Quick Read

The Commission’s consultation (which we looked at here) did not signal significant market redesign, but rather strengthening of the regulatory framework to accelerate current direction of travel.

Stakeholders considered that short-term markets (day-ahead and intraday) and marginal pricing should be preserved because they function well, provide the right price signals, are well-developed, and are the result of years of implementation of EU energy legislation.

The challenge of mitigating high energy prices will be tackled by swifter delivery and integration of renewable energy, more efficient utilisation of the grid through increased use of flexibility services, and clearer and more regular communication around capacity for new grid connections. There are also efforts to ensure that offshore projects have adequate access to interconnector capacity.

There is a strong focus on accelerating renewable energy and ensuring price stability through long-term price signals to support project development, particularly by use of corporate Power Purchase Agreements (“PPAs”), support scheme contracts for difference (“CfDs”), and enhanced forward markets.

There are also measures around the contractual and trading structures for consumers, intended to protect against price volatility and enable them to reap rewards for providing demand response and flexibility services.

 

What instruments are involved?

The main instrument is a Proposal for a Regulation to amend the Internal Market in Electricity Regulation ((EU/2019/943) and Directive ((EU) 2019/944), the ACER Regulation ((EU) 2019/942), and the Renewable Energy Directive ((EU) 2018/2001).

There is also a Proposal for a Regulation to amend the REMIT Regulation ((EU) 1227/2011) and ACER Regulation ((EU) 2019/942) to improve protection against market manipulation.

Given the urgency involved, a Commission Staff Working Document was produced instead of impact assessments.

There is also a Recommendation on Energy Storage with an accompanying Staff Working Document.

 

Short-Term Market Liquidity

A main aim is to enable renewables to trade shortages or surpluses closer to the time of delivery to the grid, when they can more accurately predict output.

TSOs and NEMOs would be required to maximise opportunities to participate in intra-zonal trade (not just cross-zonal trade) as close as possible to real time. Markets would have to be organised to ensure sharing of liquidity between NEMOs. Intraday cross-zonal gate closure is required, by 1 January 2028, to be at earliest 30 minutes ahead of real time.

In Ireland, the continuous intraday market closes one hour before real time and recent market monitoring indicates it accounts for less than a percent of ex ante market share.

Minimum bid sizes of 100kW or less would have to be facilitated (down from 500kW) to allow effective participation of demand-side response, storage, and small-scale renewables, including direct participation by customers.

 

Peak Shaving

There would be a provision for TSOs to procure peak shaving products to reduce electricity demand during peak hours. Peak hours would be hours where there is the highest electricity consumption combined with a low level of renewable generation, taking cross-zonal exchanges into account.

The TSO would have to submit a proposal to the regulatory authority complying with several requirements. For example, the peak shaving product would not mean starting generation behind the metering point.

 

Flexibility and Grid

Flexibility would be defined as the ability of an electricity system to adjust to the variability of generation and consumption patterns and grid availability, across relevant market timeframes.

The proposals seek to enable consumers to participate in electricity markets and provide flexibility (such as demand response and storage), even where Member States have been slow to roll out smart meters. There is therefore provision for System Operators (“SOs”) to use data from dedicated metering devices for the observability and settlement of flexibility services.

To incentivise SOs to optimise the grid, network tariffs would have to take into account the operational and capital expenditures of SOs for operating the electricity system efficiently and in a way that supports flexibility services. Currently, regulatory authorities may introduce performance targets to provide incentives to SOs for these purposes.  This would become mandatory.

By 1 January 2025 and then every two years, regulatory authorities would have to assess the need for flexibility on the system for a period of at least five years. Member States would define indicative national objectives for demand side response and storage, monitored through NECPs.

Member States applying capacity mechanisms, as Ireland does, should consider promotion of non-fossil flexibility through use of criteria in mechanism design. Where this is insufficient to meet flexibility needs, Member States could apply flexibility support schemes.

 

Grid Development

Both TSOs and DSOs would be required to publish in a clear and transparent manner information on the available capacity for new connections, including in congested areas if flexible energy storage connections can be accommodated, and update that information regularly, at least quarterly.

They would also have to provide clear and transparent information to system users about the status and treatment of their connection requests, within three months from submission of the request.

It has become so commonplace in Ireland that connection applications sit indefinitely in processing queues that we have come to accept it, but it is not compatible with European law.

TSOs and DSOs would be obliged to cooperate with each other in publishing information on the capacity available for new connections in their respective areas of operation in a consistent manner and giving sufficient granular visibility to developers of new energy projects and other potential network users.

 

Offshore Grid Access

Recitals state that to reduce investment risk for offshore project developers and ensure projects have full access to surrounding markets, TSOs should guarantee access of the offshore project to the capacity of any hybrid interconnectors for all market time units.

Under the IME Regulation, when allocating congestion income, priority currently is given to guaranteeing availability of the allocated capacity and to maintaining or increasing cross-zonal capacity.

A third priority would be added: compensating offshore generators if access to interconnected markets has been reduced in such a way that one or more TSOs have not made enough capacity available on the interconnector or the critical network elements affecting the capacity of the interconnector, resulting in the offshore plant operator not being able to export its generation capability to the market.

 

Long-Term Stability: PPAs and CfDs

There is significant emphasis on putting in place the right regulatory framework to provide renewable energy investors with long-term certainty and price signals.

Member States would be obliged to facilitate PPAs and to ensure that instruments (such as guarantee schemes) are available to reduce the financial risks associated with off-taker payment default. They would have to ensure that PPAs are accessible to customers facing barriers to the PPA market, such as SMEs.

When designing renewable support schemes, Member States would have to allow participation of projects that reserve part of their electricity for sale outside the support scheme. Member States should use evaluation criteria, for example, to give preference to bidders who have a signed PPA or commitment to sign a PPA for part of the project’s generation to buyers facing entry barriers to the PPA market.

PPAs would have to specify the conditions under which customers and producers can exit them.

Direct price support schemes for wind, solar, geothermal, hydropower without reservoir, and nuclear would be required to take the form of a two-way CfD. New investments would have to include repowering and extending or prolonging the life of existing facilities. Revenues collected when the market price is above the strike price would have to be distributed to final electricity customers (without removing incentives to reduce or shift consumption). In Ireland, there is already a legislative basis whereby the Public Service Obligation is refunded to customers via supplier billing.

 

Long-term Stability: Forward Markets

The Commission states that suppliers and consumers need effective forward markets to cover long-term price exposure and decrease dependence on short-term prices.

The proposals would require establishment of regional virtual hubs with a view to overcoming existing market fragmentation and low liquidity. The hubs would reflect the aggregated price of multiple bidding zones and provide a reference price for market operators to offer forward hedging products.

ENTSO would be required to submit a proposal to ACER by 1 December 2024 which would include a methodology for the calculation of reference prices for the virtual hubs. It would have to be approved or amended within six months.

The role of the single allocation platform would be expanded to offer trading of financial long-term transmission rights between biding zones and virtual hubs; allocate long-term cross-zonal capacity on a regular basis; and offer trading of financial transmission rights that would allow holders to remove exposure to positive and negative price spreads, and with frequent maturities of up to at least three years ahead.

Where regulatory authorities consider there are insufficient hedging opportunities, they would be able to require power exchanges or TSOs to implement additional measures.

 

Customers

To protect customers from volatile prices, amendments to the IME Directive would provide an entitlement to fixed term, fixed price electricity supply contracts up to a duration of one year, which could include a flexible element with peak and off-peak price variations.

There is clarification that customers would be entitled to have more than one metering and billing point covered by the single connection point to their premises, relating to their entitlement to have more than one electricity supply contract.

The proposals build on the Clean Energy Package framework for active customers by providing for ‘energy sharing’ (without the need to establish energy communities). This would relate to energy generated or stored by a facility the active customers own, lease, or rent, or else energy the right to which has been transferred to them by another active customer. All households, SMEs and public bodies would have the right to participate in energy sharing, including by way of a third-party facilitator.  Conditions are set out to facilitate netting-off of shared energy against metered consumption in a time interval no longer than the imbalance settlement period, to facilitate calculation of the energy only component.

Regulatory authorities would have responsibility for ensuring that suppliers have appropriate hedging strategies to limit the risk of changes to the economic viability of their contracts with customers.

Where there are sufficiently developed PPA markets, Member States would be able to require that a share of suppliers’ risk exposure to wholesale electricity prices is covered using PPAs.  Hedging products should be available to citizen energy communities and renewable energy communities. Member States would have to appoint suppliers of last resort.

There would be a power for the Commission to declare a regional or EU-wide electricity price crisis during which time Member States may temporarily intervene in price setting for the supply of electricity.

 

Storage

Storage is considered, in addition to the proposals outlined above, in a Recommendation on Energy Storage and accompanying Staff Working Document.

The Commission notes the fundamental place of storage in energy transition, particularly in less interconnected systems such as Ireland, and that different technologies can provide diverse services on different scales and at different timeframes. It notes that off-grid storage also has an important role, for example in individual and district heating systems.

While EU market design allows storage to participate in all markets, which facilitates revenue stacking, accessing finance is a challenge because of the need for long-term visibility and predictability of revenue streams.

The Commission makes ten recommendations. Several aim to guide Member States and regulatory authorities in effective integration of storage in market and grid regulatory frameworks.

Member States should also identify potential financing gaps for short-, medium- and long-term storage and consider the need for financing instruments that provide visibility and predictability of revenues.

Member States should explore whether storage services are sufficiently remunerated and whether operators can add up the remuneration of several services.

Member States should consider competitive bidding processes and explore improvements in the design of capacity mechanisms, for example by ensuring that de-rating factors are appropriate, reducing minimum eligible capacity, facilitating aggregation or prioritising greener technologies.

Comparatively isolated systems should accelerate the deployment of storage, for example through support schemes for low carbon flexible resources, and should revise the network connection criteria to promote hybrid energy projects.

To facilitate investment decisions for new storage facilities, real time detailed data should be published on congestion, curtailment, market prices, renewable energy, emission content and installed energy storage facilities.

 

Evolution but Fast

As we previously commented here, the focus is on how to achieve current objectives.  The proposals should be used as a tool by market participants to raise awareness about the current barriers they face and to strengthen the case for their solutions to progress project delivery and ensure optimal market functioning.

There is laudable ambition in Ireland around climate goals but timely delivery of infrastructure will require resourcing of the consenting process, investment in enabling infrastructure (particularly the grid), appropriate incentivisation of provision of system services, refinements of market rules and an economically efficient risk allocation as between project developers and TSOs.

There is existing legislation designed to achieve this, but the new proposals provide helpful obligations and frameworks to bolster the principles that already underpin market design.