Locational pricing – how UK energy market reform could impact asset valuations

Locational pricing – how UK energy market reform could impact asset valuations

Thu 24 Nov 2022

Locational marginal pricing, if introduced, would represent the biggest change to the UK’s electricity market for decades, and its impact on asset valuations could be profound.

In May 2022, National Grid ESO published its Net Zero Market Report, which explored the current market design for electricity across Britain. The report concluded that:

  • “Britain’s electricity market needs to be substantially reformed if it is to deliver a net zero electricity system by 2035 at least cost to households and industry.”
  • “The current market design – based on a blanket national wholesale price for electricity – is no longer fit for purpose for a rapidly decarbonising system.”

In place of the current arrangements, the report recommended that Britain should move to a system which includes more explicit locational price elements (based on the marginal cost of electricity at each individual location) and where the decision as to which generators supplies power to the grid is determined centrally.  

This recommendation, known as locational marginal pricing (LMP), is now being considered as part of the UK government’s Review of Electricity Market Arrangements (REMA), a consultation on a broad range of potential energy market reforms.

REMA repeated the argument that the current system does not sufficiently or transparently incentivise investment in power generation in those areas where demand is highest. Assuming they can secure a grid connection, project developers do not have to pay much attention to which part of the grid their projects are connected to. The result, it is argued, is grid congestion and inefficiencies, increasing balancing costs which ultimately flow to consumers. The REMA consultation ran until mid-October and responses are now being analysed by Government. LMP is one of the most significant proposals under evaluation and there are many others who do a great job of explaining exactly what LMP is, including setting out some of the different options of LMP and how these differ from the current arrangements.1

But a key question is emerging that will likely shape whether the reform is adopted and in what form – how far will the introduction of LMP increase the cost of capital for existing and new renewable energy projects? 

Uncertainty about the potential costs and benefits of locational marginal pricing

In recent Ofgem workshops to model the potential impacts of LMP, FTI Consulting estimated that LMP would lead to potential net consumer benefits of £55bn with socio-economic benefits of £31bn between 2025 and 2040.2

FTI also considered the potential impact on the cost of capital but concluded that there is limited evidence that there would be an increase and that, if there were to be one, the magnitude is highly uncertain. For that reason, it didn’t include a higher cost of capital as part of its base case analysis and limited a sensitivity analysis in the latest Ofgem workshop to 25bps for CfD contract holders and 50bps for merchant power producers.

FTI argued that the cost of capital would need to go up by more than 200bps to wipe out the potential consumer benefits of LMP. A very different view has recently been provided by Frontier Economics, in a commissioned piece focusing on this question. Frontier Economics’ approach was to analyse the variability of pricing in existing locational pricing markets and apply the Sharpe ratio to assess the impact of higher standard deviations on required returns. Based on this, Frontier Economics concluded that the WACC could increase by between 180bps and 400bps, with a most likely range of 200bps to 300bps.

So who is right?

How locational marginal pricing is likely to increase risk for generators

There are two aspects of LMP that all commentators appear to accept and which we have also seen in other markets:

  1. LMP would lead to the transfer of curtailment risk to generators – in other words, generators would lose the right to export electricity to the grid. In other LMP markets, this has been mitigated through the use of hedging products known as financial transmission rights (FTRs). But there are question marks as to whether the FTR market could be deep enough to resolve this sufficiently and about the likely cost of FTRs.
  2. LMP would increase price volatility and uncertainty for generators. For instance, in areas of high renewable energy supply, there would likely be significant downward pressures on price when the wind blows (perhaps even leading to negative pricing), and potentially very high prices when it doesn’t. And price forecasts would need to be based on predictions of what other local projects are likely to be built, as these would expose generators to new competition. Of course, this volatility could also be positive for some projects – the question is how relevant this will prove to be for sectors such as onshore and offshore wind where there are strong other reasons driving the location of projects.3

It is likely that the factors described in both points 1 and 2 would impact the valuations of generation assets. But this would not purely be owing to their impact on the cost of capital.

How do investors evaluate curtailment risk currently?

When appraising opportunities across markets, our experience is that many investors – especially financial investors – are currently unwilling to accept that significant curtailment risk can be captured through a discount rate adjustment. Instead, they make changes to forecast cashflow assumptions. And if an assumption can’t be reasonably predicted, they often decide not to invest.  Similarly, debt providers would not usually reflect this risk through margin adjustments – they would require effective risk transfer, allowing a significant level of base case certainty and visibility of potential downside cases.

To the extent that curtailment risk could be mitigated through FTRs, investors would include the cost of these in their forecast cashflows and, assuming the FTRs are bankable, they would not need to model reduced output.

But curtailment risk, whether it is reflected in reduced revenue forecasts or an additional cost item, would nonetheless still have an impact on valuations.

How do investors price increased price volatility?  

The second risk – of heightened price volatility and uncertainty – would also be likely to affect valuations.

There are two potential elements to this risk. One is the possibility that projects which have benefitted from (or would benefit from) fixed-price offtake contracts, such as CfDs, become exposed to some locational pricing risk. To the extent that this risk can’t be hedged, it would likely impact directly on the cost of capital. And this impact can be quantified based on current market experience: investors currently value fully merchant renewable energy projects with unlevered equity discount rates of between 100 and 200bps higher than those for projects with medium-term fixed offtake pricing. Or to take another point of comparison: projects with a mix of ROCs and merchant revenues are typically valued with discount rates that are 50-100bps higher than CfD projects.4

A further element to consider is that projects already receiving merchant revenues become exposed to greater price volatility and unpredictability. We can learn here from experiences in the battery storage sector, which suggest that we should not expect a fixed impact on the cost of capital.

Battery projects relying on trading and arbitrage revenues are currently valued with discount rates between 300 and 400bps higher than those for solar projects with merchant power price risk. But at least some of this differential can be explained in terms of a lack of sector experience and track record, and slightly higher technical and health and safety risks. And as familiarity with and confidence in the sector increases among investors, discount rates for battery projects are starting to come down.

This could well be the experience with locational pricing too. It will take time to build investor confidence, and we can expect higher discount rates in this period until a track record is established and a threshold of predictability is reached. That threshold may be reached in some locations and not others; but once it has been achieved, discount rates may start to trend back towards those used for merchant projects in the current market.

Getting the details of locational marginal pricing right

Summing up the above, the introduction of LMP is likely to increase the levelised cost of investing in new and existing renewable energy projects. It does feel unrealistic to assume there will be no impact as part of a base case analysis of the costs and benefits of LMP.

It’s difficult though to reach firm conclusions on the extent of this impact as these are currently only outline reform proposals. The details are likely to really matter, with many important questions still to be answered. For instance:

  • How would locational pricing interact with CfDs?
  • Will the LMP system be zonal or nodal?
  • Would new arrangements just apply to transmission network assets, or also to smaller distribution network assets?
  • How will new arrangements impact on existing projects?
  • How will reforms interact with other aspects of the market and what transitional arrangements would be put in place?

These points matter not just because of their direct impact on specific projects, but also, more generally, because investor confidence has always been a key factor in driving discount rates. It affects them directly – because investment committees need a higher return to justify higher-risk investments. But it also affects them indirectly – because discount rates are also driven by the demand for assets, and heightened uncertainty typically discourages potential investors in the first place.

Well-implemented reforms may or may not have a net positive impact on the overall cost of energy across the energy market as a whole. But whether due to a higher cost of capital or lower cashflow assumptions or most likely both of these, it is unrealistic to think that transferring risk to generation projects will not impact on the cost of delivering and investing in those projects.

1 See the following as examples: Regen Insight Paper, Wild Texas Wind, 2022, National Audit Office, Electricity Balancing Services, 2014, UKERC, Exploring the implications of locational marginal pricing of electricity, 2022

2 Ofgen, workshop slides 20 October 2022

3 Such as wind speed, proximity to grid, likelihood of planning success etc. See Regen Insight Paper, Wild Texas Wind, 2022 for a discussion on the experience in Texas.

4 These and subsequent discount rate indications are based on recent transactional experience and published reports of listed funds.