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Glossary · Energy industry & energy transition

FCA Guideline

FCA Guideline Forward Capacity Allocation electricity market futures market EU Hedging transmission capacity

The FCA Guideline is the European guideline for the long-term allocation of cross-border transmission capacity in the electricity market. FCA stands for Forward Capacity Allocation. It refers to Commission Regulation (EU) 2016/1719 of 26 September 2016. The regulation defines this allocation as the assignment of long-term cross-zonal capacity by auction, before the day-ahead timeframe. It also provides for a common methodology for calculating this capacity, a Europe-wide single allocation platform, and the return and transfer of acquired rights. It does not govern short-term electricity trading itself. Rather, the aim is to hedge against price differences between bidding zones that arise from grid congestion.

The term "capacity" here means neither power plant capacity nor a capacity market for security of supply. It refers to cross-zonal capacity, i.e. the ability of the interconnected system to transmit energy between two bidding zones, for example between Germany and a neighbouring country. A long-term transmission right applies to one border, one direction, one product period and a quantity in megawatts that is specified for each hour of the period. Transmission system operators issuing such rights must offer at least yearly and monthly products. At individual borders, further maturities are also available, such as quarterly products.

Objective: hedging cross-zonal price risks

According to the recitals, the regulation is intended to give generators, consumers and suppliers effective hedging opportunities against future price risks. This includes harmonising the previously inconsistent auction rules. An example: a supplier sells electricity for the coming year in bidding zone B, but procures it via a forward contract in zone A. If the interconnection is fully utilised, the day-ahead price in B can be significantly higher than in A. This difference would then be an unhedged loss. A long-term transmission right from A to B pays out the price difference in precisely these hours and fully or partially offsets the risk. It is therefore an instrument of hedging and a complement to the forward market. An electricity future hedges the price within a zone, whereas a transmission right hedges the price difference between two zones.

Types of long-term transmission rights

The regulation permits three forms: physical transmission rights (PTR) under the "use it or sell it" (UIOSI) principle, financial transmission rights as an option (FTR option) and financial transmission rights as an obligation (FTR obligation). They differ as follows:

  • PTR with UIOSI: The holder may nominate the capacity, i.e. actually use it for a cross-border schedule. If the holder does not nominate it, the capacity is reallocated in the day-ahead timeframe. The holder receives financial compensation for this, which as a rule is based on the day-ahead price difference between the two zones.

  • FTR option: It does not allow nomination, but pays the same compensation as an unused PTR. A payment is made only if the price difference in the purchased direction is positive. If the difference is reversed, the holder incurs no loss.

  • FTR obligation: It is provided for in law and works in both directions. The holder receives a positive price difference but must pay a negative one themselves. According to the sources reviewed here, this form is hardly used in current allocation practice.

Which form is offered at which border is decided for each border individually by the competent transmission system operators and authorities. Belgium, for example, offers FTR options at its borders with the Netherlands, France and Germany. The procedure is governed by the Europe-wide harmonised allocation rules (EU HAR): registration, collateral, bids, nomination, curtailment and compensation, return and transfer of rights, and force majeure.

Actors and procedures

The transmission system operators are primarily responsible. They jointly calculate long-term capacity in capacity calculation regions. The standard method is the coordinated NTC approach, which sets a maximum exchange quantity for each border. A flow-based approach is permitted if capacities between zones are strongly interdependent and the approach is more economically efficient. The capacity is then split between yearly and monthly auctions. The rights are auctioned via the single allocation platform. All transmission system operators have entrusted this task to the Joint Allocation Office (JAO), based in Luxembourg. The national regulatory authorities and the EU agency ACER approve the common methodologies. The sharing of congestion income from the long-term auctions is also regulated methodologically.

Distinction from the day-ahead market and market coupling

The CACM Regulation (EU) 2015/1222 applies to the day-ahead market and intraday trading. There, capacity is allocated implicitly together with energy via market coupling. The FCA Guideline operates earlier, namely months to about a year before delivery. The two levels are closely linked: the payout of transmission rights depends on the price differences resulting from day-ahead market coupling. Capacity that is not nominated flows back into daily allocation. Price differences between bidding zones are not a failure of market integration but indicate grid scarcity. The FCA rules ensure that the resulting risk can be hedged.

Obligation to issue rights and exceptions

Not every bidding zone border is strictly required to offer long-term transmission rights. Under Article 9(1) of the Electricity Market Regulation (EU) 2019/943, in the version applicable since July 2024: transmission system operators issue long-term transmission rights in accordance with the FCA Guideline or put equivalent measures in place. This is intended to enable market participants, expressly including operators of renewable installations, to hedge price risks. The obligation lapses only if, in a review of the forward market at the border, the competent regulatory authorities find sufficient hedging opportunities. If, on the other hand, they consider the opportunities insufficient, they may require power exchanges or grid operators to take additional measures, for example market making to increase liquidity. An example of market-based hedging without transmission rights is the Nordic model. There, forward transactions are referenced to a common system price and supplemented by price difference products.

Reform: longer maturities and virtual hubs

With the reform of the electricity market design (Regulation (EU) 2024/1747), Article 9 of the Electricity Market Regulation was recast. Long-term transmission rights must accordingly be allocated regularly, transparently, on a market basis and in a non-discriminatory manner via the single allocation platform. This platform is also intended to facilitate trading of the rights. The Commission was to submit an impact assessment by 17 January 2026. This was to examine several questions: more frequent allocations, maturities of at least three years, a changed type of rights, a stronger secondary market and regional virtual hubs. Such a hub is a non-physical region consisting of several bidding zones with a methodologically calculated reference price. On this basis, the Commission was to adopt an implementing act by 17 July 2026. ACER has proposed that rights in future be allocated between a bidding zone and a hub rather than for each border individually. Industry associations, by contrast, regard virtual hubs as risky for continental Europe. Whether and in what form these changes already apply should be checked on a case-by-case basis.

Common misunderstandings

  • No grid expansion: The guideline does not build lines and does not increase their capacity. It allocates and prices the capacity that, according to the calculation methodologies, can be offered in the long term. Structural congestion remains, but its economic consequences become hedgeable.

  • No delivery guarantee: A transmission right does not mean that a particular power plant delivers electricity to a particular customer abroad. Physical flows follow the laws of electrical engineering, not contracts. If a right is curtailed due to grid problems, the rules provide for compensation, which may be limited.

  • Not a capacity mechanism: "Forward capacity" has nothing to do with a capacity mechanism in which power plants or flexible loads are paid for their availability. The scarcity here lies at the border between price areas.

Bidding zones, congestion and system costs

Under EU law, a bidding zone is the largest geographical area within which energy can be traded without capacity allocation. Congestion within a zone therefore does not appear in the wholesale price but is managed through redispatch and similar measures. Between bidding zones, by contrast, congestion directly affects prices. The FCA Guideline does not determine how bidding zones are configured. However, it determines which hedging instruments exist at the existing borders. Price differences, congestion income, hedging costs and redispatch costs are interrelated but are booked in different places. Well-designed long-term capacity allocation can reduce risk premiums and support liquidity. It does not replace grid investment, careful review of bidding zones and good short-term market rules.

Sources

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Edited by eCMS on 11.11.2026 19:47

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