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REMA is set to be a 'once in a generation' review of the market. Image: Getty.
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The reality of REMA

REMA is set to be a 'once in a generation' review of the market. Image: Getty.

As the Conservative leadership contest progresses, unaccountably few of those standing have given an opinion on the future of the electricity balancing mechanism. Arguably that subject – along with everything else to do with the future of the power market – will have considerably more impact on the UK’s future economic success than anything promised by the candidates in this campaign.

The state of the UK’s political debate notwithstanding, proper examination of any proposals for the reform of the power market is vital. The Government’s Review of Electricity Market Arrangements (REMA), published on 18 July, is precisely this: looking at the pent-up problems and suggested fixes to those problems that have arisen since the Electricity Market Reform (EMR) process in the early 2010s.

The challenge facing REMA

The first – and perhaps primary – challenge is the delivery of the enormous volumes of new infrastructure that achieving zero carbon electricity by 2035 will entail. National Grid’s Future Energy Scenarios see the total capacity of UK generation increasing by at least 150% on 2020 levels by 2035. This is equivalent to building ten gigawatts (GW) of new generation every year, or three Hinkley Point Cs.

The second is around the relative stability of the power system – or perhaps more accurately, the increasing cost of making sure the system is stable. Net balancing costs increased from £506 million in 2015 to £1.3 billion in 2020, and are projected to increase even further in the future. These costs are driven in large part by an increasing need to manage large volumes of generation, principally wind, stuck behind constrained areas of the network.

The third challenge is related, but needs to be a specific objective by itself: cost. We are in the grip of the worst energy price crisis since the 1970s. Gas prices are projected to, if not remain as high as they are, be considerably more volatile over the next decade than over the entirety of the 2010s. Any reforms to the market will be subject to a political test of whether they genuinely reduce costs, as a minimum in the medium term.

Options to tackle these challenges are varied, but can be split into two primary categories under which the Government is developing some of its thinking. The first is around the mechanisms that deliver investment in low carbon power.

Solving Investment

The Government has an existing suite of instruments it can use to deliver particular kinds of assets. The Contract for Difference (CfD), which pays generators a guaranteed price for their power, has been used for the Hinkley Point C nuclear plant and to deliver large volumes of renewables at low cost. The Dispatchable Power Agreement (DPA), which combines a capacity payment with a degree of revenue certainty for assets capable of flexing their output – principally gas power stations equipped with carbon capture and storage – has yet to be implemented. The Regulated Asset Base (RAB) model, already used for network infrastructure, is now being used to support new gigawatt-scale nuclear.

The focus of the debate in this space is around whether the CfD is the right mechanism to deliver the very large volumes of investment needed by 2035 at the lowest possible cost. The bulk of generation needed for that deadline is large fixed cost variable output renewables. While the CfD has delivered effectively, there are reasons to consider why it might not be suitable in the long term.

The first is how it interacts with a key market impact of renewables: price cannibalisation. The more renewables you have chasing after the same consumer demand when the wind is blowing and the sun is shining, the lower the overall market price. While this doesn’t matter to generators with a CfD, CfDs only last for fifteen years. When these come to an end, those generators will only be able to receive that cannibalised price for their power. For some generators, this might mean shutting down.

The second is that it leaves Government in charge of volume risk. We don’t know precisely how much renewable generation we’ll need at a given point; we need a lot, but there’s a risk in building it all, not least the additional cost it would place on consumers. Government’s instincts will always be to over-build; alternative mechanisms might take volume risk away from the billpayer.

Solutions to these challenges are varied:

Pot Zero

First put forward by UKERC, this calls for a new CfD ‘pot’ for existing renewables and low carbon power. Participation in this new auction would be voluntary – although some commentators have called for a ‘stick’ in the form of a windfall tax on non-participants – and would serve to provide existing generators with price stability for 5-10 years and consumers with a reduction in the overall cost of power. UKERC’s estimates of the value to consumers of this move range from £70-300 per household, although this analysis is explicitly high level. BEIS is considering this as a short term measure outside of the REMA process.

Green Power Pool

Proposed by Professor Michael Grubb, envisages the creation of a Green Power Pool. This would be a special entity established by Government that would offer long-term contracts to all low carbon plant, bundle up their output and sell them directly to consumers as well as any additional generation needed to balance their demand. In essence, this involves the creation of a Government-backer electricity supplier with a dominant position in the market, theoretically able to undercut other retailers through its exclusive access to cheap green power.

Wholesale Market Bifurcation

Different versions of this approach have been suggested by a number of commentators, including iGov and the Oxford Institute for Energy Studies. It draws on the insight that different types of generation have different levels of capital intensity, and that for high capex and low opex plants, cheap financing through revenue stability is likely to lead to lower costs. It removes these types of plant from the current wholesale market, which focuses on short-run costs, and instead places them into a long-run cost market where generators compete for long-term price stability contracts in a manner analogous to the CfD, except market-wide. The iGov proposal removes offtake risk for the long-run market by obliging suppliers to source power from it first before topping up in the short-run market.

Clean Electricity Mandate

Proposed by the Energy Systems Catapult, this solution involves walking away from the CfD mechanism and turning over contracting for low carbon generation entirely to suppliers. They would be obliged to contract for this generation by virtue of a legal obligation to only sell power at a certain carbon intensity, declining every year until hitting zero in 2035. While the mode of contracting is up to the supplier, this approach assumes long-term power purchase agreements will be the route taken. This would therefore move low carbon power out of the wholesale market.

Solving Stability

Restructuring the market to reduce the cost of integrating all these new assets is clearly a priority, and multiple solutions are on the table. In general, they involve increasing locational price signals for generation. This helps to ensure that the burden of managing grid constraints can be managed more effectively, and there are stronger signals to invest in particular locations – or, conversely, reduce investment where there’s not enough connectivity to get power out.

Nodal Pricing

This model replaces the UK’s current national wholesale price for power with hundreds of local prices set at places such as where the transmission network hands off power to the distribution system. Already used in a range of markets including Texas, California, Ontario and New Zealand, this would change the way in which generators dispatch from the current model in which they produce power in response to their contract or market conditions, and instead produce power on instruction from the system operator. Advocates argue it allows the more efficient running of thermal power stations and removes the need to pay constrained generators; detractors claim it disincentivises investment in assets like wind that need to be located at the edge of the system.

Local Balancing Markets

The UK’s power supply is currently balanced nationally every half hour. This approach instead creates a new balancing market divided into local areas. This would produce sharper prices for assets like aggregated demand side response, potentially encouraging more consumer participation in the system. It would also involve less market disruption than nodal pricing.

Granular Transmission Pricing

The costs of using the UK’s electricity transmission are normally set in advance on an annual basis. Given that these charges relate directly to the use of the physical assets necessary to get power out of a location, changing these charges to being set on a much more granular level could optimise the use of existing connectivity. These charges could be set either via some kind of standard methodology or through auctions for particular lengths of cable – so-called ‘wire-by-wire’ charging.

Next Steps

REMA is likely to take several years, as did EMR before it. The consultation against this broad array of options is now open, and will close in October. While the preference of officials will be to take the time needed to get to the right answer, we assume that the new Conservative leader will have a pressing need to cut costs as soon as possible. This autumn is likely to have an impact on energy policy in the UK that will resound for many years.

Contributer

Adam Bell Head of policy, Stonehaven

Adam Bell is head of energy policy at consultancy Stonehaven.

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