10 minute read 13 Jan 2020
carbon-footprint

How net-zero emissions present the power sector with an opportunity

By

Benoit Laclau

EY Global Energy Leader

Experienced energy leader and advisor.

Contributors
10 minute read 13 Jan 2020

Meeting mid-century climate targets poses enormous challenges that touch on every part of the modern economy.

But decarbonisation also offers a transformative opportunity for the power and utilities sector as the challenge drives convergence across power, heat and transport.

Climate policy is beginning to catch up with climate science. Last year, the Intergovernmental Panel on Climate Change – set up by governments to help them understand the underlying science explaining climate change – warned that global emissions need to reach net-zero by mid-century if we are to have a reasonable chance of keeping warming below the Paris Agreement’s goal of 1.5°C above pre-industrial levels. Current policies in place around the world would result in around 3.2°C of warming.

Roughly a year later, at the UN Secretary-General’s Climate Action Summit in New York in September, Antonio Guterres announced that 77 countries had committed to net-zero carbon emissions by 2050. Some, such as the UK, France, Sweden and Norway, have introduced legislation to that effect. For others, the goal is currently aspirational.

“Setting targets can be unhelpful. If they are insufficiently tangible,” says Joseph Dutton, a policy advisor at E3G, a UK-based climate change thinktank, but “net-zero policies can be helpful to give a point of focus for policymakers and industry. But, once net-zero commitments are made, governments need to set out short- and medium-term plans for each sector to ensure they are on the right trajectory.”

Decarbonisation will require profound change in almost every part of the economy – and the power and utilities sector will play a central role in most (if not all) of these efforts.

The electrification of the economy will create new demand for power companies, which will increasingly be met by zero-carbon renewable sources. Norwegian power company Statkraft1 estimates that electricity demand will double by 2050 , with its share of final energy use multiplying by 20 times in transport, 66% in buildings, and 40% in industry.

According to Eurelectric’s Decarbonisation Pathways report (pdf)2, under a scenario whereby the EU achieved 95% emissions reductions by 2050, electricity demand would be more than double 2015 levels, at 6,000TWh/year.

Indeed, the power sector has played the leading role in the first phase of the low-carbon transition, with most the emissions reductions achieved to date delivered by utilities switching from coal- to gas-fired generation, and by massive investment in renewable energy capacity.

But this process has only just begun. Deployment of key technologies, such as distributed energy resources, electric vehicles, demand response and energy storage systems, will only accelerate. Below, we consider the opportunities and challenges facing the power and utilities sector from four major parts of the decarbonisation jigsaw: electrifying transport; low-carbon heating and cooling; a clean hydrogen economy; and a smart transmission and distribution network.

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Chapter 1

Electrifying transportation

The transport sector is responsible for 27% of emissions in the EU, and 29% in the US.

While the uptake of electric vehicles is accelerating, the vehicle fleet will need to become entirely decarbonised to meet net-zero commitments.

The opportunity 

EY teams' study of 29 EV value pools, which aimed to identify the eight most attractive opportunities for utilities, found that the most important is electricity retail – the sale of electricity for EV charging, including electricity retail to commercial charging spaces, battery swapping stations and residential charge points.

The electrification of transport represents an enormous new source of power demand. According to International Energy Agency (IEA)3 data, electricity demand to serve EVs globally is projected to reach almost 640 terawatt-hours (TWh) in 2030 in its central New Policies Scenario, and 1,110TWh in its more aggressive EV30@30 Scenario, which assumes 30% market share for EVs by 2030. The latter is more than three times the total UK electricity consumption in 2018.

EY commissioned a study of 29 EV value pools to identify the eight most attractive opportunities for utilities. It found that the most important is electricity retail – the sale of electricity for EV charging, including electricity retail to commercial charging spaces, battery swapping stations and residential charge points.

The second biggest value pool is public charging stations – turnkey solutions for installation of public EV charging stations, including site evaluation and selection of chargers as well as the operation and maintenance of charging station networks.

Electric vehicles – more specifically the batteries in them – also offer a partial solution to the problems caused by the supply of power from intermittent renewables. Smart grid infrastructure and dynamic time-of-use charging could help soak up surplus supply from renewables, and shave demand from peaks in consumption. In future, as vehicle-to-grid (V2G) capability comes on line, millions of stationary EVs could be linked together to form a giant virtual power plant to meet peaks in demand, such as on a windless winter evening.

Developing EV infrastructure also provides direct opportunities for utilities. For example, SSE Enterprise, an arm of UK utility SSE, provides a range of solutions to support the electrification of vehicle fleets across the private and public sectors.

“We construct, own, operate, maintain and optimise localised energy infrastructure to support EVs,” says Kevin Welstead, Sector Director Electric Vehicles, SSE Enterprise.

The challenge

The biggest challenge is ensuring that infrastructure can meet anticipated power demand, likely to be concentrated at certain parts of the day, such as during existing evening peaks, when commuters arrive home.

“It’s an open question – will demand from the transport sector exacerbate current demand peaks? We can’t possibly afford to build out capacity to meet maximum possible demand,” says Maria Bengtsson, Director, Transaction Advisory Services, Ernst & Young LLP.

There has also been limited progress in deploying the V2G technology that will allow grid operators to use electric vehicle batteries as a giant distributed source of power supply.

Paying for EV infrastructure also creates equity challenges, particularly during the early phase of the EV uptake. Should the investments needed by utilities and grid operators be shared among all electricity users – as they typically are now – or should those who benefit, the affluent early adopters, shoulder most of the cost?

It’s an open question – will demand from the transport sector exacerbate current demand peaks? We can’t afford to build out capacity to meet maximum possible demand.
Maria Bengtsson,
Director, Transaction Advisory Services, Ernst & Young LLP

What needs to happen

Electric cars are expected to become cheaper than their combustion engine equivalents by 2022, according to Bloomberg New Energy Finance.4 However, government incentives to reduce their cost can speed penetration: in Norway, which offers attractive tax breaks and road-toll discounts, nearly half of new cars sold in the country in the first six months of 2019 were electric.

Meanwhile, governments need to act to coordinate the rollout of an EV charging infrastructure, says SSE’s Welstead, who notes that the involvement of different layers of government can complicate planning and regulatory approvals.

As electric vehicle penetration increases, there will need to be an education process to change behaviours and mindsets, says Bengtsson, to make car owners comfortable with a third-party drawing power from their battery. “It’s putting control into someone else’s hands – there needs to be a clear commercial case,” she says.

More immediately, she adds that there is an urgent need to develop the technological tools, regulatory frameworks and business models to enable V2G power supply, and many chargers currently being installed do not enable the two-way flow of power.

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Chapter 2

Heating and cooling

Buildings currently account for around 30% of global final energy consumption, according to the IEA.

More than half of building's energy is supplied by natural gas, coal or biomass. Electricity supplies about a quarter of the energy used in residential buildings5. Current heating demand patterns, in particular, are characterised by highly distributed sources of emissions – namely small-scale gas boilers – and, in colder countries, by high peak demand.

The opportunity

As with transportation, there is considerable potential to electrify heating. Ground or air-source heat pumps – which are three to four times more efficient than other types of space heating – could replace a large proportion of conventional heating in certain markets.

As with electric vehicles, domestic heating systems offer enormous potential to act as a huge distributed energy storage system. Smart electric water heaters could be set to heat up during periods of high levels of renewable power generation, and to turn off at times of peak demand.

There is considerable potential for utilities to develop or expand products and services around energy management – home automation, smart tariffs, facility management and ancillary services, energy efficiency solutions, asset maintenance and building energy management systems.

District heating systems – using waste industrial heat, large-scale heat pumps, or sustainable biomass – also offer considerable potential to reduce emissions.

Countries and companies are investigating alternatives such as substituting natural gas with carbon-neutral biogas or green hydrogen. The choice of pathway is complex, but the ready availability and competitive cost of carbon-free electricity is expected to drive a significant increase in electricity’s share of the heating markets.

There is considerable potential for utilities to develop or expand products and services around energy management – home automation, smart tariffs, facility management and ancillary services, energy efficiency solutions, asset maintenance and building energy management systems.

The challenge

Strong policy action is needed by government to mandate low-carbon heating and cooling in new-build properties, says Dutton at E3G.

For existing housing stock, particularly older properties, aggressive action is needed on insulation, given that heat pumps work best in well-insulated homes. Richard Lowes, a research fellow and member of the Energy Policy Group at Exeter University in the UK, says such initiatives would need to be state-led and ensure that the skills existed to make sure energy efficiency retrofitting is done properly.

More broadly, he argues that decarbonising heating requires decisive policy interventions, including devolving responsibility to local authorities (alongside adequate financing), attractive incentives for building owners to replace gas boilers and, potentially, a carbon tax on gas used for heating. But there could be a private sector-driven offering that combines time-of-use electricity tariffs and upfront, third-party financing to allow homeowners to buy heat pumps.

“It’s possible to provide low-carbon heating at no additional cost to the consumer… there’s a holy grail the private sector could get to,” says Richard Lowes, Research Fellow and member of the Energy Policy Group, Exeter University, UK.

District heating systems, meanwhile, need to be designed with flexibility in mind, says Stuart Allison, Head of Solutions at Vattenfall. “The engineering decisions being taken and the contracts being put in place today need to have the capacity built in to move to zero-carbon,” he says. While the engineering solutions exist to build zero-carbon district heating systems, cost considerations mean that they may well initially operate on a low-carbon basis instead, with a clear strategy to advance to zero-carbon as the market economics allow.

It’s possible to provide low-carbon heating at no additional cost to the consumer … there’s a holy grail the private sector could get to
Richard Lowes,
Research fellow and member of the Energy Policy Group, Exeter University, UK
The-hydrogen-economy-Ideas-Water, naturalgases
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Chapter 3

The hydrogen economy

As a (potentially low-carbon) form of energy, hydrogen has a number of advantages.

Like liquid fossil fuels, it has a high energy density, making it suitable to power vehicles, heat buildings and even fuel industrial processes such as steel production. It is non-toxic, abundant in the form of water and natural gas, and, if produced using electrolysis powered with renewable electricity – or from natural gas using carbon capture and storage – emissions in production and use. On the other hand, it is highly flammable and needs to be stored and transported under pressure, adding to its cost.

The opportunity

Hydrogen offers the prospect of helping to decarbonise the transport, heat and industrial sectors while providing a use for surplus renewable power. The International Renewable Energy Association (IRENA) estimates that it could supply 6% of final energy consumption by 2050, while industry body the Hydrogen Council says this could be as high as 18%.6

A number of pilot schemes to replace fossil fuel with hydrogen are underway:

  • Swedish utility Vattenfall is working with Preem, a Swedish fuel refiner and supplier, on a pilot 20MW hydrogen production plant, employing water electrolysis using renewable power.
  • Steel maker ArcelorMittal is working on a €65m demonstration project in Hamburg to replace coking coal with hydrogen produced using power from offshore wind farms.
  • In the UK, Danish clean energy firm Ørsted is working with fuel cell company ITM Power and renewables development firm Element Power on a UK Government-funded project to investigate the large-scale delivery of green hydrogen.
  • In South Australia, the Government has unveiled a Hydrogen Action Plan (pdf)7 which sets out how the state could become a major producer and exporter of green hydrogen, based on a major expansion of its renewable energy capacity.

For utilities, hydrogen production could play a particularly important role in the seasonal storage of renewable electricity, IRENA argues, in scenarios with high renewables penetration (and, therefore, periodically large volumes of surplus capacity).

The challenge

The main challenge is the cost of green hydrogen, and the vast investments in infrastructure needed for its rollout. Currently, it is too expensive to produce economically for any but a handful of niche, high-value applications – although its costs are falling.

However, cost comparisons with primary fuel sources need to be viewed in context, says Tim Calver, Associate Partner, Advisory at EY: “Hydrogen also creates value through its role as an energy vector, coupling electricity and gas systems, enabling long-duration, high-volume storage of intermittent power, and in providing the functionality of a combustible gas rather than electrons.”

The main challenge is the cost of green hydrogen, and the vast investments in infrastructure that will be required for its rollout. Currently, green hydrogen is too expensive to produce economically for any but a handful of niche, high-value applications – although its costs are falling.

What needs to happen

Critical to developing a hydrogen economy is reaching scale quickly, says Calver. “Governments can help by encouraging large-scale trials – that’s the only way to tackle a number of challenges at once and drive economies of scale.” Equally, attention should be focused on developing projects around large-scale sources of demand first, such as industrial applications, rather than projects around the use of hydrogen in domestic heating.

Secondly, policymakers and regulators need to take a systems-wide approach. “This is about the convergence of power and gas as a means of driving deep decarbonisation,” says Calver. “Ensuring joined-up regulation between power and gas markets will be critical.”

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Chapter 4

Electricity grid infrastructure

A zero-carbon electricity system will need a substantially different grid.

It needs one that has shifted away from dominant, large, centralised sources of generation to a more distributed model, which has hundreds of thousands of small-scale or micro renewables systems, with the flexibility to much more dynamically match supply and demand, including by tapping large-scale storage capacity. Substantial investments at both the transmission or distribution levels will be needed, not only in the physical wires but also in the IT needed to balance an increasingly complex and intermittent generation system.

The opportunity

For grid operators able to recover their costs, plus a margin, from regulators, this presents an opportunity for significant investment. For institutional investors, grid modernisation presents an opportunity to earn reliable, regulated returns.

“There’s a massive amount of investment needed,” says Calver at EY. “At the moment, we are seeing regulators drive a very hard bargain in terms of rates of return, which is obviously important from the point of view of the consumer. But you don’t want to discourage grid operators from deploying capital.”

“We’re going to see the biggest changes at the edge of the grid, on the distribution side, to support high penetration of variable resources,” says Juan Torres, Associate Laboratory Director, Energy Systems Integration at the National Renewable Energy Laboratory (NREL) in Golden, Colorado. “We have to install much smarter devices to manage grid variability.”

“We do have an opportunity in the rapid advancement in terms of the technology available to manage the grid,” says Juan Torres, Associate Laboratory Director, Energy Systems Integration at the National Renewable Energy Laboratory (NREL) in Golden, Colorado.

“We do have an opportunity in the rapid advancement in terms of the technology available to manage the grid. Moving into the age of artificial intelligence and big data, the owners of the grid are looking at how they can use those to make the grid more reliable,” he adds.

We do have an opportunity in the rapid advancement in terms of the technology available to manage the grid.
Juan Torres,
Associate Laboratory Director, Energy Systems Integration at the National Renewable Energy Laboratory (NREL) in Golden, Colorado

The challenge

One particular challenge, says Kevin Schneider, Chief Engineer at the Pacific Northwest National Laboratory (PNNL), will be a how to compensate those utilities that operate distribution networks as behind-the-meter renewables generation undermines their revenues. “They will have to look for non-kilowatt sources of revenue, such as consulting services,” he says.

Schneider also notes that the communications capacity of a modernised grid will have to be an order of magnitude greater than currently required, and will involve grid operators or other actors, to have considerably more control over third-party assets, such as batteries, and smart heating and cooling systems.

Another often overlooked aspect is the workforce that will be required to operate an increasingly sophisticated electricity system.

He adds that “It’s going to be a really big cost. Look at a crew in a bucket-truck – 20 years ago, it was very blue collar. Today, it’s a far more technologically demanding job, requiring much more training.”

What needs to happen

Calver argues that the type of mechanisms that exist to manage supply and demand at the transmission level will need to be developed at the distribution level, enabling small-scale sources of generation and load to trade locally. “Using new, automated technology systems, commercial mechanisms and price signals need to be put in place to enable supply and demand to be balanced at the local level – that would help to optimise investment at the transmission and distribution levels capacity.”

Distributed system operators (DSOs) – responsible for connecting new capacity to the distribution grid and improving system resilience through appropriate reinforcement – will be essential in enabling the energy transition and guaranteeing network stability. They must be enabled, through forward-looking regulation, smart technology, and greater interaction with customers, to tap flexibility mechanisms such as demand response and storage capacity. EY teams have worked with Eurelectric to provide guidance (pdf)8 for DSOs, regulators and policy-makers to inform the next generation of DSOs.

There are also fewer tangible changes needed, says Schneider at PNNL. For example, regulators and utilities and grid operators need to work closely together to forge a way forward, while regulatory bodies themselves need to improve their levels of technical understanding of the issues at play. “Regulators are not typically power system engineers: but they need to be able to find sources of trusted knowledge to ensure that what they propose is grounded.”

Summary

Considering the opportunities - and challenges - facing the power and utilities sector from four major parts of the decarbonisation jigsaw: electrifying transport; low-carbon heating and cooling; a clean hydrogen economy; and a smart transmission and distribution network.

About this article

By

Benoit Laclau

EY Global Energy Leader

Experienced energy leader and advisor.

Contributors