In its Sixth Carbon Budget reportpublished at the end of last year, the Climate Change Committee (CCC) recommended full decarbonisation of the power sector (including phase-out of unabated gas-fired power) by 2035.
That’s just 15 years away.
Will our current market arrangements get us there cost-effectively, meeting the huge influx of electrified transport and heating that the targets imply (while maintaining little things, like the grid stability and security that we are so used to)? That is the urgent question facing policymakers.
We set out our thoughts on this huge, multifaceted challenge in our recent report – Rethinking Electricity Markets: EMR2.0. While GB’s Electricity Market Reform (EMR) has out-performed expectations in driving down costs and mobilising investment in zero carbon generation capacity, we are convinced that a new phase of reforms is necessary. This is because the challenges have changed, are complex (see Figure 1) and need multi-pronged strategic solutions that can simultaneously address them all. In this blog, we set out why work on this must start now and the signs that the current system is starting to creak.
Figure 1: Energy Systems Catapult identified five key challenges that need to be addressed by electricity market design reforms
Renewables growth is outpacing flexibility & system development
The share of intermittent renewables – wind and solar – in the power mix has rocketed from 3% in 2010 to 28% in 2020 (TWh). But storage, demand-side flexibility and system development have been unable to keep pace. As a result, negative prices in the short-term wholesale electricity markets are more commonplace and system balancing costs are increasing.
Net balancing costs were £506m in 2015 but system pressures have pushed the net cost in 2020 to £1.3bn, 67% higher than 2019 (£794m) (see Figure 2).
Figure 2: Source: Elexon (note: not including availability fees or start-up costs)
The raising of an emergency grid code modification (GC0147) allowing ESO to instruct DNOs to disconnect embedded generators under “emergency conditions” – this is because GB hasn’t yet found a way to make embedded generators visible, controllable or incentivised to respond to the power system’s needs and this should change;
Hastily launching an Optional Downward Flexibility Management product for Demand Turn Up or Generation Turn Down from any assets not in the Balancing Market – this is because until now a lot of small and non-traditional assets are excluded from participating in the Balancing Mechanism due to rules, eligibility criteria etc, when it’s the case that they can actually provide the needed services or outcomes; the situation is improving with theWider Accessinitiative but the barrier to entry is still high for many resources. Also, ESO’s access to flexible energy resources is restricted by Active Network Management in DNO areas.
In many ways, last year’s lockdown was a postcard from the future. While it showed that massive demand reduction is possible – through, for example, homeworking, reduced travel, videoconferencing – it also highlighted the risks of a system with a high proportion of variable supply and limited storage and demand-side flexibility. Disruptions through extraordinary measures detailed above are not desirable.
Flexibility needs better market signals
So the GB power system needs to be much more flexible. This week’s report from the Carbon Trust was also just the latest piece of evidence showing how flexibility can deliver cost savings. In a power system based on high shares of variable renewable energy, we also need flexibility providers to respond to highly dynamic price signals that much more accurately reflect the physics of the power system in real-time and by location. But current prices and incentives are distorted, relatively static and blunt. Unlike many other countries, we still have only one national electricity price that changes every half hour.
The need to drive innovation in large-scale sources of firm, flexible power and inter-seasonal storage is urgent. Recognising this, the Government has set out commitments to support commercialisation of some technologies – such as gas and bioenergy with CCS, flexible nuclear and hydrogen – in its Ten Point Plan and Energy White Paper.
To achieve Net Zero, it’s imperative to decarbonise energy demand, which will connect many millions of distributed assets such as electric vehicles and heat pumps to the power system. This will create a much more complex system. The costs of decarbonising these new demands can be significantly reduced with flexible control and operation of these assets responding to accurate market signals. To bring forward this innovation we need market signals that reward service providers and consumers for the full system value of their flexibility. This approach would reduce total system costs and unlock benefits for all consumers.
Harnessing flexibility can make a huge difference to the cost of the future electricity systems. In modelling done for ESC by Baringa, different versions of the 2050 power system ranged in absolute costs from £35 to 45bn a year – potentially 30% more expensive than the cheapest scenario (of course, it is worth saying that current models are still conservative on the potential of demand-side innovation, as much is unknown). Contrary to the views of some, we doubt our ability to predict the right energy mix for 2050. And when we don’t know the answers, well-designed markets can reveal the best answers that really work for service users. This is why we think market reform is crucial for revealing the true potential for flexibility in delivering zero carbon electricity.
Ofgem and BEIS have made great strides in implementing the Smart Systems Flexibility Plan (SSFP) and an updated plan is expected to be released by summer. While many of the measures of the SSFP to enable flexibility – such as removal of market barriers and adoption of Market Wide Half Hourly Settlement (MHHS) reforms – will be implemented by 2025, commercialisation of flexibility will continue to be hampered if wholesale market prices are not able to sufficiently or accurately reflect system value.
Unfortunately, it seems likely that the scope of the SSFP will be restricted to the current legislative framework and EMR policy. We think that the Government’s strategy to increase system flexibility will require reforms to EMR if flexibility is to have access to full system value.
CFDs and the Capacity Market distorting incentives for demand-side innovation
Perhaps the biggest factor distorting electricity markets, and therefore stifling the potential of demand-side measures and the innovative companies that could provide them, is the Contracts for Difference (CfD) and Capacity Market (CM) schemes – the two main pillars of the Electricity Market Reform Policy (EMR).
The CfD scheme means renewables increasingly cannibalise their own revenues from markets over time (see Figure 3 – and explained in more detail here). And as figure 3 shows, this is going to get more pronounced the more variable renewables are added to the system. The Capacity Market dampens the scarcity pricing effect and so reduces incentives for flexibility. Both of these schemes, through the out-of-market compensation they provide, suppress average wholesale prices.
Figure 3: Modelled capture prices for wind and solar, UK (2018 money). Source: Cornwall Insight, 2018.
The schemes also have a distorting impact on electricity retail markets, with their costs adding to the increasing environmental and social obligation costs that include the costs of previous schemes (e.g. Renewable Obligation (RO); Feed-in-Tariffs (FiTs)). These costs now account for nearly a quarter of the average retail bill (see Figure 4). These costs are much higher for electricity than residential gas, delaying decarbonisation through switching from gas to electricity (ESC has set out our suggestions for better heat and buildings policy here). The policy costs could be levelised across gas and electricity or socialised across generation taxation. Ultimately, however, we need to phase-out the out-of-market compensation that ends up as levies on retail bills.
Figure 4: Rising costs of third parties passed through to consumers by the supplier. Source: Cornwall Insight, presentation at LCCC autumn conference, November 2019.
For the system to be efficient, market actors need to face the costs that they impose on the system or be fairly rewarded for the system benefits they provide – and the Government recognises this. If we fail to start reforming this now, we are in effect distorting the incentives for investment in new innovation – causing less investment and attention to be focused on innovation in system integration technologies and business models of all kinds.
Earlier this year the Government launched a Call for Evidence (CFE) on “how policy support for renewables should evolve effectively over the long term with the objective of reducing overall system cost and maximising the benefits to consumers, including the potential for wider economic benefit”. Through this Call for Evidence, the Government put several CfD scheme reform options on the table.
Immediate reform of the CfD scheme is necessary and can be done relatively quickly within the scope of the current Energy Act 2013. But continued use of Government-led long-term contracting through CfDs for the purpose of fully decarbonising the power system will carry significant medium-term risks for innovation and revealing the efficient mix of flexibility and demand-side technologies.
At this point, many economists reach for carbon tax tools. While carbon pricing should play an important role (and carbon incentives are currently a chaotic mess across the economy), it needs to be complemented by a mechanism that will guarantee decarbonisation of the power sector at the needed pace, ahead of other sectors. Such a mechanism should do this in a way that does not distort markets, drives efficient system development and investment, as well as innovation right across the energy value chain for the benefit of consumers and wider society. We think an obligation on suppliers to progressively reduce the carbon content of their portfolios of energy resources and on offtakers for their purchases, is the way to do it. It would be technology-neutral, neutral between the demand and the supply side innovators, and provide investor confidence. See here for further explanation.
Relying on CfDs and the CM to procure all the zero carbon capacity needed to decarbonise the power sector would seriously reduce optionality and close down innovation opportunities, particularly in the retail and financial markets – not to mention the high likelihood of oversupplying the market, therefore costing consumers more than it needs to. There’s also the risk, some would say inevitability, that Government could get it wrong in picking the winners and deciding the combination and volume of resources entirely through central procurement. This would likely result in a power system that is much more expensive than necessary – worse, the Government or regulator might be forced to step in with unpopular, blunt regulatory interventions applied directly to consumers in order to manage system security and reliability.
To ensure the power system is sufficiently reliable, we need a capacity remuneration mechanism (CRM) that is much more compatible with the demand-side. Our deep analysis conducted with AFRY concluded that a decentralised approach to reliability policy, possibly using Reliability Options, would provide stronger incentives for retailers to use demand-side flexibility and provide energy services through decentralised contracting, as well as manage risk on behalf of consumers. We will blog on this in the comings weeks.
In addition to these market reform measures, the Government needs to take further steps on enablers of the shift to a more flexible, digitalised system: a smarter consumer protection framework; interoperability standards; open data; a more strategic approach to code changes. With this greater clarity, market actors will be much more strongly incentivised and free to innovate, and investors can more effectively manage uncertainty and risk. A summary of our proposed reforms for zero carbon electricity is set out in Figure 5.
Figure 5: Overview of a decentralised outcome-based market and policy framework for zero carbon electricity
Relying on the system operator to manage the new pressures on the system is fraught with risk in a more complex system
National Grid Electricity System Operator (ESO) is pushing ahead to develop its capability so that it can successfully operate a zero-carbon electricity system in Britain by 2025. But the CCC’s recommendation for 2035 means using this capability every half hour of every day with no recourse to carbon-based energy resources. Not only this but huge growth in electricity demand is expected, with potentially very high growth rates between the late 2020s to the 2040s, as energy demand electrifies in order to decarbonise.
NG ESO has set out comprehensive roadmaps and plans to reform aspects of market design that are within its control, focusing on things like simplifying and broadening access, moving procurement closer to real-time and defining the new products and services that are needed by high-renewables systems. What is becoming increasingly evident with growth in variable renewables, however, are rapidly rising system integration costs and an increasing reliance on NG ESO to balance and stabilise the system. Those rising costs for balancing the system are under review by Ofgem. ESO’s ability to manage the system in the way we have come to expect, however, is strongly influenced by past operating practices and limited by the current market design, policy framework and governance arrangements.
NG ESO is thinking widely about the development of markets in consultation with stakeholders through its Bridging the Gap initiative, chaired by Laura Sandys. Strikingly, this initiative only looks forward to 2025. NG ESO needs to be looking much further ahead given its role in delivering a Net Zero economy by 2050, but this isn’t really possible in the absence of a clear long-term vision from Government on market design.
This long-term vision, with clarity on outcomes to be achieved by the market, should be guiding the near-term evolutionary reforms – such as the network charging reforms currently being undertaken by Ofgem, the various industry codes being developed in an ad-hoc fashion, and BEIS’s considerations to evolve the EMR schemes. In absence of this, near-term reforms will be progressed based on past experience and current ways of thinking, and this increases the risk of high path dependency, reducing options and opportunities for later change towards the future we actually want.
Reform takes a long time – it needs to start now
In its 6th carbon budget report, the CCC calls for immediate action to reform market design:
“An evolutionary approach is appropriate over the short-to-medium term. But planning for running a fully decarbonised system should begin immediately, given lead-times for policy development and investment; The Government should develop a clear long-term strategy as soon as possible, and certainly before 2025, on market design for a fully decarbonised electricity system.” (Climate Change Committee, 2020b, p52).
We argue in Rethinking Electricity Markets: EMR2.0 that major reforms are needed sooner rather than later, requiring considerable resources and time. While evolutionary reforms should continue in the short term, preparations for more far-reaching reforms should be undertaken in parallel and should feed into short-term decision-making.
Progress in adapting the energy sector and market design for a Net Zero future has been severely held back by the industry’s self-regulation code regime which is excruciatingly slow, ad-hoc and lacking consumer focus. Our work with the Institute of Engineering and Technology on the Future Power System Architecture Programme found that a much more agile approach to regulatory change is needed in future and this is only possible through code governance reform and a new agile change and governance approach. It is crucial, therefore, to include governance reforms in the new legislation. In addition, it is critical for Government to clarify the roles and responsibilities of NG ESO (to ISO), DNOs (to DSOs) and the coordination between them. New institutions are likely needed, such as an independent power market monitor.
It may seem as though 2035 and 2050 are a long way off, but from an infrastructure investment and technology development perspective, it is no time at all.
We must therefore act now to ensure networks are used and developed as efficiently as possible – we have to get this right given the billions of investment that will be needed to develop and reinforce networks – and also to incentivise the innovations that can manage and reduce pressure on infrastructure networks. Effectively regulating the network owners (TOs/DNOs) through reforms to the RIIO price control is crucial to encourage the right investment decisions but this should be supported by sharper and more granular and dynamic locational price signals.
Locational energy pricing – with energy prices varying every half hour by location around the UK, reflecting network congestion – could potentially save consumers billions, with Aurora and Policy Exchange estimating some £2.6bn/year for one scenario. Locational energy prices, efficiently combined with other sharper locational price signals or incentives (e.g. network connection charges; network use of system charges or local energy/flexibility markets (potentially also with locational energy pricing) at lower voltage levels; CfD scheme design) would – combined with strategic planning at national and local levels (e.g. Local Area Energy Planning (LAEP)) – achieve much more efficient siting of generation or demand reduction in locations of high electricity demand, ensure efficient dispatch by location and better inform efficient planning and investment decisions for networks. Not only would this significantly reduce total system costs, it would contribute to greater system diversity and resilience, and also create new jobs across the country.
We believe Government needs to urgently launch a formal process for the next phase of electricity market reform, reforming the Energy Act 2013. It will be a challenging and ambitious piece of legislation to construct and needs to be wide-ranging in scope, including:
clear vision for long-term market design, as well as market outcomes to be achieved;
reform to the EMR policy framework in order that it achieves targeted market outcomes (e.g. full decarbonisation of electricity by 2035) and develops markets and the industry towards the new vision;
more efficient system and market operation, including locational energy pricing;
governance (including roles, responsibilities, powers and accountability of various institutions, and industry code governance); and
consumer rights/protection, including ensuring consumers can access the full value of their flexibility but that risks are appropriately managed by retailers.
This will demand considerable time and resource as the process should involve whole systems analysis, sufficiently deep and integrated market and policy impact assessments, debate and wide consultations with stakeholders, drafting of legislation, adoption of the Act by Parliament and finally, implementation that will require phasing and transition. We have little time to waste.
Markets, Policy and Regulation
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