Assessing the implications of zonal pricing for support payments in the GB electricity market

As part of its ongoing REMA programme, DESNZ is considering the introduction of a zonal wholesale electricity market in Great Britain (GB). 

The implications of this change would be significant so this topic continues to spark debate across the GB energy industry.  We have highlighted previously the need for any assessment of zonal pricing to balance any of the claimed efficiency benefits against potential wider system implications – in particular investor risk and the cost of capital. 

In a zonal market investors are more exposed to changes in the prices and sales volumes they are able to achieve as a result of congestion on the network.  For many plant, these changes in prices and volumes are likely to create more uncertainty than would result from transmission charge (TNUoS) volatility in a national market and would likely translate into an increase in the investor’s cost of capital. 

Assessing the impact of market design changes on investor cost of capital directly is not straightforward.  Frontier and LCP Delta were commissioned by SSE to examine the impact that this increase in risk could have on the level of CfD and capacity payments using a simplified approach.  The results will depend on the particular CfD design chosen and on the range of scenarios which individual investors consider credible.  Our analysis draws on LCP Delta’s simulations of zonal pricing in Great Britain, using data produced across all the scenarios and sensitivities analysed.

Based on these inputs, we show that compared to a national market, an archetypal offshore windfarm in Scotland is likely to require a significantly higher strike price in a zonal market for two reasons: 

  • First, future wholesale market revenues would be significantly lower on average in the zonal market due to congestion; and  

  • Second, the distribution of its returns across a range of different scenarios for local supply, demand and network development would be greater in a zonal market (compared to a national market with TNUoS volatility) which investors would need to take into account by increasing their strike price bid.   

The analysis also suggests implications for the next CfD allocation round (AR7) in March 2025.  Depending on policy decisions made by the time of the auction, bidders may face transitional uncertainty if a zonal market is to be implemented during the term of the CfD.  For example, will the CfD reference price be the local zonal price or a system average price, and what degree of protection will be offered by transitional arrangements?  Our analysis shows that the outcome of these decisions will be highly material for strike price bids, and therefore continuing uncertainty may drive high risk premia or low participation in future auction rounds. 

We also analyse the implications for dispatchable plants where the impacts of a zonal market on risk are more uncertain and likely to depend on the extent to which a plant is already exposed to locational risk in the Balancing Market (BM) under the national market.  We find for a new-build dispatchable plant earning a mix of wholesale and BM revenues that the distribution of capacity payments across the zonal market scenarios required to achieve a target rate of return is wider than the distribution in a national market driven by locational TNUoS risk and BM revenue risk.