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. 

                       
                 
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1 June 2022


ACER and CEER consult on the EU electricity forward market

ACER and CEER, Draft Policy Paper on the Further Development of the EU Electricity Forward Market for Consultation, 1 June 2022


April  2022

 

The ACER calls on the European Commission:

  • to extend in the possible review of the Forward Capacity Allocation Regulation the time horizon for the allocation of cross-zonal capacities beyond one year to stimulate liquidity in forward markets in longer horizons and 
  • to mandate TSOs to allocate long-term cross-zonal capacities in a way that enables the ‘coupling’ of national forward markets.

   

 

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 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).

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See also:

 

Forward transaction

 

Balancing market

 

Intraday electricity market

 

Day-ahead electricity market 

 

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.

 

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.

 

 

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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.

 

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