Forward electricity markets

Category: European Union Electricity Market Glossary

Published: 11 January 2017

Last Updated: 19 March 2024

Competitive and liquid forward electricity markets are essential for market participants (equally, producers as well as consumers) to hedge their short-term (e.g. day-ahead) price risks and uncertainties. 

This is due to the fact that in the modern electricity market trading is possible many years ahead physical delivery (also with the use of purely financial deals) and can continue until one day before delivery. 

The utilities typically hedge up to 3 years ahead and have the respective hedging schedules imposed by their boards with percentages of their hedging to be reached for each year by the end of that deadline.

European energy market regulators see the long-term market “as an equilibrium of interests of consumers and generators/investors to hedge against the uncertain future” (document of 14 February 2023 “ACER-CEER Reaction to the European Commission’s public consultation on electricity market design”). With this respect, a liquid forward market where consumers and generators can hedge at any time any future would be for the regulators an ideal market outcome. However, for various reasons such markets have not developed and instead alternatives such as power purchase agreements (PPAs) and contracts for difference (CfDs) have gained momentum. Private PPAs can be seen as filling the gap of non-functioning forward markets beyond 3 years ahead, where hedging interest exists on both sides, but the organised market still has not developed enough (due to e.g. insufficient supply and demand, inadequate market design, high hedging costs). On the other hand, CfDs or other state contracts may have been developed to cover the gap between the lack of consumers’ interest to enter long-term contracts (with implicit hope that the states will protect them in periods of high prices and shortages)and significant producers’ interest to enter long-term contracts especially in times of high regulatory uncertainty.

The forward market refers to transactions from years to weeks ahead of delivery, precisely a “forward” contract is considered any electricity transaction concluded more than a day before delivery. The forward market is the most prominent electricity market when it comes to the number of transactions (88% of transactions), followed by spot markets covering day-ahead (11%) and intraday (1%) timeframes. The geographical scope is also, theoretically, unlimited within the EU, given the availability of long term transmission rights (LTTRs), physical or financial, between bidding zones.

The fundamental EU legal framework governing the above issues (with the cross-zonal focus) is stipulated in the Network Code on Forward Capacity Allocation (FCA).

When it comes to terminology, long-term standardised instruments traded in organised venues are usually called “futures”, while the term “forwards” is reserved for products that are unstandardised and traded OTC (i.e. on the bilateral basis).

Nevertheless, in more general sense the term “forward electricity market” covers both types of above products.

ACER/CEER Annual Report on the Results of Monitoring the Internal Electricity Market in 2014 (November 2015, p. 175, 176) underlined the fact that different types of participants may expect different benefits from forward markets:

a) established players will see forward markets as an additional tool for managing their risk, they usually hold various forms of physical options (including generation units, permanent or semi-permanent customer bases, etc.), which can act as hedging instruments to protect against future price changes; 


b) new entrant generation businesses will be looking to lock long-run prices in to cover for their fixed-cost exposure to investment sunk costs; such players will look for hedging instruments which lock in prices over the investment timeframe (up to 15 years or even more); 


c) new entrant supply businesses will be looking to lock in wholesale prices, for instance up to two years ahead, to match the expected revenues from their projected customers base; and 


d) commodity traders will see forward energy products as part of a larger risk management portfolio, their core business is speculation – taking market positions and profit from fluctuations in the price of the underlying assets – and they contribute to the liquidity in forward markets. 


The structure of European forward markets diverges significantly:

- in a majority of markets most forward market volumes are traded over the counter (including cleared and non-cleared OTC),
- in the Nordic markets the largest share is traded at the power exchange (53% in 2016),
- in Germany/Austria/Luxembourg, the share of volumes traded at the power exchange was 35% in 2016 (ACER/CEER, Annual Report on the Results of Monitoring the Internal Electricity and Gas Markets in 2016, Electricity Wholesale Markets Volume, October 2017, p. 41). 

The ACER/CEER Annual Report on the Results of Monitoring the Internal Electricity Market in 2015 (September 2016, p. 33) referred in turn to the low liquidity of forward markets in Europe in 2015 with the main exceptions being Germany, the Nordic area, France and Great Britain. The highest growth in the same period was recorded in the French forward market.

The analogous ACER and CEER report published in 2018 for the year 2017 observed that:

- the biggest bidding zone in Europe (Germany/Austria/Luxembourg) recorded the highest level of liquidity in forward markets,
- France and Great Britain were also among the forward markets with the highest liquidity,
- other relatively large bidding zones such as Spain or Poland recorded much lower levels of forward market liquidity.

The regulators’ conclusion is that, besides the bidding zone’s configuration, other factors, such as market concentration, the level of market integration or market maturity, influence the forward market’s liquidity more decisively.  

According to the ENTSO-E policy paper of December 2022 on the EU's Electricity Forward Markets electricity futures are listed for all bidding zones in Europe, including countries that are not part of the European Union but are interconnected and coupled with EU markets (such as UK, Switzerland and Norway). Financially-settled futures are the reference electricity product for trading and hedging across Europe. The European Energy Exchange (EEX) is the European largest marketplace for the exchange of power derivatives, listing futures on markets across the entire of Europe. EEX also lists electricity options for the main European markets (Germany, France, Spain and Italy).

Additional marketplaces for electricity derivatives include:

• Nasdaq, which lists futures for the Nordic region, as well as German and French futures;
• the Intercontinental Exchange (ICE), which lists futures for Germany, the Baltic region, Italy, France, the UK, Netherlands, Belgium, Austria, Switzerland and Spain, as well as options for the German, French and Italian markets;
• the Operador do Mercado Ibérico de Energia - Pólo Português (OMIP), which lists futures for the Spanish, Portuguese, German and French markets, as well as options and physically-settled forwards for the Spanish and Portuguese markets; and
• the national exchanges in Italy (GME), Greece (HEnEx), Austria (Wiener Boerse) and Hungary (HuDEx), which list futures contracts for their respective national markets (in the case of Italy, physically-settled forwards).

Financially-settled futures represent  by far the most liquid products in the European forward markets, but similar considerations apply also to physically-settled forwards that present the same payoff structure. Given their payoff structure, the value of financial futures is determined as the expected average spot price of electricity during the delivery period. Otherwise stated, at any given point in time, the price of the futures reflects the expectation of the market regarding the spot electricity prices over the delivery period.

The liquidity of the EU electricity forward market was the major concern for the ACER-CEER document of 14 February 2023 "Reaction to the European Commission’s public consultation on electricity market design". In the document the EU energy market regulators observe that only the German bidding zone has sufficiently high liquidity in its electricity forward market (and even then, only for futures products up to three years to delivery). Hedging products of all other EU zones have liquidity issues, which directly impact the hedging opportunities of the market participants. Over the last years, it seems that as a general trend across the continent, the liquidity of the forward markets is decreasing. Poor liquidity for a hedging product increases the bid-ask spread and forces market participants on one side to pay higher risk premium (and the other side receiving it) or to find proxy hedging solutions in other zones which very often do not protect against the risk sufficiently.

The persistence of high absolute values of assessed risk premia in the valuation of long term transmission rights and of Electricity Price Area Differentials (EPADs) point to different problems in the markets for these products, which are crucial for efficient cross-border trading. For instance, transmission right prices reflect inefficiencies such as lack of market coupling, the presence of curtailments in combination with weak firmness regimes, and periods of maintenance reducing the offered capacity, which dampen the value of transmission rights. Also the Commission Staff Working Document of 30 November 2016 accompanying the Commission Final Report of the Sector Inquiry on Capacity Mechanisms ({COM(2016) 752 final} SWD(2016) 385 final, p. 35) underlines the importance of the the cross-border access to forward markets in the context of a limited number of liquid forward markets in Europe. The said Commission Staff Working Document of 30 November 2016 refers, however, to the fact that the cross-border access to forward markets depends on the market design. 

In most of Europe the cross-border access to forward markets is based on transmission rights, either Physical Transmission Rights (PTRs) or Financial Transmission Rights (FTRs), issued by Transmission System Operators (TSOs), which enable market participants to hedge short-term price differentials between two neighbouring bidding zones. In the Nordic and Baltic markets and within Italy, cross-border access to forward markets is based on contracts which cover the difference between the relevant "hub" price (which represents the forward price reference for a group of bidding zones) and each specific bidding zone price. Examples of these contracts are the EPADs in the Nordic and Baltic markets or FTRs within Italy. 

The aforementioned Commission Staff Working Document of 30.11.2016 (p. 40) argues that the maximum price in any forward market is constrained by the maximum prices charged in the balancing market, which functions as an implicit price cap for electricity prices in forward markets. Some EU Member States were, at the time of the document, having no price caps in the balancing market or experiencing prices reflecting the value of lost load (VOLL) even when there has been scarcity.  This can be the case when the balancing price, while not being subject to a cap, does not reflect the full cost of the services used to balance the market or the full cost of the unmet consumer demand (represented by VOLL). Member States should therefore ensure that balancing market rules, even in the absence of an explicit price cap, do reflect the full costs of balancing and do not implicitly constrain electricity prices in forward markets.

European forward electricity market designs

ACER/CEER Annual Report on the Results of Monitoring the Internal Electricity Market in 2014, November 2015 (p. 175, 176) points to the fact that, in general, the cross-border access to forward markets depends on the market design. In Europe, two such forward market designs have emerged. 

The first design, implemented in the Nordic and Baltic countries and within Italy, relies mainly on the market and a variety of products developed through the various market platforms. This design contains a set of hedging contracts for a group of bidding zones, and these contracts are linked to a hub (or system) price, which represents either a physically unconstrained day-ahead price, as in the case of the Nordic and Baltic areas, or some sort of an average day-ahead price within this group of zones, as in the case of the Italian area (multi-zone hub). In this design, market participants can hedge the bidding zone price risk by combining a forward product in order to hedge the hub price, with a contract for differences which covers the difference between the hub price and the bidding zone price. Examples of contract for differences are the Electricity Price Area Differentials (EPADs) in the Nordic market or financial transmission rights (FTRs) within Italy. Contracts for differences are particularly needed when the hub and bidding zone prices are not sufficiently correlated.

The second design, implemented in nearly all Member States in Continental Europe, is based on a set of hedging contracts for each bidding zone which are linked to the day ahead clearing price of this bidding zone (single-zone hub). These contracts may be sufficient to hedge the price risk of market participants. However, some market participants located in a given bidding zone may want to use a hedging contract of a neighbouring bidding zone in order to hedge their exposure to risk. This could be a sufficient hedge if prices in the two zones are highly correlated. Otherwise, they would need an additional hedging tool to cover the price differential between the two zones. In this context, the second design gives an additional and specific role to TSOs. They are responsible for calculating long term capacities in a coordinated way and for auctioning (either physical or financial) transmission rights (PTRs or FTRs), enabling market participants to hedge against the specific risk of short-term zonal price differentials.

In Continental Europe the establishment of the Single Allocation Platform for allocating long term transmission rights will replace the current local or regional ones.

Uniform legal framework for the EU forward electricity markets according to current rules

The so-called Winter Energy Package (Clean Energy for all Europeans - CEP) establishes the uniform legal framework for the EU forward electricity markets. According to the Article 9 of the Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity (recast) TSOs are required to issue long-term transmission rights or have equivalent measures in place to allow for market participants, including owners of power-generation facilities using renewable energies, to hedge price risks across bidding zone borders, unless an assessment of the forward market on the bidding zone borders performed by the competent regulatory authorities shows that there are sufficient hedging opportunities in the concerned bidding zones. The said Article 9 of the said Regulation (EU) 2019/943 envisions that the long-term transmission rights must be allocated in a transparent, market based and non-discriminatory manner through a single allocation platform,

The Regulation stipulated, moreover, that subject to compliance with Union competition law, market operators are free to develop forward hedging products, including long-term forward hedging products, to provide market participants, including owners of power-generating facilities using renewable energy sources, with appropriate possibilities for hedging financial risks against price fluctuations.

Article 9 of the Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity (recast) Forward markets  1. In accordance with Regulation (EU) 2016/1719, transmission system operators shall issue long-term transmission rights or have equivalent measures in place to allow for market participants, including owners of power-generating facilities using renewable energy sources, to hedge price risks across bidding zone borders, unless an assessment of the forward market on the bidding zone borders performed by the competent regulatory authorities shows that there are sufficient hedging opportunities in the concerned bidding zones. 2. Long-term transmission rights shall be allocated in a transparent, market based and non-discriminatory manner through a single allocation platform.  3. Subject to compliance with Union competition law, market operators shall be free to develop forward hedging products, including long-term forward hedging products, to provide market participants, including owners of power-generating facilities using renewable energy sources, with appropriate possibilities for hedging financial risks against price fluctuations. Member States shall not require that such hedging activity be limited to trades within a Member State or bidding zone.

Shortcomings of the current forward electricity market design

ACER and CEER Draft Policy Paper of 1 June 2022 on the Further Development of the EU Electricity Forward Market for Consultation observes that existing electricity forward markets in the EU suffer from a number of problems which prevent achieving the objective of an effective and efficient electricity forward market. The main shortcoming of existing forward markets is that they do not function as a single integrated forward market. This objective was achieved in the day-ahead and intraday timeframe (soon also in the balancing timeframe) with the help of (implicit) cross-zonal capacity allocation. However, in the forward timeframe, the long-term capacity allocation is not designed in a way that would integrate national forward markets in the most efficient way.

ACER and CEER identify three policy options for the type of regulatory intervention aiming to address the identified problems with better allocation of long-term cross-zonal capacities. These are:

(i) allocation of zone-to-hub Financial Transmission Rights by TSOs

(ii) market coupling with Contracts for Differences and

(iii) market coupling with energy futures.

All three options involve allocation of long-term cross-zonal capacities by TSOs (either explicit or implicit) in timeframes up to three years ahead of delivery. In case TSOs allocate long-term transmission rights, ACER and CEER also recommend that these are allocated in a form of FTR obligations and not FTR options or PTRs. The EU Member States must not restrict such hedging activity to trades within a Member State or bidding zone.

In turn, in the Final Assessment of the EU Wholesale Electricity Market Design published in April 2022 the ACER assessed that a possible review by the European Commission of the Forward Capacity Allocation Regulation could take on board mandating TSOs to allocate long-term cross-zonal capacities in a way that enables the ‘coupling’ of national forward markets - as in the single day-ahead and intraday coupling - to provide an efficient pooling of liquidity in forward markets. According to the ACER extending the time horizon for the allocation of cross-zonal capacities beyond one year would stimulate liquidity in forward markets in longer horizons, TSOs should also maximise the long-term cross-zonal capacity, as a prerequisite for well-functioning and integrated forward markets.

The above policy options materialised in concrete propositions set out in the ACER’s policy paper on the further development of the EU electricity forward market of 6 February 2023.

The said document concludes that under the current legal framework, each zone has its own market (with the exception of the Nordic region) bridged by transmission rights issued by the TSOs. Unlike the day-ahead and intraday markets, the EU forward market does not work as a single integrated EU market. This problem has been partially addressed in the short term markets through the allocation of cross zonal capacities. Therefore, the ACER proposes a set of changes to improve the functioning of the EU electricity forward market:

• creation of virtual trading hubs combined with the issuance of transmission rights between bidding zones and those hubs;
• improved allocation of the transmission rights (more frequent, over longer period of time, in revised quantities) by the TSOs;
• transmission rights issued in the form of financial obligations; and
• optionally, the possibility to assign market making tasks.

Contracts for difference (CfDs) as an instrument of the EU electricity forward market reform

On 23 January 2023 the European Commission announced public consultations on the reform of the EU’s electricity market design. The consultation document considers, among other things, also the contracts for difference (CfDs) as an instrument of the EU electricity forward market reform. The EU energy market regulators views in this regard are presented in the document of 14 February 2023 “ACER-CEER Reaction to the European Commission’s public consultation on electricity market design".

As opposite to the typical two-way CfDs considered, which entail:

(i) the state as a single buyer, 

(ii) settlement with single strike price (typically against the day-ahead electricity market price) and produced volume and 

(iii) direct settlement with all consumers through taxes and levies (bonus or malus);

“ACER and CEER would have less concerns with smarter design of CfDs” which could entail the following improvements:

1. settlement based on predefined volume or reference volume (e.g. reference wind turbine);

2. cap and floor instead of single strike price. The floor price can replace the system of subsidies, whereas the cap price can replace the inframarginal revenue cap to channel excessive revenues back to consumers; and

3. reselling of CfDs as financial contracts (e.g. futures) in forward markets closer to delivery (up to 3 years) and no direct settlement with consumers.

Given the above, ACER and CEER at this stage cannot support EU actions mandating the use of CfDs or similar type of state long-term contracts. This is because the optimal design of CfDs is not known yet and because the EU Member States can achieve the objective of protecting consumers through other means as well (e.g. limit excessive inframarginal revenue, taxation policy, (energy) poverty policy, etc.). 

Nevertheless, Member States may be allowed to use such mechanisms to meet their objectives. In such case, this mechanism should only be implemented after a thorough assessment of negative effects on other Member States and the European electricity market and only with a State Aid approval. In case of negative effects these instruments should only be implemented if the benefits surpass cost on a European level.

Regarding the forward market up to 3 years ahead, ACER identifies several potential improvements:

1. reduce hedging disincentives by designing better investment support (e.g. RES subsidies, CfDs) and/or consumer protection schemes that have less negative impact on forward markets;
2. revise the Regulation on Forward Capacity Allocation to introduce several changes:
- introduction of regional hubs complemented by zone-to-hub transmission rights,
- improvement of the access to financial transmission rights with adequate cross-zonal capacities, longer term maturities, more frequent auctions and secondary market through continuous access.

ACER also identifies 3 policies that could further strengthen the forward market beyond three years ahead:

1. adjusting collateral requirements and risk management policies at organised marketplaces defined in the financial regulation to have them better fitting the energy markets (e.g. reducing collateral requirements or their required quality or reducing risk management standard) possibly combined with state guarantees for participants with physical assets (producers, consumers),

2. adjusting trading and settlement arrangements (for example instead of continuous trading, auctions could be organised),

3. educating consumers about risks and opportunities when entering supply contracts. 

This should include the benefits of long-term fixed price contracts, potentially linked to collective investments in generation capacity, as well as their possible risks. This may be complemented with clear signals of government inviting consumers to seek protection themselves if they want to be protected from high prices.

Reform of the forward electricity market design - 2023 

On 14 March 2023 the European Commission proposed reform of the EU electricity market design “to boost renewables, better protect consumers and enhance industrial competitiveness”.

The package of measures covered, inter alia, the Proposal for a Regulation of the European Parliament and the Council amending Regulations (EU) 2019/943 and (EU) 2019/942 as well as Directives (EU) 2018/2001 and (EU) 2019/944 to improve the Union’s electricity market design, which in Article 1(6) replaces the wording of Article 9 of the Regulation (EU) 2019/943. The legislative project alludes to the above ACER and CEER analyses, in particular to zone-to-hub construct (the establishment of regional virtual hubs for the forward market).

The competence to submit the respective proposal is granted to the ENTSO for Electricity (after having consulted ESMA). The proposal for the establishment of regional virtual hubs for the forward market shall be submitted by 1 December 2024 to ACER and shall:

(a) define the geographical scope of the virtual hubs for the forward market, including the bidding zones constituting these hubs, aiming to maximise the price correlation between the reference prices and the prices of the bidding zones constituting virtual hubs; 

(b) include a methodology for the calculation of the reference prices for the virtual hubs for the forward market, aiming to maximise the correlations between the reference price and the prices of the bidding zones constituting a virtual hub; such methodology shall be applicable to all virtual hubs and based on predefined objective criteria; 

(c) include a definition of financial long-term transmission rights from bidding zones to the virtual hubs for the forward market.

According to the legislative proposal the single allocation platform (SAP) shall: 

(a) offer trading of long-term transmission rights between each bidding zone and virtual hub; where a bidding zone is not part of a virtual hub it may issue financial long-term transmission rights to a virtual hub or to other bidding zones that are part of the same capacity calculation region; 

(b) allocate long-term cross-zonal capacity on a regular basis and in a transparent, marketbased and non-discriminatory manner; the frequency of allocation of the long-term cross-zonal capacity shall support the efficient functioning of the forward market; and 

(c) offer trading of financial transmission rights that shall allow holders of these financial transmission rights to remove exposure to positive and negative price spreads, and with frequent maturities of up to at least three years ahead. 

European Commission Proposal of 14 March 2023 for a Regulation of the European Parliament and the Council amending Regulations (EU) 2019/943 and (EU) 2019/942 as well as Directives (EU) 2018/2001 and (EU) 2019/944 to improve the Union’s electricity market design, Article 1(6)

Amendments to Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity

Regulation (EU) 2019/943 is amended as follows:

Article 9 of the Regulation (EU) 2019/943 is replaced by the following:

“Article 9 

1. By 1 December 2024 the ENTSO for Electricity shall submit to ACER, after having consulted ESMA, a proposal for the establishment of regional virtual hubs for the forward market. The proposal shall: 
(a) define the geographical scope of the virtual hubs for the forward market, including the bidding zones constituting these hubs, aiming to maximise the price correlation between the reference prices and the prices of the bidding zones constituting virtual hubs; 
(b) include a methodology for the calculation of the reference prices for the virtual hubs for the forward market, aiming to maximise the correlations between the reference price and the prices of the bidding zones constituting a virtual hub; such methodology shall be applicable to all virtual hubs and based on predefined objective criteria; 
(c) include a definition of financial long-term transmission rights from bidding zones to the virtual hubs for the forward market;
(d) maximise the trading opportunities for hedging products referencing the virtual hubs for the forward market as well as for long term transmission rights from bidding zones to virtual hubs. 
2. Within six months of receipt of the proposal on the establishment of the regional virtual hubs for the forward market, ACER shall evaluate it and either approve or amend it. In the latter case, ACER shall consult the ENTSO for Electricity before adopting the amendments. The adopted proposal shall be published on ACER's website. 
3. The single allocation platform established in accordance with Regulation (EU) 2016/1719 shall have a legal form as referred to in Annex II to Directive (EU) 2017/1132 of the European Parliament and of the Council. 
4. The single allocation platform shall: 
(a) offer trading of long-term transmission rights between each bidding zone and virtual hub; where a bidding zone is not part of a virtual hub it may issue financial long-term transmission rights to a virtual hub or to other bidding zones that are part of the same capacity calculation region; 
(b) allocate long-term cross-zonal capacity on a regular basis and in a transparent, marketbased and non-discriminatory manner; the frequency of allocation of the long-term cross-zonal capacity shall support the efficient functioning of the forward market; 
(c) offer trading of financial transmission rights that shall allow holders of these financial transmission rights to remove exposure to positive and negative price spreads, and with frequent maturities of up to at least three years ahead. 
5. Where a regulatory authority considers that there are insufficient hedging opportunities available for market participants, and after consultation of relevant financial market competent authorities in case the forward markets concern financial instruments as defined under Article 4(1)(15), it may require power exchanges or transmission system operators to implement additional measures, such as market-making activities, to improve the liquidity of the forward market. Subject to compliance with Union competition law and with Directive (EU) 2014/65 and Regulations (EU) 648/2012 and 600/2014, market operators shall be free to develop forward hedging products, including long-term forward hedging products, to provide market participants, including owners of power-generating facilities using renewable energy sources, with appropriate possibilities for hedging financial risks against price fluctuations. Member States shall not require that such hedging activity may be limited to trades within a Member State or bidding zone”.

According to ENTSO-E (ENTSO-E's Response to the European Commission Public Consultation on Electricity Market Design) “zone-to-hub FTRs could be complementary instruments to the default zone-to-zone products. This can be beneficial for providing stable hedging opportunities for market participants in small, illiquid bidding zones. As an alternative for the forward market of their own illiquid market, they would prefer to hedge themselves on the hub forward market if this one has more liquidity. Via zone-to-hub, FTR market participants can adequately hedge themselves against the price differences of the spot price of their own market against the fixed forward contract on the hub”. Moreover, “a hub makes it easier for market participants to trade between non-neighbouring bidding zones.”

Also the ACER in its policy paper of 6 February 2023 on the further development of the EU electricity forward market identifies that zone-to-hub FTRs is the most suitable option to support the forward market. This is expected to attract and gather liquidity of national forward markets into regional hubs. These regional hubs promise to attract much higher liquidity than national forward markets and are independent on the size and change of bidding zones. Nevertheless, such regional hubs must be complemented by liquid or frequently accessible zone-to-hub FTRs. Thereby zone-to-hub FTRs should be complemented by an improved calculation and allocation of long-term crosszonal capacities by TSOs in timeframes up to three years ahead of delivery with more frequent allocation of cross-zonal capacities. 

Nevertheless, ENTSO-E in its reaction of 31 March 2023 warns that: "Implementing Regional Virtual Hubs, a theoretical and still untested approach, would require long implementation times (5-10 years as estimated by ACER) and may lead to significant costs and risks for TSOs, grid users and market participants". ENTSO-E elaborates on these risks and proposes the following alternatives to the proposed CfDs design. In injection-based CfDs, the operators receive/provide a payment corresponding to the difference between the strike price and day-ahead prices multiplied by the energy volumes injected by the renewable installation. Just as with strictly one-sided CfDs (i.e., support when prices are low), operators are incentivized to maximize the production volume, regardless of the actual market situation (“produce and forget”), with the following adverse effects:

• RES installations feed-in even if the day-ahead prices are negative;

• market-based intraday curtailment or provision of negative balancing services is limited to situations where the price drops below (- strike price);

• prevention (e.g. by full reservation of the capacity) or demotivation of participation in complementary short-term markets (balancing, ancillary services);

In addition, in a 2-sided injection-based CfD policy makers should be aware that there are many more cases where distortions occur. In certain situations, it can lead to artificially increased costs of RES energy and RES sources intentionally reducing production. To ensure incentives for optimal dispatch behaviour, volumes paid out under CfDs should be decoupled from the actual injection. Examples are:

• capability-based CfDs: power plant owners compete in an auction for a fixed strike price. The payment is based on the volumes that “could” be produced by the installation, based on technical characteristics and local weather conditions, such a signal is already used by some TSOs in balancing products.

• financial CfDs: the government provides a fixed hourly lump-sum, the generator pays the government the hourly spot market revenues – but not the actual revenues, but benchmark revenues based on a reference profile.

The design of these measures can vary. The preferred design is a matter of further discussion, but it seems highly feasible to come up with an efficient solution. Each option brings the advantage that they eliminate distortive dispatch incentives in the short-term markets of injection-based CfDs. With capability-based CfDs, the revenue of the producer is not affected by welfare-enhancing measures such as (introduction of new bidding zones, the commissioning of new interconnectors...). In addition, the granularity of the volume definition is specific to the plant, which should lower risk for the generator owner and suppress costs of the mechanism. Financial CfDs directly incentivize to optimize market revenues. This means that operators will plan maintenance during expected low-price periods. In addition, there is a stimulus for the diversification within the technology classes to reduce cannibalization effects (e.g., PV systems with an east/west orientation or low wind turbines). An advantage from the perspective of the operators is that they also have a hedge for the generation volume. In a low-wind month, spot revenues are low, but so is the payback to the state.

Considering all these problems involved, among the options ENTSO-E (ENTSO-E's Response of December 2022 to the European Commission Public Consultation on Electricity Market Design) sees even the possibility of a completely new approach, which terminates the LTTRs market in its current form. This (alternative) policy option relies on the purely financial forward electricity markets where the long-term market evolves without TSOs, and hedging products for the future will be developed based on need by other market operators. Terminating the LTTR market is expected to reduce the complexity of the overall forward market, increase its flexibility and support the formation of correct long-term electricity prices. 

Further ENTSO-E document of 26 October 2023 „Legislative proposal for a Regulation to improve the Union’s electricity market design, ENTSO-E assessment - trilogues” refers to this issue as follows:

„As per design improvements to Forward Markets (Art. 9), we fully support the approach of the EP which replaces the mandatory introduction of Regional Virtual Hubs (RVH) with a step-wise process prior to any legislative change, to be introduced via the existing Forward Capacity Allocation (FCA) Guideline. Such approach includes both an assessment of practical solutions addressing market participants' hedging needs, and an assessment of the implications of Regional Virtual Hubs (RVHs) complemented by an extensive consultation prior to any implementation decision. To avoid preempting the outcome of such key assessments and consultation, the final text should not explicitly indicate (as currently defined in the Council proposal) that RVHs are the ultimate target model for forward markets. Moreover, to avoid inconsistencies with the current legislative framework set in the FCA Guideline, the regulation should not introduce deadlines for the allocation of longer maturities (up to at least 3 years ahead) of transmission rights. The implementation of specific products should be defined via the FCA guideline respecting due processes and realistic timelines. As such, we call for the Council text to align with EP proposal on this point. Lastly, the Council text should also align with the EP in leaving the possibility of alternative hedging instruments for market parties and not exclusively Long-Term Transmission Rights issued by TSOs”.

The Electricity Market Design Package agreed on 14 December 2023 (Proposal for a Regulation of the European Parliament and of the Council amending Regulations (EU) 2019/943 and (EU) 2019/942 as well as Directives (EU) 2018/2001 and (EU) 2019/944 to improve the Union’s electricity market design) in Recital 21 clarifies that virtual regional hubs "if introduced, virtual hubs would reflect the aggregated price of multiple bidding zones and provide a reference price, which should be used by market operators to offer forward hedging products. To that extent, virtual hubs should not be understood as entities arranging or executing transactions. The regional virtual hubs, by providing a reference price index, would enable the pooling of liquidity and provide additional hedging opportunities to market participants”.

Moreover, implementing powers have been conferred on the European Commission to set out detailed rules on the design of the Union’s electricity forward market as regards the establishment of regional virtual hubs. 

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