With an ambition to fully decarbonise the electricity system by 2035, the British power system will rely primarily on renewable generation technologies – wind and solar – whose output cannot be controlled in the way fossil-fuelled generation has been. To keep the costs of such a system manageable and avoid unacceptable supply interruptions, responsiveness or ‘flexibility’ needs to come from dedicated assets (storage) and demand response.

The Review of Electricity Market Arrangements (REMA) presents an important opportunity to design a system that supports large volumes of both renewable generation and flexibility in mutually supportive ways.

To date, debate around the REMA consultation and related work on energy market reforms has tended to present a conflict between investment in renewable generation and investment in flexibility.

Proponents of the former favour keeping market arrangements broadly unchanged, particularly with regard to renewables’ exposure to price signals. Proponents of the latter favour the introduction of sharper price signals in time and space. This short report seeks to bridge the gap between these two extreme positions by drawing on insights from international markets.

Key points

As part of our Rethinking Electricity Markets project, Energy Systems Catapult reviewed the evidence from markets across the US and in New Zealand that use locational marginal pricing (LMP), as well as European markets that use zonal pricing. While no electricity system can be said to have fully solved the challenge of how to integrate high volumes of intermittent renewables, we make general observations that are relevant to the GB debate.

LMP is not an obstacle to large-scale investment in renewable generation.

• US markets vary considerably in the strength of decarbonisation policy drivers, but have generally seen high levels of investment in renewables – for example, New York and California have seen 2.2GW and 3.5GW of wind capacity, respectively, have come online since those markets introduced LMP.
• US markets have adopted different structural approaches to incentivising investment in clean energy rather than centralised procurement. Investment in renewables in  US markets has tended to rely on tradeable renewable energy certificates, while there are also examples of merchant renewables investment and ongoing development of contracting and hedging approaches. This highlights the importance of designing support schemes for renewables that work together with the underlying market design (e.g. LMP in the wholesale market) but do not distort the underlying price signals.
• We were not able to find conclusive evidence that sharper price signals in LMP markets increased the cost of capital for generators, despite some commentators making that link.

The GB electricity market could benefit from a different technology mix that would emerge under LMP markets.

• US markets with LMP have typically seen more deployment of storage than European markets with zonal or uniform prices. This observation cannot be attributed entirely to nodal price signals – mandates on storage deployment (in California) and overlays such as a capacity market (in PJM) likely played a role. Nevertheless, storage is disproportionately located in US markets that use LMP: despite only making up 58% of grid capacity in the US, those markets make up 74% of large-scale battery storage power capacity (GW) and 72% of energy capacity (GWh).
• There is also emerging evidence from US markets of storage being co-located with renewable generation – allowing intermittent renewables to behave like price-responsive assets in LMP.

Overall, we find that Britain does not need to choose between a market that works for investors in renewables and a market that works for investors in flexibility – both can be successfully accommodated by learning from international experience.