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Offshore wind is in the worst possible place – literally

The UK electricity sector stands on the cusp of monumental change. The ongoing Reform of Electricity Market Arrangements (REMA), a cornerstone of the UK government’s strategy to decarbonise the power sector in 12 short years, brings both promise and peril.

Policymakers face the unenviable task of unpicking the quasi-infinite complexity of wholesale power market design, layered as it is with numerous sub-markets and defunct but grandfathered legacy subsidy regimes. They must then design a new system that resolves the classic trilemma of the energy transition: delivering secure, affordable and clean electricity for a population of more than 60 million people unevenly spread across the British Isles.

REMA is a minefield of unintended consequences. Years of successive regulatory interventions have left the UK with a patchwork of policies and support regimes. Policy siloes that might at first glance appear targeted and discrete are in fact interwoven in a complex web of co-dependencies, meaning there are precious few ‘no-regrets’ decisions on the table.

Before setting a direction of travel, there is a philosophical question facing the Department for Energy Security and Net Zero (DESNZ): should power sector reform take an evolutionary approach, or seek to revolutionise every aspect of the market?

A shift to either zonal and nodal pricing is laden with opportunity and dangers for new and established sectors of the economy

Evolution or revolution?

The ‘evolution versus revolution’ divide neatly defines the sides taken in the debate around the most contentious aspect of REMA: the contemplation of Locational Marginal Pricing (LMP), a regulatory intervention that would reshape the energy landscape. LMP would move from national pricing in British wholesale electricity markets to location-based pricing at each zone or node on the transmission network.

A shift to either zonal and nodal pricing is laden with opportunity and dangers for new and established sectors of the economy. The UK offshore wind industry, which is already facing a crisis of confidence, sees LMP as a major threat to its growth prospects.

Wind investors generally acknowledge the need to improve the strength and transparency of existing locational signals in the GB market, both for long-term investment decisions and short-term operational efficiency. But lobbyists are almost unanimous in their antipathy towards LMP since the downside risks substantially outweigh the touted benefits.

In theory, locational wholesale pricing would site generation capacity where it is most needed (e.g. close to demand centres) and discourage development where it is not (i.e. in remote areas of the network). It would also herald a fundamental change in how assets operate by moving from a self-dispatch model – where each generator chooses when to ramp up and down – to one of centralised dispatch – where these decisions are taken by the system operator, National Grid ESO (NGESO). This pushes a whole new category of risk – dispatch risk – onto wind investors, potentially driving up their cost of capital.

LMP is seen by its proponents, such as NGESO, non-profit quango Energy Systems Catapult and some utilities, as vital to stimulating system flexibility. Nodal pricing favours location-agnostic dispatchable generation, energy storage assets and demand-side response providers that will play a central role balancing a zero-emissions power sector dominated by variable-output renewables.

Flexibility vs. generation

The current national price model shields wind generators from their impact on system balancing costs, and dulls the incentive to invest in flexible assets by papering over the cost of resolving supply-demand imbalances. It also creates perverse incentives, for example rewarding grid-connected batteries located behind a network constraint to dispatch when the system requires them to recharge. LMP, in theory, fixes this.

However, in doing so it penalises generation in some of the UK’s best wind hotspots. Offshore wind farms are uniquely constrained in their ability to capitalise on locational price signals, either at the pre-development or operational stage of their lifecycle. Vast swathes of the North Sea are by definition located far away from demand centres and thus highly likely to be subject to lower wholesale pricing under any locational methodology.

Until there is clarity on forward price patterns and effective hedging strategies, such revolutionary reform presents a clear risk of investment hiatus while the new rules are thrashed out and have time to bed in. Wind investors and project developers forced home this message in the government’s initial REMA consultation.

The siting of offshore projects is, the industry argues, already determined by resource availability, marine spatial planning and the Crown Estate’s seabed leasing process. The Crown Estate itself made this point to government. A spokesperson told efwd that, while it is for the government and regulator to decide on LMP, “[w]e indicated in our response to the initial consultation that the locations for offshore wind power over the coming years have largely been set through seabed leasing processes, with these decisions underpinned by detailed analysis of the technical resource, spatial characterisation, and constraints on the seabed.”

Network charges are locational

The UK electricity market is not devoid of locational price signals. These are already present in Transmission Network Use of System (TNUoS) charges, which are designed to recover the cost of installing and maintaining the electricity transmission system in England, Wales, Scotland, onshore and offshore. Regulator Ofgem is in the process of reforming TNUoS methodology and is considering increasing the granularity of locational charging zones beyond the 27 currently in use. The wind industry argues that taking a decision now to impose LMP would preempt that work.

“TNUoS has an extremely strong locational element for generation, which is potentially even too strong, although the way it is delivered reduces its ability to drive well informed investment decisions,” renewables trade body Regen said in a recent paper. TNUoS charges are forecast five years ahead, but they impact wind farms throughout their 15-year Contract for Difference (CfD), so developers must second-guess future rate changes and try to cover these costs when bidding for CfDs.

To minimise shortfall risk, wind developers incorporate worst-case charge assumptions into their CfD bidding strategy. And since CfD auctions are pay-as-clear, higher TNUoS charges in Scotland drive up the clearing price for all participating generators, regardless of their location.

TNUoS charges broadly correlate with structural supply-demand imbalances: generators in Scotland pay roughly £6-7 per MWh more than those in south-east England and Wales, and this differential is set to rise significantly to as much as £15 per MWh in the coming years, Regen predicts.

TNUos charges are normally presented in £/kW of installed capacity per year. For the current year, the highest charge for intermittent generation is £31/kW/year in zone 4 (Skye and Lochalsh). This is forecast to rise to £45/kW/year in 2028/29.

The lowest charge, -£11/kW/year in zone 22 (Cotswold), will fall even further below zero to -£15/kW/year, meaning generators will not only get paid to connect in this zone, but the payments will increase.In its latest TNUoS forecast, covering the 2029/30 to 2033/34 period, NGESO sees zone 4 charges peaking at £73/kW/year, while zone 22 charges will fall as low as -£33/kW/year.

Gridlocked grid

The relationship between LMP and transmission constraints is, to put it mildly, complex. There are compelling reasons to believe that nodal pricing would both help and hinder the UK’s grid bottleneck.

Among the many sources of friction to achieving the government’s stated ambition for 50GW of offshore wind by 2030 is the lengthy queue for a grid connection. Projects wait on average 6.5 years for a firm connection and lead times can reach up to 15 years, according to Regen. The connection queue now stands at more than 140 projects representing in excess of 300GW – three times Britain’s total generation capacity, according to Tim Pick, the UK’s previous Offshore Wind Champion.

Wind lobbyists argue that ramping up transmission capacity will render locational pricing unnecessary by resolving network constraints that LMP is intended to fix. And since there is no escaping the need for colossal grid upgrades to deliver the 50GW offshore target, LMP is already obsolete.

Constrained logic

The underlying thesis supporting zonal or nodal pricing rests on location-specific price signals driving the efficient allocation of resources, be they generation capacity, flexible demand or transmission upgrades. This concept supports two somewhat contradictory analyses of how LMP resolves grid constraints.

On the one hand, proponents of LMP describe a ‘transmission first’ approach as akin to building more roads to fix traffic jams: it fails to attack the source of the problem. Generating more electrons close to demand centres is a more cost-efficient solution than building out costly infrastructure to support generation in far-flung regions.

On the other hand, there is a school of thought that reflecting grid imbalances via locational price signals would support a programme of rapid transmission upgrades by identifying constraints and driving investment into grid pinch-points.

This raises the question: if the cheapest solution to a persistent network constraint under LMP is to discourage generation behind that constraint, will there still be an investment case for expanding the network? If not, how will the UK achieve the capacity expansions required to decarbonise the power sector?

Out of balance

NGESO’s support for LMP is rooted in an urgent need to tame the spiralling cost of balancing the grid. The system operator sees this problem as a function of the current market’s failure to price in the locational value of electricity either side of a network bottleneck.

The main component of grid balancing costs is constraint payments to turn down excess wind capacity behind a grid pinch-point and fire up gas-fired generation on the other side. Notably, the cost of powering up gas turbines is consistently and significantly higher than the amount that wind farms bid to curtail output.

So far this year, NGESO has paid £117 million to fire up gas plants and £37 million to constrain wind farms. The net cost to consumers from wind constraint payments is actually less than this, because constrained generators lose their CfD or Renewables Obligation (RO) support payments.

Constraint payments increased eight-fold since 2010 to hit £507 million in 2021, when a spike in global commodity prices ratcheted up the cost of powering up gas-fired power generators. Costs could spiral as high as £3-5 billion per year by 2035 “even after more transmission and distribution lines are built,” Energy Systems Catapult says

Under today’s self-dispatch model, balancing the network in this way is known as ‘redispatch’, and is conducted through the system operator’s Balancing Market (BM). But the situation is becoming untenable: NGESO regularly redispatches more than 50% of demand in any settlement period, up from 10% in 2008.

“The ESO is effectively at times acting as central dispatcher but under very condensed gate closure timescales. This undermines the light-touch balancing role envisaged for ESO when the current market design was introduced,” NGESO says.

With the system operator already acting as a de-facto central dispatch controller, the switch to centralised dispatch under nodal or zonal pricing would in a sense only formalise and codify current ad-hoc dispatch arrangements. In this sense, LMP simplifies matters and should – in theory – reduce overall system costs.

Capital punishment

Policymakers are always grappling with the trade-off between protecting consumers and rewarding investors. If LMP lowers system costs as its proponents claim, then there is a strongly held view that this will come at the expense of cost of capital for offshore wind projects. This downside, together with the inevitable delays of implementing such radical reform, outweighs the benefits of LMP – many of which are seen as theoretical or speculative. 

Cost of capital is an increasingly important metric in a decarbonising grid. A power sector dominated by capital-intensive, zero marginal cost generation must offer revenue certainty, which the current national price model combined with CfDs provides. If the price formation rulebook is torn up and rewritten, that certainty goes out the window – and with it, investor confidence.

This is the strongest argument in favour of an evolutionary, rather than revolutionary, approach to REMA. Countless proposals for incremental reform have been tabled in the hope of presenting less disruptive means of achieving REMA’s objectives. These include tweaking the CfD with longer duration contracts, a cap and floor for strike prices or revenues, longer CfD reference price periods, or even introduce a ‘locational CfD’, among others. All eyes are now on the imminent next phase of REMA consultation to understand which way DESNZ is leaning.

Investment hiatus?

Considering the unsustainability of current market arrangements, reform – and therefore REMA – is entirely necessary. But the process is so fraught with complexity, and the various technical arguments on both sides of the LMP debate so compelling, that the process is at risk of becoming a lobbyists’ charter.

Weighing the pros and cons is a daunting task, yet one that officials at DESNZ must strive to do – and quickly, in order to stem the rising sense that the UK is wading into a period of prolonged regulatory delay, just as the rest of the world rolls out the red carpet to wind investors and supply chain companies.

The most radical proposals of REMA guarantee short term pain for many if not all market participants; whether they will deliver long-term gain remains an open question. Any decision to pursue ‘revolutionary’ market interventions such as LMP will require detailed cost-benefit analysis that makes a compelling case. With acute international competition for capital, the investment community will need reassurance that the UK’s offshore wind industry remains open for business.

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