Steep increases in wholesale gas prices over the last 2 years have prompted a raft of interventions as policymakers at EU and national level have sought to cushion the impact on energy consumers. We explored the drivers behind price increases, and the short-term policy response at a webinar in December last year.
A concern among some stakeholders has been the impact of higher gas prices on the price of electricity. Higher gas prices have incentivised some switching to other fuels to generate electricity. But in periods when gas-fired generation is nevertheless still required to balance the system, the current “marginal pricing” model for electricity means that higher gas prices translate into higher electricity prices. Higher power prices are earned by all capacity with lower running costs than gas-fired generation, despite their costs being largely unaltered by the current crisis. As such, policymakers have sought to identify and claw back so-called “windfall profits” – with low-carbon generation in particular being a target given typically low running costs. As we noted at our December webinar, the devil in the design of such claw back or “revenue cap” mechanisms is often in the detail.
While prices have subsided somewhat since their peaks, they remain elevated. Clearly, part of the policy response to higher prices will involve “hardware” upgrades: deploying more low-carbon energy and boosting energy efficiency will tend to reduce the influence of gas prices on customer bills. However, the transition will not happen overnight, and indeed decarbonisation may lead to higher (not lower) electricity demand as the transport and heat sectors electrify.
As a result, policymakers have also been considering “software” upgrades: reforms to “market design” to increase the resilience of electricity prices faced by consumers to external shocks.
Main aspects of the Commission's EMD reform proposal
The EU Commission launched a public consultation on 23 January 2023. The Commission has since published legislative proposals for reforms, including in the following key areas:
- Power Purchase Agreements (PPAs): removing barriers for long-term contracts between producers and consumers for low-carbon energy production;
- Support schemes for low-carbon generation: advocating (long-term) two-way Contracts for Difference (CfDs) – which stabilise the price received by plants - as the default method for supporting new investments in low-carbon generation – both new-build and lifetime extensions or “re-powering” of existing sites;
- Peak Shaving Product: enabling TSOs to procure demand reduction during peak hours;
- Flexibility needs: requesting national regulators to assess system flexibility needs and allowing member states to design support schemes for non-fossil flexibility investments;
- Regional virtual hubs: pooling liquidity on forward markets covering different bidding zones; and
- Supplier hedging: Member States are to ensure energy retailers have appropriate hedging strategies in place to limit their exposure to wholesale price shocks.
Many open questions
While some of the proposals brought forward in the market design discussion were pushing for a far-reaching reform (e.g. those from Spain and Greece), the Commission now seems to favour more targeted adjustments in line with what was recommended by regulators and industry associations (e.g. ACER, Eurelectric). These more incremental measures are mainly focused on reducing price volatility through long-term contracts, enhanced flexibility and demand reduction, and public interventions in price setting in case of emergencies. However, understandably given the speed at which proposals were developed, a number of key questions remain to be addressed.
The common thread running through the Spanish and Greek proposals as well as the Commission’s proposals on CfDs and PPAs is that stabilising prices for investors (and, in so doing, limiting the potential for investors in renewables to profit from unexpected increases in wholesale prices) should help stabilise prices for electricity consumers. However, doing so necessarily involves reducing investors’ exposure to market signals (which, among other things, help to indicate the value to the system of producing power at different points in time). If investors do not factor in the full impacts of their decisions on the system, this in turn implies a greater role for policymakers in steering the future technology mix. This does not appear to have been explicitly acknowledged by policymakers.
In addition, the simultaneous emphasis on supplier hedging and longer-term contracting for low-carbon generation also raises tensions. In the UK, the government has recognised in its ongoing assessment of electricity market design that increasing amounts of renewable capacity on CfDs, incentivised primarily to trade in short-term (‘spot’) markets, may have led to a mismatch between the risk management preferences of generators and suppliers, since the latter typically seek to purchase longer-dated contracts. But equally, the precise role of suppliers in ensuring price stability for consumers in a world in which governments are themselves providing financial hedges via CfDs requires further consideration.
The desire to promote low-carbon flexibility is understandable and important, and previous Frontier work has considered the business case for technologies such as storage and the barriers that may affect it in current market design. However, the precise definitions of “peak shaving” and “flexibility” (which is multi-dimensional) in the Commission’s proposal remain vague. It is unclear how such products would differ from, and interact with, existing products already available, such as response to wholesale price signals (both short-term and long-term), reserve products that grid operators can already procure under current rules or capacity mechanisms. The requirements for flexibility support schemes appear to be far less strict than requirements for capacity mechanisms are currently.
The proposed rules for regional virtual hubs for the forward market provide ACER and ENTSO-E with far-reaching authority to define these hubs, without requiring prior market consultation. While the main objective of this measure is to enhance forward liquidity by allowing participants to better manage risks related to cross-border price differences, it may open the door for more granular locational wholesale price signals (smaller bidding zones, and potentially nodal pricing in the future). It will be important that this does not divert attention away from another instrument to increase liquidity: enlarging bidding zones by congestion relieving investments into the transmission grid. According to the EC proposal, the new established single allocation platform shall issue and allocate long-term transmission rights between virtual hubs and bidding zones. This raises some questions e.g. whether there will be parallel long-term transmission rights between bidding zones issued by TSOs and between the hub and bidding zones; parallel trading hubs, i.e. a regional virtual hub covering more than one bidding zones, and another trading hub within a bidding zone.
As these examples of open questions indicate, EU co-legislators will have a busy time finalising the legislation. In doing this, they will need to consider the balance between the role of competitive markets and the role of policymakers in steering investment and operational decisions. This will be crucial to set the right guidelines for maintaining economic growth and energy security on the way to full decarbonization by 2050. That said, given the upcoming EU elections in 2024, it may well be that this is not the final word on EU electricity market design.
 Our report on flexibility platforms for ENTSO-E is cited in the Commission Staff Working Document accompanying the proposal.