electrolysis reliant on electricity supplied from a tidal power installation.

Fuel cell buses have been operating on the streets of London and other major cities for several years.

Fuel cell cars are available, but they are expensive and unlikely to make much of an impact in the short to medium term. Among truck manufacturers, several big names are promoting fuel cell powered heavy commercial vehicles. A hydrogen powered commercial truck built by Hyundai started hauling groceries in Switzerland in April 2020, the first of 1600 fuel cell electric trucks that the manufacturer plans to commission by 2025. Switzerland levies a tariff on heavy vehicles that corresponds to around €0.8/km. Green vehicles are exempt. As Switzerland’s electricity is 98% carbon free, its hydrogen trucks will have impeccable green credentials.

LAST WORD Most hydrogen today, however, is derived from non-renewable sources and even electrolytic hydrogen is reliant on electricity from grids that are still at least partially dependent on fossil fuel. Given that the production of hydrogen from renewables will always cost more than the renewables electricity used in the electrolysis process, clean hydrogen will always be more expensive than clean electricity. As a result, truly carbon-free hydrogen, produced from renewable energy-powered electrolysis, is unlikely to contribute in any significant way to reducing emissions for many years yet. If it becomes a mainstream carrier alongside electricity, it could be the railways that spearheaded the hydrogen revolution • FORESIGHT

THE TROUBLE WITH HYDROGEN Hydrogen is only as clean as the method used for separating it out of its natural state, whether by exposing fossil fuels to steam or subjecting water to an electric charge. Electrolytic hydrogen from water is emissions free when the electricity used for the process is supplied from a renewable source of energy, but that is rarely the case. Nearly all grid electricity around the world is a major source of CO2 emissions. The carbon content of electricity used for electrolysis has a strong bearing on the carbon emissions associated with the resulting hydrogen.

In countries reliant on coal fired power stations, grid electricity is far from clean.

South Africa, Australia, Poland and India all deliver electricity with a carbon content in excess of 700 grams of CO2 per kilowatt hour.

The efficiency of electrolysis is about 70%, meaning that 30% of the energy that goes into the process is wasted. Fuel cell efficiency is similar. As a result, the carbon content of the electricity delivered by fuel cells to a train’s traction motors is roughly double that of the input grid electricity.

By comparing the emissions from diesel trains with the "full cycle" emissions from hydrogen trains, it is apparent that the grid carbon intensity needs to be less than about 600 grams of CO2 per kWh if CO2 is to be saved by using hydrogen instead of diesel. The more a grid is fed from renewable sources of energy, the lower its carbon density. Iceland, Denmark, Norway, Sweden, Switzerland and the UK are countries with a grid carbon content below the 600g/ kWh threshold, which would make hydrogen trains cleaner than their diesel counterparts.

In locations where the grid electricity carbon content comes above this threshold, hydrogen trains still offer quiet travel with no local carbon emissions, but will not reduce overall emissions unless the hydrogen comes from a dedicated renewable energy source.

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No more than 250 MW of electrolysers are in operation worldwide.

That leaves a lot to be done

The economics of hydrogen production will benefit from increasing the scale of operations, partly from “learning by doing” and partly from the use of larger sizes of electrolyser. Compressors will also be needed to compress the hydrogen, either into storage tanks or into smaller vessels suitable for transportation, all of which are standard equipment in the large grey hydrogen market.

In Germany, two refuelling stations are already under construction for its hydrogen trains, with operator Linde claiming its station will have a capacity of around 1600 kg of hydrogen a day. That is sufficient for around 5000 kilometres of train operations.

HYDROGEN SUPPLY LOGISTICS

T

wo logistical challenges must be overcome for widespread use of hydrogen fuel cell trains: organising a hydrogen supply and building filling stations. Sufficient hydrogen needs to be produced using electrolysis and for carbon-free railway operations, the electricity for that process has to come from a renewable energy source.

No more than 250 MW of electrolysers are in operation worldwide. That leaves a lot to be done. Germany aims to commission up to 5000 MW of electrolysis capacity within the next five years, assuming the endorsement of its hydrogen strategy proposed in late 2020. The EU envisages installing at least 6 GW of renewables hydrogen electrolysers in the EU by 2024 60

and 40 GW by 2030, as outlined in its hydrogen strategy released in July 2020. The strategy proposed a competition to build a 100 MW electrolyser, much bigger than anything already operating.

Denmark’s Ørsted, an offshore wind farm developer, is involved in the early stages of four green hydrogen projects, in Germany (50 MW), Britain (5 MW), the Netherlands (5 MW) and Denmark (2 MW), powered by wind farms in the North Sea dedicated to industrial scale electrolysis. The demonstration projects are slated for growth to commercial scale, with the most ambitious plan being a 1.3 GW facility in Denmark in 2030. The German proposal, with BP, is to supply BP’s refinery at Lingen, with the first phase producing nearly 9000 tonnes of hydrogen, a fifth of the refinery’s demand. Ørsted sees substitution of grey hydrogen as the main market for green hydrogen production.

FORESIGHT

STORAGE AND HANDLING

The hydrogen used in Alstom’s trains in Germany is compressed to 350 bar.

That is slightly higher than the pressure in most oxygen cylinders and as a result will need careful handling, especially as the gas is highly inflammable. One or two explosions in connection with filling stations have occurred, but the United States Department of Energy argues that hydrogen is no more or less dangerous than many other flammable liquids and gases. If it does leak, it diffuses quickly, with little time for the right hydrogen/oxygen ratio to cause an explosion.

The fuel tanks for Alstom’s trains fit comfortably on the roof. The British train’s tanks occupy space in one of the coaches, but they need more room as the pressure is less. The owners have stated their intention to accommodate the tanks underneath the coach and will probably use a higher pressure. •

HyNetherlands a green hydrogen value chain

The ENGIE HyNetherlands project consists of building a first of a kind hydrogen value chain partnership to serve a series of off-takers in a favourable context serving the Dutch government’s ambition to reach carbon neutrality.

HyNetherlands is based on a stepwise approach with progressive commitments starting with a 100 MW electrolysis in 2024, and increasing to the Gigawatt scale before 2030.

Green hydrogen, which is mainly produced by water electrolysis using renewable electricity, is one of the levers that will speed up the transition to a carbon neutral future: development of green mobility, decarbonisation of large-scale industrial uses of hydrogen (fertilisers, refineries, chemicals, etc.), improved inteÂŹgration of intermittent renewable energies into the energy system, and massive storage of the surplus electricity generated.

The HyNetherlands project combines large-scale production, transport, storage and application of green hydrogen. Located in The Northern Netherlands, surrounded by green electricity, a good and extensive existing gas network, gas storage options and the presence of large industrial users of hydrogen, it is perfectly located for large-scale green hydrogen.

The HyNetherlands project is in line with the ambition of the Northern Netherlands to develop a regional hydrogen economy and become a leader in Europe.

www.engie.nl

CEMENT & STEEL

Cement and steel manufacturing are two of the most carbon intensive industries in the world. Electrification can play a role in decarbonising both, though technology innovation is expensive and removing all emissions from the processes is a tall order.

Given the accelerating problems of global warming, serious government help is essential to achieve at least partial electrification in the necessary timeframe

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TEXT Catherine Early PHOTO Ricardo Gomez

Heavy industry to carbon light

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he processes involved in manufacturing cement and steel, used in buildings, vehicles and infrastructure around the globe, are among the industrial activities that cause most climate change. Cement is responsible for 8% and steel 7% of the world’s carbon emissions. Both sectors are working on ways to reduce their reliance on fossil fuels, driven by government policies and public pressure to re-establish the earth’s carbon balance, known as achieving net-zero, climate neutrality or being carbon neutral.

The challenge the cement and steel industries face is enormous. To stay in business as well as go carbon light they must protect current investments in production facilities that have long operational lives. At the same time they must invest in making those facilities obsolete as fast as possible. Massive government subsidies to assist both sectors would appear to be unavoidable. Knowing what to support and what not to support is likely to depend on which technologies gain market backing and which do not. The industry is working on a range of options, including direct and indirect electrification of processes that not long ago were seen as impossible to electrify, both physically and economically.

“Industrial plants have a service life of up to 70 years, which means that investments in purely conventional plants are already no longer compatible with the long term goal of climate neutrality. In order to avoid stranded assets, decisions must be made in favour of climate neutral innovation from now on,” says Frank Peter, at AgoraEnergiewende, a German green policy institute.

The steel and cement industries will only achieve the required emission savings over the next decade by adopting climate neutral key technologies. Without their participation the EU’s more ambitious climate target of at least 55% lower emissions by 2030 will be hard to reach, Agora Energiwende notes in a November 2020 report.

CEMENT TRIALS In cement making, around 60% of carbon dioxide emissions are released during the process of limestone calcination. Since the carbon is produced as a by-product of a chemical reaction, it cannot be reduced by changing fuels or increasing manufacturing plant efficiency. Either new processes have to be found for greener cement or the carbon emitted has to be captured and put to another use or stored (CCUS). Pilot CCUS projects are underway at cement plants in the US and China, with others planned in Norway, Canada and India, reported the International Energy Agency (IEA) in 2020.

First, the cement industry must make sure the electricity it uses comes from a renewable energy FORESIGHT

source, the IEA points out. Swiss cement company LafargeHolcim announced in October 2020 the opening of a solar energy facility alongside its cement factory in Maryland, United States. At 10 MW the solar plant is expected to power around 25% of the factory’s annual electricity requirements, the company says. The target for 2030 is to reduce indirect emissions from the generation of electricity used to power its equipment to 13 kilograms of CO2 for each tonne of cement produced, a 65% reduction compared with 2018.

LafargeHolcim already uses a 15 MW solar plant to supply 30% of the electricity used at its factory in Jordan and in Argentina it buys 30% of its electricity through a wind power purchase agreement. Over the next five years, it hopes to install enough renewable energy capacity to cover the electricity used by all its plants and contribute to powering surrounding communities.

None of these efforts, however, puts the smallest dent in the carbon emissions from operation of LafargeHolcim’s kilns. Cement kilns need to be kept at a constant temperature of 1300-1400 degrees Celsius, making supply from variable sources such as wind and solar unrealistic, explains Thomas Schulz, who heads FLSmidth, a large Danish engineering firm. “The damage to the plant’s firing system can be traumatic if the energy goes away—not only the quality of what you produce, but if the temperature is reduced, you can damage the shell and liner of the kiln,” he says.

Yet, from the World Cement Association, Ian Riley sees no major role for electricity in the sector’s decarbonised future. Using electricity for kilns would require a huge investment to retrofit the equipment, he says. In any case, the cement industry is providing a useful secondary service by burning waste that is otherwise difficult to dispose of, such as paints and oils, he adds. “I’m not convinced electrification will make sense from an economic point of view, but also not from an environmental and circular economy perspective. If I think about things I would do to decarbonise the cement industry, electrification would be pretty much the last one,” he says, pointing to changes in the composition of clinker and efficiency gains.

KILN ELECTRIFICATION Nevertheless, research on kiln electrification is underway, though at an early stage, according to European industry body Cembureau’s 2050 roadmap.

Using electrical heating, plasma or solar energy to calcinate the raw materials could result in fuel-related CO2 savings of up to 55% if renewables electricity is used, it states. Emissions can also be avoided by combusting green hydrogen, produced using renewable energy, and biomass fuels, instead of using fossil fuels to create the extreme temperatures needed in the clinker process. Combined, the adoption of these 63

CEMENT & STEEL

technologies could enable the cement industry to achieve near zero emissions. Remaining emissions from the calcination process would need to be captured. LafargeHolcim says it is piloting more than 20 CCUS projects in Europe and North America.

In Sweden a joint effort by cement producer Cementa, a subsidiary of Germany’s HeidelbergCement, with energy company Vattenfall to electrify cement production is part of a project known as CEMZero.

A feasibility study, completed in early 2019, showed that electrified cement production is technically possible and likely cost-competitive with other options to substantially reduce emissions. The partnership is constructing a pilot plant.

STEEL EFFORTS As a carbon sinner, steel is even worse than cement.

Steel production ranks first among heavy industries for CO2 emissions and second for energy consumption, according to the IEA. It is the largest industrial consumer of coal, which provides around 75% of its energy demand. Coal is used to generate heat and to make coke, instrumental in the chemical reactions necessary to produce steel from iron ore.

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Steel is already heavily recycled and energy efficiency gains at plants will not achieve sufficiently deep emissions reductions, the IEA says. The main routes to decarbonising the sector are: attaching CCUS to blast furnace operation; replacing coal with green hydrogen to reduce iron ore into steel, known as direct reduced iron or DRI; and direct electrification, where an electric arc furnace can become hot enough to melt scrap steel for reuse.

Electric arc furnaces have been in use for over 100 years to produce new steel from recycled scrap. As grid electricity is increasingly decarbonised, so is the operation of electrically driven furnaces. Their emissions can be further cut by replacing natural gas used to heat them with a lower carbon heat source, such as green hydrogen biofuel. The economics of meeting demand for steel by recycling more of it, however, depend heavily on the price of electricity, which is mainly a function of government policy and how the costs of not only generation but power system operation are allocated. In the UK, electricity costs are high— over 60% higher than in Germany—which is a major barrier to electrification, points out Frank Aaskov, energy and climate change policy manager at UK Steel.

FORESIGHT

Grey to green Electrical processes in concrete production can help to reduce the sector's emissions

CEMENT & STEEL

Using renewables electricity to make carbon-free hydrogen through electrolysis is an expensive process compared with the gasification of coal or steam-methane reforming from natural gas. Replacing the use of natural gas with green hydrogen still costs about four times more for a less efficient fuel use. Cost remains a significant barrier. “That impacts the possibility of being able to sell you steel so that’s a big barrier to hydrogen taking off at the moment,” says Aaskov.

As demand for green hydrogen increases, however, economies of scale are projected to cut in and significantly reduce its production costs through cheaper electrolysers and cheaper renewable energy.

Energy efficiency gains at steel plants will not achieve sufficiently deep emissions reductions

Analysis from BloombergNEF, the new energy finance and research arm of news group Bloomberg, found that hydrogen produced from renewables electricity could be cost competitive with coal for steel making by 2050, if a carbon price of $50/tCO2 was applied to coking coal. Production of enough green hydrogen to make a significant dent in steel emissions, however, requires a vast increase in the development of renewable energy generation, which is also needed to decarbonise the grid. Energy analyst Chris Goodall estimated in November 2020 that if the entire steel industry was to convert to hydrogen by 2050, the world would need about 1600-1650 GW of extra wind turbines—more than two-and-a-half times the current installed capacity of wind power globally.

HYDROGEN CASE STUDIES Despite these challenges, several steelmakers are forging ahead with research and development projects that use hydrogen. In October 2020, ArcelorMittal announced it would be offering its first 30,000 tonnes of “green steel” to customers before the year was out, scaling up to 600,000 tonnes by 2022. Hydrogen in both its blast furnace and DRI will help advance its strategy to cut emissions by 30% by 2030, it says. It is developing facilities to produce the hydrogen using electrolysers, which will undergo largescale tests at its site in Bremen, Germany. Another plant in Dunkirk, France, is to install a large scale DRI plant, combined with an electric arc furnace. The DRI FORESIGHT

plant will initially use natural gas but will be able to convert to green hydrogen in the blast furnace when enough of it becomes available.

In Sweden, steelmaker SSAB, mining company LKAB and Vattenfall have a joint project, called Hybrit, to produce fossil-free steel using hydrogen DRI technology. A pilot plant in Luleå began operation in August 2020 and will test the production of hydrogen at the plant by electrolysing water with fossil-free electricity. The partnership is now working on scaling up the tests to an industrial scale demonstration plant, which it hopes will be operational by 2025.

Meanwhile, in Germany, the country’s second largest steelmaker, Salzgitter, wants to replace the fossil fuels it uses with a gradually rising share of renewables hydrogen. It already uses an electrolyser at its plant for the steel finishing process, soon to be powered with electricity from newly built wind turbines on site. Initially DRI will use natural gas before shifting to wind power. Salzgitter also plans to use electric arc furnaces, but is waiting for both financial support for the initial investment and a change in market regulations to allow for the sale of low carbon steel, its technology boss, Volker Hille, told German news source Clean Energy Wire last year. The firm also applied for funding from the European Investment Fund in October 2020.

Other projects are similarly dependent on public funding. ArcelorMittal is seeking money from the European Union’s Innovation Fund which is designed to support low carbon investments. Sweden’s Hybrit project is being supported by the Swedish Energy Agency, which provided €57 million out of the total €200 million for the initial phase. In October 2020 the project secured a further €2 million to fund a feasibility study for its next stage.

Aaskov says the UK steel industry needs a level playing field to boost the viability of decarbonisation.

The EU has its Emissions Trading System and the UK is considering setting one up following its departure from the EU. “That’s unlikely to happen at a global level, so we need to look at compensation to make up for that, such as lowering the cost of industrial energy, direct capital support for industry, or in the longer term, product standards or a carbon border tax,” he says.

Steel producing countries around the world are undoubtedly considering the same problem and weighing up a similar range of options in the absence of a globally agreed approach to putting the world on track for fast decarbonisation. If two countries both have steel and cement industries, but only one prices carbon or has climate change policies for its industry, then it will be outcompeted unless mitigating policies are introduced, says Aaskov. • 65

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