The UK has made great strides in the transition towards a low-carbon energy economy, but a new national target to be carbon neutral by 2050 and sweeping changes to the way power is generated, delivered, and consumed, will place unprecedented demands on network regulation, planning and operation.
A proliferation of new energy and storage technologies, from electric heat pumps to homes batteries and electric vehicles (EVs), and a move away from traditional centralised power plants to a more distributed system, is forcing a rethink of how utilities manage energy flows and co-ordinate demand response.
Heating accounts for around a third of UK greenhouse gas emissions and, alongside energy efficiency improvements to homes and businesses, there is an urgent need for sustainable energy alternatives like low-carbon district heating networks or the use of hydrogen as a replacement for natural gas.
Policy and regulation will be key to directing environmental strategy, but critics claim that prescriptive energy regulation smothers the innovation needed to create sustainable solutions. A recent report by the National Infrastructure Commission warns that the UK will fail to meet its 2050 net zero target unless regulators are equipped with new powers to boost investment in sustainable Infrastructure and move away from the current culture of “short-termism”.
Meanwhile, no-one has yet convincingly answered the question of who should pay for decarbonisation, and whether the bill should be met through taxation on businesses and/or individuals, or customer energy bills. Michael Pollitt, assistant director of the Energy Policy Research Group tells Utility Week: “Energy demand is actually falling in OECD [Organisation for Economic Co-operation and Development] countries but low-carbon solutions involve very high fixed costs. It is difficult to see how you can decarbonise without raising the unit price of energy, and the capacity to finance this through taxation is limited.”
Britain is not alone in grappling with these challenges, and as the examples on the following pages demonstrate, important lessons can be learnt from ideas and initiatives implemented in countries abroad.
Lessons from Australia: How do we integrate distributed energy resources?
Distributed energy resources (DER), such as rooftop solar, home batteries, electric vehicles and smart appliances will play a key role in the electricity system of tomorrow, but finding ways to make these systems work in a grid designed for large, centralised generation is a challenge that energy experts are grappling with.
Australia is leading the world on DER integration in a scramble to accommodate a massive uptake of rooftop solar, installed on around two million homes. Work is already under way to reform network charging so that customers pay not just for energy consumed but for access to the services required through the network, while being rewarded for providing services to the grid.
A $12.5 million (£7 million) pot from the state-run Australian Renewable Energy Agency will fund innovation projects and studies designed to integrate DER into the electricity system.
One project will trial software on the New South Wales grid that acts as a “traffic controller”, with the ability to remotely increase or decrease output from customer-owned assets to manage grid congestion. Another will develop a prototype smart hot water system that can be aggregated into a centrally controlled fleet and exploit energy usage predictions and weather forecasts to optimise the use of excess solar power to heat water.
The latest review of the regulatory framework, by the Australian Energy Market Commission, pushes for major grid reforms to integrate DER intended to avoid billions of dollars of capital investment in new capacity such as substations, poles and wires.
Among other things, the report recommends that distribution network operators and the Australian Energy Regulator introduce reduced network tariffs for customers who invest in solar PV with electricity storage, as an incentive to improve grid efficiency.
It calls for the accelerated development of technical standards and information to support the integration of distributed energy. These include: new regulator guidelines to evaluate revenue proposals from distribution businesses for projects designed to better integrate DER; a review of competition in smart metering arrangements; and identifying distribution businesses’ future data requirements, including additional meter data that should be collected.
Guy Newey, strategy and performance director at the Energy Systems Catapult comments: “Australians had tax breaks to install solar panels but the grid implications were not thought through so the regulator has had to be very nimble to deal with the overload and get the market signals right to encourage people to provide grid stability. It’s a leading example of regulatory innovation.”
Lessons from Norway: How do we create a more flexible energy market?
The increasing prevalence of technologies like smart meters, battery storage, EVs, solar PV and electric heating offers an opportunity to manage and operate the grid more efficiently and level out demand, rather than having to build out new capacity.
This transformation will require a big shift in the way electricity markets function, underpinned by the principle of flexibility and giving people more control in how they use electricity and opportunities to compete to sell their power into new flexibility service markets.
The recently adopted European Clean Energy Legislative Package lays out new rules for network operators to procure flexibility resources for electricity system operation, it says that distribution system operators (DSOs) should buy these services where these are cheaper than grid expansion.
Platforms that demonstrate the benefits of a flexibility services market are being rolled out in Norway, the Netherlands, Germany, Australia and elsewhere.
Norway’s NODES is an open and independent marketplace, jointly owned by the power market Nord Pool and energy company Agder Energi. It enables DSOs and TSOs (transmission system operators) to buy local flexibility to help manage local bottlenecks and operate the grid more cost efficiently.
A fully automated version of the platform, built on Microsoft technology, is live in south Norway where, during a pilot, Agder Energi was able to defer a grid investment of €4.5 million (£3.8 millioin) by buying local flexibility.
The GOPACS platform, launched earlier this year in Holland, enables the TSO, TenneT, and all DSOs to mitigate grid congestion by buying flexibility on the intraday market.
It matches a reduction in production in one area of the grid with an increase in another area, creating an intraday congestion spread. The price difference is paid for by grid operators via the intraday market platform Energy Trading Platform Amsterdam.
Randolph Brazier, head of innovation and development at the Energy Networks Association, tells Utility Week: “GOPACS enables flexibility providers to trade between themselves and provide services to both transmission and distribution networks. That level of co-ordination between different market players is traditionally extremely difficult, it can help prevent oscillating market signals and optimise system operation to create a very efficient grid. It allows renewable energy providers and other distributed energy resources to provide services to different markets and stack revenue streams, which is not normally possible.”
A successful move into this nascent space will require new regulatory measures. According to SmartEn, the association for digital and decentralised energy solutions, system operators will need to be incentivised to invest in digital solutions and software rather than physical infrastructure alone to resolve grid congestion problems.
To avoid a concentration of market power by the system operator, it says flexibility markets should be directly open and accessible to decentralised resources and consistent with electricity wholesale markets and the transmission level.
Lessons from Mexico: How can we roll out low-carbon energy projects more efficiently?
Britain is a world leader in offshore wind, prices for the third round of contracts for difference (CfD) auctions, held in September, fell by as much as 66 per cent compared with the first round held in 2015.
But that success story has not been replicated in the rollout of other low-carbon electricity technologies, such as solar PV, onshore wind or nuclear. Jeff Hardy, senior research fellow at the Grantham Institute – Climate Change and the Environment at Imperial College London, comments: “Nuclear hasn’t gone through the same transparent competitive process, we have a moratorium in England on onshore wind deployments and there isn’t really an incentive for solar, which is one of the cheapest technologies available.”
Procurement lessons could be learnt from Mexico, where a series of technology-neutral power auctions have attracted global attention: the most recent in 2017 recorded the world’s cheapest solar bid of US$20.57 per megawatt-hour.
The auctions were the result of sweeping reforms to the regulatory framework, designed to open up the market to private sector firms and enable the country to achieve 35 per cent green generation by 2024. Around half the pledged investment in the 2017 auction went into new solar, with the remainder going to wind and natural gas.
Hardy comments: “Power prices for solar PV in Mexico have been really low, which is good for customers, gives certainty to developers and allows the government to get things built. Auctions tend to drive really good cost reductions because good developers are able to work out where to save money in the development process and can make money while entering into a low-cost contract with the government for the power.”
The delays and massive cost overruns at Hinkley Point C are symptomatic of a global problem with complex and bespoke nuclear designs. Projects can take 20 years to mature and are becoming less attractive to power companies that now have cheaper, renewable means of producing electricity.
South Korea has managed to buck the nuclear trend and build reactors in less than five years through the adoption of standardised designs, constructed sequentially, on a limited number of sites using a stable supply chain.
“South Korea has had the most success in the past 20 years in terms of reducing the cost of nuclear,” says Guy Newey, strategy and performance director at Energy Systems Catapult. “It’s down to the fleet approach, using the same reactor design and the same people, who move around the country constructing reactors and building their learning into subsequent projects.”
Lessons from Sweden: Who pays for the transition to low-carbon?
The complex question of who should foot the bill for a decarbonised energy system has yet to be answered, but it is likely to involve a trade-off between taxation for carbon dioxide emitters, industrial users and citizens – or hikes to customer energy bills.
Sweden is one of the few countries which has implemented a blanket carbon tax that applies to all upstream fuel and energy industries that produce emissions from fossil fuels, and downstream sectors, such as manufacturing, agriculture, co-generation plants, forestry, and residential and service sectors, which are compelled to pay 25-50 per cent of the tax.
The tax rate is one of the highest in the world and measured in proportion to the carbon content of the fuel. Certain exemptions and reductions allow some energy-intensive industries to remain economically competitive. The tax is widely considered an economic and environmental success. In 2017 alone it generated €2.4 billion and citizens have consistently supported its ability to lower emissions without impacting the overall economy.
The decarbonising price signals have triggered an increase in alternative fuel use in some sectors. According to a report by the Energy Systems Catapult, the UK can learn in particular from the impact of carbon taxation on Sweden’s residential sector, which experienced a 60 per cent uptick in the use of biomass fuel for district heating, greatly reducing emissions. The report states: “Promoting biomass use for residential and commercial heating could be an alternative and more effective policy to combined heat and power investment in the UK.”
Ofgem is currently focused on limiting the costs paid by consumers for decarbonisation, but that’s not the approach adopted by Germany where householders pay some of the highest electricity prices in the world.
The country’s highly ambitious targets for renewable power generation under its Enegiewende programme (45 per cent by 2030 and 100 per cent by 2050) resulted in expensive wind and solar installations. Coupled with the decision to shut down nuclear plants early and with a continued reliance on coal power, the effect has been a hike in wholesale electricity prices.
Germany’s two major electricity companies, Eon and RWE, suffered major losses, but rather than penalise heavy energy users, such as car plants, which already receive substantial energy discounts, costs were instead placed at the feet of consumers and small businesses.
This schizophrenic policy has not produced a low-carbon economy, but positive lessons can be learnt from it, says Energy Systems Catapult’s Guy Newey: “Germany is a good example of how to do something different yet still manage to maintain political support for the transition. Consumers there remain mostly supportive of the low-carbon transition; they want to protect their industry and are comfortable about paying for that through their energy bills.”
According to Energy Policy Research Group assistant director Michael Pollitt: “No-one has a solution to how you pay for decarbonisation. One of the problems is that energy demand is actually falling in OECD countries and low-carbon solutions involve very high fixed costs spread over declining numbers of units of energy. It is difficult to see how you can do it without putting the unit price of energy up. And the capacity to finance this through taxation is limited.”
Lessons from the Netherlands: How do we decarbonise heat?
Heating buildings accounts for more than a third of UK greenhouse gas emissions due to heavy reliance on the fossil fuel natural gas.
A decarbonised future will require massive investment, and supporting policy and regulation, to switch millions of people to new modes of heating, including electric heat pumps, direct electric and storage heating (run on green electricity); district heating networks with low-carbon heat sources, and gas networks converted to run on biogas or hydrogen.
Lessons can be learnt from the Netherlands where the decision to end natural gas production by 2030 in the wake of several earthquakes led the government to adopt targets to make all new buildings “almost energy neutral” by the end of 2021, and to phase out gas in heating entirely by 2050.
A range of subsidies and tax breaks were made available to homes and businesses to fund the installation of low-carbon heating solutions, and a €120 million subsidy was given to 32 districts in 27 municipalities to phase out gas.
A surge in customer interest in decarbonised solutions, mainly heat pumps, triggered market growth of over 50 per cent a year, resulting in more electric-only and hybrid heat pump solutions on the market and an agreement to train 6,000 more engineers to support the expansion.
Jeff Hardy, senior Research fellow at the Grantham Institute – Climate Change and the Environment at Imperial College London, tells Utility Week: “Beyond 2021 [when the Renewable Heat Incentive expires] the UK doesn’t have a single incentive in place for homes or businesses to install zero-carbon heating technologies … an important question is how we help homeowners with the upfront capital costs. Countries in Scandinavia and elsewhere have introduced schemes that help with some of that capital. In addition, the UK lacks regulations that set standards for heat pumps and centres of excellence where engineers can be trained and devices tested to prove they will work in particular circumstances and climates.”
Stephen Cousins is a freelance journalist