In this submission we focus on the allocation of wholesale market price risk, and how that affects both cost of capital and the likely availability of capital in the power market in Great Britain.

In this submission we focus on the allocation of wholesale market price risk, and how that affects both cost of capital and the likely availability of capital in the power market in Great Britain. The rising share of zero marginal cost generators such as wind and solar will have a significant impact on wholesale electricity prices, and the UK has set ambitious targets for such generators. The 40 GW offshore wind in 2030 target is the most obvious and immediate, but far greater roll out of zero carbon generation and a phasing out of unabated use of fossil fuels are prerequisites for net zero.

A key challenge for the UK is to galvanise a large volume of investment in a historically short timeframe. We are therefore concerned that many of the questions the consultation poses appear to presuppose the desirability of returning to a more ‘merchant’ or ‘market based’ solution space. This is highly problematic if the market in question is very similar to the largely energy-only market we have for the GB system today, where price is set by short run marginal costs.

Summary of UKERC’s position

UKERC takes as a starting point that policy has shifted from subsidising new investment in emerging technologies in order to promote innovation and reduce costs, to enabling investment at scale using low carbon options that are largely cost-competitive on a levelised basis. In many markets wind and solar investment can now be financed at contract prices at or below average wholesale price. However, this is often predicated on long run contracts and a highly credit worthy counterparty.

Questions remain about the underlying market designs that create incentives for flexibility and deliver best value for customers whilst also providing incentives for generators to invest in low carbon generation – in substantial volumes. A conventional ‘energy only’ wholesale/retail market is not well suited to deliver large volumes of new low carbon capacity at minimum cost to consumers. This is because a competitive wholesale market where price is set by short run marginal cost (SRMC) will, in the long-run, tend to under compensate participants who have a high sunk cost and very low SRMC. As a result, such markets are likely to fail to deliver the investment in low carbon generation needed to meet ambitious carbon reduction targets.

One reason for this is the problem known as ‘price cannibalisation’ where price falls to low levels or even goes negative during spells when wind or solar output is high and demand is low. Price cannibalisation has emerged as a phenomenon in a number of markets and in the GB market, a combination of subsidies from the Renewables Obligation and the CfD mean that price cannibalisation is already visible during periods of low demand as were observed during the first Covid-19 lockdown.

There is then a separate question regarding how best to provide investment signals for the flexibility needed to accommodate rising shares of low carbon generation and to provide essential system services – through storage, demand response, schedulable generation or interconnection. It is important that low-cost sources of flexibility come forward to accompany the growing role of renewable and other low carbon sources of bulk electricity.

Allocation of risk

Underlying all of this debate is the difficulty of satisfying the principle that risks should be allocated to those best able to manage them. In particular, we see two main types of risk:

  • Dynamic equilibrium These pertain to a situation where physical infrastructure has largely been established, supply and demand are roughly in balance, and investment is largely driven by the need for plant renewal and incorporation of new innovations, consumer demands and business models.
  • Non-equilibrium risks. These pertain to systems that are in a state of flux, shifting to substantially different infrastructure for supply and different patterns of demand, with many of these changes driven by policy, and very little historical pricing information to inform future investments.

For at least the next 10 years, to get substantially onto a trajectory of zero carbon electricity during the 2030s, and meet goals such as the 40 GW of offshore wind, the non-equilibrium risks are substantial. The policy-dependency of many of these risks makes them potentially unsuitable to be wholly managed by the private sector.

The relatively early stages of this transition are perhaps the most uncertain. To tackle the transition over the next 8-15 years, a pragmatic approach would be to continue to commit to CfDs, perhaps modified in ways discussed in this submission such as to include existing and repowering plant. Work could then take place in parallel on phasing in a new form of market that will facilitate the continuation of low carbon investment over the long-term.

Alternatives to CfDs

In the long-term, if CfDs are to be removed, there would likely need to be some alternative form of long-run marginal cost price signal. Various options available in a new ‘equilibrium’ world make it possible for these signals to be driven less by government procurement decisions (or those of a central agency) than is the case today. Whether that is desirable is something that needs to be considered carefully, based on an assessment of what would lead to a least cost outcome.

As we move into 2021, UKERC’s research will have a strong focus on these      challenges and we will work with government and wider stakeholders on transition plans and longer-term options for market reform. Given the urgency of the task perhaps the main immediate requirement is for pragmatism and learning by doing, fine tuning policies to enable action and ensuring that we do not allow the ‘best to be the enemy of the good’.