Transmission Marketplaces
(1)
Dept. of Accounting and Commercial Law, Hanken School of Economics, Vaasa, Finland
5.1 General Remarks
Transmission capacity is allocated in the transmission marketplace. The allocation methods can be market-based (explicit or implicit auctions) or not market-based (bilateral contracting). One can also distinguish between primary and secondary capacity markets.
Producers
Electricity producers need a transmission marketplace because electricity cannot be supplied without transmission capacity.1 Their actions are influenced by the regulation and structure of the transmission marketplace. For example, risk management and investment in both generation and transmission assets can depend on whether electricity producers may use bilateral contracting and long-term contracts in their dealings with transmission service providers. Moreover, investment in generation assets and energy-intensive industrial processes can depend on whether the regulation of transmission costs and prices is designed to give market participants locational signals. The fact that these signals have so far been weak may have helped to increase the distance between electricity generation and consumption.
Monopoly
Electricity transmission is a natural monopoly. TSOs are natural sellers of transmission capacity rights and the only players in a position to offer the required firm transmission hedges (see Chap. 12).2 The regulatory authorities will fix or approve the transmission tariffs or their methodologies, and monitor the TSOs’ capacity allocation and congestion management rules.3 Electricity firms will have to adapt to the relevant TSO’s rules.
Operation and Ownership of Transmission Assets
In principle, transmission assets could be owned and operated in different ways. (a) They could be owned and operated by one entity or by different entities and (b) the assets could be part of a system operation business (in which case they are owned by the TSO) or a stand-alone business (in which case they are not owned by the TSO).
In the EU, the main rule is that transmission assets must be owned by the TSO. This is one of the cornerstones of ownership unbundling. Ownership unbundling is regarded as necessary to remove “the incentive for vertically integrated undertakings to discriminate against competitors as regards network access and investment”.4
Ownership unbundling works in three ways in transmission. First, each undertaking which owns a transmission system must also act as a TSO.5 Cross-border joint-ventures between two or more TSOs are nevertheless permitted.6 Second, there are restrictions on such an undertaking’s right to own a business that performs any of the functions of generation or supply.7 Third, the same restrictions govern the rights of a firm that performs any of the functions of generation or supply to own a TSO.8
In other words, ownership unbundling implies “the appointment of the network owner as the system operator and its independence from any supply and production interests”.
In the US, transmission assets are not owned by the system operator. The entities responsible for managing system operations are Regional Transmission Organizations (RTOs) or Independent System Operators (ISOs).
The restructuring of the industry began with the Public Utility Regulatory Policies Act of 1978. Transmission was opened up by the Energy Policy Act of 1992 which was complemented by FERC’s Orders No. 888 (in 1996) and No. 2000 (in 1999). Open access to transmission services was designed to foster the independent operation of the power grid. FERC believed that RTOs/ISOs were the best means to implement the open access provisions of the Energy Policy Act of 1992. Neither Congress nor FERC have forced the owners of transmission assets to cede control over the assets to independent operators. Section 219(c) of the Energy Policy Act of 2005 offered rate incentives to owners of transmission assets that joined RTOs/ISOs.9
Even in the EU, there are system operators that do not own the transmission system. A Member State may designate an independent system operator (ISO) under certain circumstances.10 An ISO in the European sense is independent of the owner of transmission assets and owns computing and communication assets.11 Merchant lines raise the question whether the can be transmission systems that are not owned by a TSO (these issues are not discussed in this book).
Characteristic Problems
The TSO faces certain characteristic problems related to capacity and pricing (for characteristic problems inherent in transmission contracts, see Sect. 10.1). First, the TSO must possess enough transmission capacity and prices should cover costs. Capacity costs are the TSO’s most important cost factor. Prices should facilitate long-term investment in the transmission grid and cover short-term costs for the use of the system. Second, scarce transmission capacity should be allocated. Capacity cannot be allocated without information about estimated and actual use and congestion. Actual use and congestion can be estimated in advance but become known in real-time or later. Loop flows make it more difficult to predict actual use.12
Actual electricity flows depend on many things ranging from changes in load to the weather. They also depend on loop flows caused by Kirchhoff’s laws. Any transaction between two nodes of a meshed network induces some flow in each of its lines.
Loop flows cause two problems. First, loop flow makes it more difficult to determine actual flow-based paths (parallel flows) when multiple users compete on the same transmission system.13 Second, loop flow can also make it more difficult to forecast the actual use of the transmission system. The more transactions and the more meshed the network, the higher the chance for mismatch between commercial exchanges and physical flows.14
Mechanisms for the Allocation of Transmission Capacity
Scarce transmission capacity cannot be allocated without information about congestion. One can, therefore, distinguish between: (a) methods used for electricity flows in the more distant future when congestion can only be estimated; and (b) methods that are used when actual congestion is known.
The mechanisms for the allocation of transmission capacity necessarily consist of three components. As the allocation of transmission capacity means bringing together a market participant, a designated electricity flow, and transmission capacity, it is necessary to: allocate transmission capacity to a market participant; allocate transmission capacity to a designated electricity flow; and allocate costs and the price.
When transmission capacity is allocated for electricity flows in the more distant future, it is customary to use a combination of market-based or not market-based mechanisms (Sect. 5.3).
Mechanisms that are not market-based include first-come-first-served (priority list), pro-rata rationing, and retention. The first-come-first-served (priority list) mechanism means here the allocation of capacity according to the order in which the transmission requests have been received by the TSO. Pro-rata rationing means that all requests are partially accepted and partially curtailed in proportion to the requested capacity. Retention means that a proportion of the available capacity is reserved by electricity producers, suppliers, or large end consumers under long-term contracts. There are legal constraints on the use of long-term contracts (Sect. 5.2).
To work properly, the market-based methods would require the existence of competition in the market.15 The market based-methods include explicit auctions and implicit auctions.
Models for the Allocation of Transmission Capacity Between Designated Flows
It is not enough to choose a mechanism for the allocation of transmission capacity between market participants. The transmission capacity must also be allocated between designated electricity flows.
One can choose between different models for this purpose (Sect. 5.4). They can be combined with the chosen mechanism for the allocation of transmission capacity between market participants. The most important factors influencing the choice of the model are the general market model (complete vertical integration or liberalised market) and the structure of the grid. In liberalised electricity markets, one can distinguish between four high-level models for the allocation of transmission capacity: (1) the contract path model; (2) the flow-based model; (3) the point-to-point model with implicit flows; and (4) the entry-exit model.
Pricing Models
The mechanism for capacity allocation goes hand in hand with the pricing model (Sect. 5.7).
The pricing model can influence the behaviour of the users of the transmission system by giving locational and temporal signals for electricity supply (feed-in) and extraction (load). (a) Transmission infrastructure is used in a more efficient way when the signals reflect the costs caused by grid users. The existence of such signals contributes to the efficient use of transmission infrastructure in particular where the transmission system is well interconnected and has several alternative sources of supply. (b) The absence of signals that reflect costs implies that costs are socialised. This reduces the efficiency of the use of infrastructure.17
Transmission tariffs can have a strong impact on investments in electricity generation and transmission assets.18
EU Law and National Practices
Some of the many models have been adopted at EU level for the purposes of the allocation (Sect. 5.6) and pricing (Sect. 5.8) of transmission capacity. There is still variation between the practices of different markets and different Member States of the EU although the EU Congestion Management Guidelines19 have contributed to the convergence of practices.
Disclosure, Market Conduct and Market Abuse Regime
Much of the regulation of transmission and transmission marketplaces is sector-specific. This reflects the fact that transmission capacity is allocated by the TSO that has a duty to manage electricity flows on the system.20
On the other hand, transmission marketplaces may partly be governed by the same statutory disclosure, market conduct, and market abuse regime as other physical electricity marketplaces (see Sect. 4.7 and 4.10.1): (a) Obviously, this regime must apply where transmission capacity is allocated implicitly. (b) Moreover, TSOs and other primary owners of data relating to transportation have a disclosure duty under Regulation 543/2013 amending Annex I to Regulation 714/2009.21 (c) REMIT that regulates disclosure and reporting obligations and prohibits market abuse applies to transmission markets in the EU as they are regarded as wholesale energy markets and to transmission contracts as they are regarded as “transportation” contracts. REMIT applies to transportation contracts and related derivatives provided that they are traded but irrespective of where and how they are traded.22 The definition of wholesale energy products is very broad according to the wording of REMIT23 and ACER Guidance on the application of REMIT.24 (d) It is again clear that the MiFID II/MiFIR regime does not apply to pure transmission marketplaces as transmission contracts are not financial instruments. Neither does EMIR that applies to OTC derivatives.
5.2 Long-Term Contracts
Long-term contracts are a customary way for electricity firms to manage risk. The prohibition of long-term contracts would have a negative impact on long-term investment. For instance, where access to the grid and the use of transmission capacity cannot be secured in advance, investments in new generation capacity are subject to a higher risk. The higher risk exposure of investors could hamper investment and reduce security of supply in the long term.
Even transmission firms may need long-term contracts to reduce investment risk, increase the availability of funding, and reduce funding costs. Long-term contracts help the firm to secure its long-term cash flow in advance.25
Long-term contracts for the use of transmission capacity have been a common phenomenon in Europe. For instance, 40–60 % of the capacity on interconnectors was reserved for long-term import contracts in 200126 and the Commission pointed out in 2007 that “a significant proportion of existing interconnector capacity” was still allocated based on the priority rights or “pre-liberalisation” contracts. These capacity reservations often related to some of the most congested interconnectors.27
Non-discrimination
However, bilateral long-term contracts raise the question of non-discrimination. Non-discrimination is regarded as one of the fundamental principles of Community law. The use of long-term transmission contracts is nowadays constrained by the prohibition of discrimination in the electricity sector.
The Third Electricity Directive generally requires TSOs to ensure “non-discrimination as between system users or classes of system users”.28 Regulation 714/2009 requires the coordinated allocation of cross-border capacity through non-discriminatory market-based solutions.29 Long-term contracts are thus “disqualified as a method for allocating scarce interconnector capacity”.30
According to ACER’s CACM Framework Guidelines, the CACM Network Codes “shall foresee that the options for enabling risk hedging for cross-border trading are Financial Transmission Rights (FTR) or Physical Transmission Rights (PTR) with Use-It-Or-Sell-It (UIOSI), unless appropriate cross-border financial hedging is offered in liquid financial markets on both side of an interconnector”. Moreover, the CACM Network Codes “shall require that the TSOs provide a single platform (single point of contact) for the allocation of long-term transmission rights (PTR and FTR) at European level” with regional platforms as a transitional arrangement.31
Competition Law
In addition to the principle of non-discrimination, the use of long-term transmission contracts is constrained by general competition laws that address the problem of infrastructure foreclosure (Sect. 3.7.3).
In the Skagerrak cable case, 60 % of the total capacity of the connecting Western Denmark and Norway was reserved under an agreement with a duration of 20 years and the remaining 40 % under an agreement with a duration of 25 years. The parties agreed to free capacity after the Commission had expressed its doubts.32
In VEMW, the question was whether priority rights under long-term transmission contracts discriminate other parties that may not use the scarce transmission resources.33 According to the CJEU, comparable situations must not be treated differently unless the difference in treatment is objectively justified.34 There was no such justification in VEMW.35 In other words, the CJEU came close to a ban.
With these constraints in mind, we can now study market-based and not market-based capacity allocation mechanisms.
5.3 Mechanisms for Capacity Allocation Between Market Participants
Generally, there are various possible mechanisms for congestion management and the allocation of scarce transmission capacity between market participants (for EU law, see Sect. 5.6). The mechanisms can be used in different contexts. One can distinguish between: (a) cross–border or cross–zonal congestion management (capacity allocation); and (b) intra–zonal congestion management (capacity allocation). One can also distinguish between mechanisms applied to prevent congestion (c) on a day–ahead or intraday basis or (d) in real time.
Cross-Border or Cross-Zonal Congestion Management (Capacity Allocation)
It is characteristic of cross-border congestion management that capacity cannot be allocated before the size of the available cross-border transmission capacity has been estimated. System operators must predict the behaviour of market participants and calculate the available capacity in advance, because traders need time to use the information.36 The transmission capacity can be different in the two directions.
The European Commission’s Sector Inquiry listed the customary mechanisms for the allocation of cross-border transmission capacity.37 The mechanisms can be market-based or not market-based (Sect. 5.1).
One of the possible alternatives would be to use priority–based rules in cross-border capacity allocation. There can be different priority-based methods. The most common method uses chronological ranking of reservations and the first-come-first-served principle. This method favours incumbents at the cost of new market participants and long-term contracts at the cost of short-term trading.
On EPEX Spot, the intraday capacity service allows for the allocation of cross-border capacity continuously and anonymously under the first-come-first-served rule. That capacity is currently allocated at no cost. The required quantity of cross-border capacity is automatically booked and the remaining capacity is adjusted.38 The Intraday Capacity Service is not used between the control areas of German TSOs or between the control areas of German and Austrian TSOs.39
On the other hand, it is possible to use market–based mechanisms—explicit and implicit auctions—instead of priority-based rules. There is a fundamental difference between explicit and implicit auctions in cross-border capacity allocation.
In explicit auctions, transmission capacity is auctioned to the market separately. Transmission capacity is normally auctioned in portions through annual, monthly, or daily auctions.40 Explicit auctions can thus be for contracts with a relatively long duration. The fact that transmission capacity and electricity are traded separately can reduce transparency. The lack of information about the prices of the other commodity can hamper price convergence.
Implicit auctions can increase price convergence more compared with explicit auctions.41 They are used in spot markets within one zone. Cross-border implicit auctions are usually referred to as either market coupling (if two or more power exchanges of national electricity markets couple their price zones) or market-splitting (if one power exchange splits an area into several price zones in case of congestion between them).42 In market coupling, the day-ahead transmission capacity is used to integrate the spot markets in different bidding areas. Implicit auctions help to increase electricity flows from surplus areas (low price areas) to deficit areas (high price areas).
Intra-Zonal Capacity Allocation (Congestion Management)
Other kinds of congestion management mechanisms are used when congestion is managed within one zone that is treated as a “copper plate”—such as the high-voltage grid in Germany43—with no transmission constraints for market participants. These mechanisms will not replace the mechanisms for the allocation of cross-border transmission capacity as it would require overinvestment in the grid to make transmission networks behave like a “copper plate”.
The mechanisms include: the socialisation of congestion costs in transmission tariffs (the OTC market model); the socialisation of congestion costs as uplift payments (the exchange model); and locational marginal pricing (nodal pricing). The choice of the mechanism can depend on the structure of the market in the following ways.
Where electricity is mostly traded in the OTC market, market participants have plenty of discretion when negotiating their contracts. On the other hand, grid limitations are not visible to market participants. Consequently, such a market requires a well-developed and strong grid, and the problem of congestion must be solved by the TSO that also has to cover the incurred costs. The costs are customarily socialised, meaning that all users of the grid pay them under a form of transmission tariffs.44
Where electricity is traded on an exchange and auctions are used instead of continuous trading, there is a uniform electricity price. During the matching process, the cheapest generation gets priority according to the merit order regardless of grid limitations. If there is congestion, some out-of-merit generators are dispatched at the cost of in-merit generators. The cost of this action constitutes the uplift charge and is added to the electricity price.45
Where locational marginal pricing (nodal pricing) is used, pricing is based on the marginal cost of supplying electricity at a specific location in the grid by considering both the marginal cost of generation and the physical aspects of the transmission system. Consequently, congestion costs are not socialised. Each market participant pays for the congestion it causes. The congestion charge is the difference between energy prices at the generation node and the consumption node. Market participants can hedge against this congestion charge by entering into financial transmission contracts (FTR). Nodal pricing is regarded as efficient46 under certain circumstances (Sect. 5.7.6).47
Congestion Alleviation Methods
One can distinguish between day-ahead capacity allocation and real-time congestion management. Real-time congestion is dealt with by congestion alleviation methods that re-arrange the generation-load pattern. This can be achieved by redispatching production units and/or by shedding load.48 Congestion alleviation methods are an alternative to building more transmission capacity (Sect. 5.5).
5.4 Models for the Allocation of Transmission Capacity Between Designated Flows
The mechanisms for the allocation of transmission capacity between market participants (Sect. 5.3) are combined with models for the allocation of transmission capacity between designated electricity flows. There are estimated flows in the more distant future and actual flows. We can first study the former (for actual flows and congestion alleviation methods, see Sect. 5.5).
Grid Structure
Regulators and TSOs must choose the appropriate model. One of the factors that influence the choice of the model is the structure of the transmission grid.
There are radial and meshed grids. While a radial topology is applied to reduce costs (or to benefit a limited number of firms), a meshed topology is chosen for increasing reliability and security of supply. The choice of a meshed topology depends on the voltage level and the impact of failures.
The traditional system hierarchy is that there is a high voltage transmission level (for example, more than 110 kV) with a meshed grid, a medium voltage distribution level (for example, 6–35 kV or 6–70 kV) with a radial grid, and a low voltage distribution level (for example, less than 1 kV or 0.4 kV) with a radial grid.
In this way, the impact of failures at the distribution level is limited to local outages. As failures at the high voltage transmission level would lead to blackouts that have a large impact, their likelihood is reduced by choosing a meshed topology. For instance, it is then easier to replace the output of a failed generation unit with the output of far away generation units.49
Models
There are various models for the allocation of transmission capacity between designated electricity flows. One can distinguish between: the contract path model; the flow-based model; the point-to-point model; and the entry-exit model. (a, b) The contract path model and the flow-based model can be combined with market-based mechanisms (that is, with explicit or implicit auctions). While the contract path model is more likely to be used in radial parts of the transmission grid, the flow-based model can be used even in a meshed grid with loop flows. (c) The allocation mechanism is not market-based under the point-to-point model, because all transmission services are reserved. (d) In contrast, the entry-exit model focuses on pricing rather than the physical allocation of transmission capacity. We can study the models in more detail.
The Contract Path Model
Under the contract path model, the parties agree that power flows along a “contract path” consisting of the chain of companies that control the transmission infrastructure between the ultimate receipt and delivery points.
The actual path can be determined by the contract path where the grid is radial (no loop flow). When this is not the case, the contract path is more suitable for the allocation of costs or for pricing rather than for capacity allocation. For instance, it is clear whose transmission assets are used where the transmission infrastructure is owned by just one entity and the flows are not connected to the transmission system of any third-party entity (no loop flow over any third party’s lines).
The actual path of electricity that moves through the network is customarily not determined by the contract path fiction in most transmission grids. Most transmission grids are meshed grids. The contract-path model cannot work acceptably in a meshed grid unless cross-zonal electricity trade remains limited and predictable so regional interdependencies and externalities (such as loop-flows) can largely be ignored.50
In Europe, the contract path model has been used in some implicit auctions for transmission capacity in radial parts of the grid such as on interconnectors.51 When the contract path model is used in implicit auctions, the relevant TSO allocates a certain amount of day-ahead transmission rights to the electricity exchange.
In European gas markets, network charges must not be calculated based on contract paths.52
“Postage stamp” pricing (Sect. 5.7.5) is an example of the use of the contract path model. Under the postage stamp model, transmission contracts set a single price for energy flow over each TSO’s (or, in vertically integrated markets, each utility’s) transmission system. The calculation of entry-exit tariffs for each TSO’s transmission system results in a “postage stamp” tariff. The terms postage stamp tariff and postage stamp pricing come from the fact that the rate does not depend on how far the electricity moves within one entity’s transmission system.
The Flow-Based Model
The contract path model is not suitable for a meshed grid with loop flows. One solution could be to try to trace the actual flows and include them in the transmission rights. This leads to the flow-based model.53 Under the flow-based model, electricity is assumed to flow through all parallel paths. The flow-based approach essentially tries to maintain the physical contract-path fiction by accounting for all its implications (such as loop-flows) within a meshed grid.54 The flow-based model is complemented by flow-based pricing (Sect. 5.8.4).
In the EU, the flow-based model is applied to cross-border electricity transmission systems. The magnitudes of cross-border flows hosted and of cross-border flows designated as originating and/or ending in national transmission systems are determined based on the physical flows of electricity actually measured during a given period.55
It can nevertheless be difficult to measure actual flows when multiple users compete on the same transmission system. Several simplifying assumptions may be necessary to maintain the physical contract-path fiction. The model is unsustainable if the assumptions turn out to be wrong.56 The flow-based model has in some cases been replaced by the point-to-point model.
The Point-to-Point Model
The point-to-point model means that (1) all transmission services are reserved, and the reservations of transmission capacity permit the customer to (2) receive up to a specific amount of power into the grid at specified points of receipt, and to (3) deliver up to a specific amount of power from the grid at specified points of delivery.57
Many of the restructured US electricity markets experimented with the flow-based model in the decade between 1997 and 2007. The experiences of PJM (the RTO for thirteen states and the District of Columbia), CAISO (the California ISO), and ERCOT (Texas) were not satisfying. These three markets abandoned the flow-based zonal model and replaced it by a point-to-point model.58
The Federal Energy Regulatory Commission’s (FERC) Order No. 88859 requires public utilities to file “a single open access tariff that offers both network, load-based service and point-to-point, contract-based service”.60
The FERC has “characterized point-to-point service as involving designated points of entry into and exit from the transmitting utility’s system, with a designated amount of transfer capability at each point”.61 In Order No. 888 and the Open Access Transmission Tariff, the FERC has defined various qualified point-to-point transmission services.62 The Open Access Transmission Tariff was amended by Order No. 890.63
The minimum term of firm point-to-point transmission service is one day (day-ahead). The maximum term is specified in the service agreement.64
As all transmission services are reserved under this model, there should be rules on reservation priority, including rules setting out how the available transmission capacity is calculated.
In the US, both Order No. 888 and Order No. 890 provide for reservation priority. (a) Long-term firm point-to-point transmission service is available on a first-come, first-served basis. (b) Reservations for short-term firm point-to-point transmission service are conditional based upon the length of the requested transaction.65 (c) There are reservation priorities for some existing firm service customers (wholesale requirements and transmission-only, with a contract term of 5 years or more). These customers have a right to roll over or renew the contract when the contract expires.66 The required contract term used to be shorter under Order No. 888 (one year or more).67
Order No. 888 did not provide for a methodology for calculating the available transmission capacity. This increased the potential for discrimination and made undue discrimination more difficult to detect.68 Neither did it provide for coordinated, open and transparent transmission planning.
For this reason, the FERC adopted nine planning principles that public utility transmission providers are required to follow.69 The planning principles relate to: coordination70; openness71; transparency72; information exchange73; comparability74; dispute resolution75; regional participation76; economic planning studies77; and cost allocation for new projects.78
The fact that all transmission services must be reserved also means that either market participants themselves or the TSO must be responsible for the scheduling of electricity flows.
In the US, the responsibility for the scheduling of flows is divided between market participants and the system operator (ISO or RTO). (a) The starting point is that each market participant is responsible for the scheduling of its own power plants. A market participant schedules power plants to meet its own load or according to the terms of bilateral trades. (b) In addition, the system operator (ISO or RTO) runs a day-ahead market with central scheduling of generation units.79
The Entry-Exit Model
Under the entry-exit model, the entry point and the exit point are independent for transmission capacity and tariff purposes. The entry-exit model is regarded as suitable for unbundled and liberalised electricity markets. It is discussed in the context of pricing (Sect. 5.7.4).
5.5 Congestion Alleviation Methods
5.5.1 General Remarks
The mechanisms for the allocation of transmission capacity necessarily consist of three components (Sect. 5.1). One of them is the allocation of transmission capacity for electricity flows (Sect. 5.4). Flows can be flows in the more distant future or actual flows. When actual flows and congestion are known in the control area of a TSO, one can apply particular congestion alleviation methods.
The alleviation of congestion has costs. Some congestion is necessary for reasons of economic efficiency, because there are costs for building new transmission infrastructure. Capacity allocation methods that reduce congestion can also reduce the costs of congestion alleviation.80 The use of alternative congestion alleviation methods can reduce the need to build new transmission infrastructure.81
Transmission system operators are in the best position to manage congestion risks.82 They use physical and financial congestion alleviation methods.
Physical methods mean changing the level of generation (or demand) at different locations on the grid.83 They are the primary way to relieve transmission congestion constraints.
Financial methods focus on price differences or volatility caused by congestion. Financial methods tend to be market-based. Physical methods can be market-based or not market-based. We can have a look at financial methods first.
5.5.2 Financial Methods
There are two kinds of financial methods, structural and contractual. The use of structural methods means that the TSO can split its control area in bidding zones. Financial methods mean the use of financial transmission contracts to address the problem of price volatility and regional price differences caused by congestion.
Bidding Zones
In most cases, the bidding zone is the control area of the TSO. The TSO may decide to split its control area into two or more bidding zones if there are transmission constraints inside the control area. In this case, there will be a price difference between the zones in the event of congestion.84
There are several examples of bidding zones in Europe: Norway (5), Sweden (4), Denmark (2), the UK (2), and Italy (6 bidding zones for producers, a single price zone for end consumers).85
Financial Transmission Contracts
The contractual methods mean the use of financial transmission contracts. They include: (a) financial transmission rights (FTRs such as point-to-point FTRs and flowgate FTRs); and (b) contracts for difference (CfDs).
A financial transmission right (FTR) gives its owner a right to a share of congestion rents received by the TSO during transmission congestion. A FTR can be structured as a firm obligation or as an option.86 The duration of FTRs tends to range from months to years.
FTRs can be obtained in three main ways. FTRs can be allocated at an auction or allocated to transmission service customers who pay the embedded costs of the transmission system.87 There can also be a secondary market.88
One can distinguish between point-to-point FTRs and flowgate FTRs. (a) Point-to-point FTRs give a right to the difference in locational prices times the contractual volume. (b) Flowgate FTRs are based on two ideas. The first is that congestion payments should be linked to actual electricity flows. The other is that there are particular transmission constraints called flowgates. Flowgate FTRs give the right to collect payments based on the shadow price associated with a particular transmission constraint (flowgate).
Contracts for difference can be used in various ways (Sect. 12.4). One of them is hedging. They can be used to hedge against the difference between two uncertain spot prices (locational swaps) or against the difference between the spot price and the reference price.89 They can also be used for basis trading.
5.5.3 Physical Methods
The physical methods inside a zone can be market-based or not market-based. They include: (a) long-term infrastructure solutions like building new lines; (b) locational signals for infrastructure investment; (c) curtailment (transmission loading relief); (d) redispatching and coordinated redispatching; and (e) countertrading.90 Transmission capacity is regarded as firm when it cannot be curtailed or re-dispatched.
Locational Signals
Locational signals matter. For example, peak transmission flows can depend on the location of base-load generators and peak-load generators. Where the base-load generators are located a long way from demand centres and peak-load generators are close to demand, transmission flows are greatest at off-peak times, when the generators close to the load are not running. Where the base-load generators are located close to demand and the peak-load generators further away, the transmission peak will coincide with the demand peak.91
Curtailment
Curtailment is a physical method that is not market-based. Transactions contributing to congestion can be curtailed. For instance, congestion inside the control area of a TSO could be reduced by limiting flows on an interconnector.92 The costs of curtailment are allocated to the TSO.
In the US, the procedure used for this purpose is called Transmission Loading Relief. It is based on Reliability Standard IRO-006-3 (as amended).
In the EU, Regulation 714/2009 limits the use of curtailment as far as cross-border transmission capacity is concerned. The permitted use of curtailment is limited to “emergency situations where the transmission system operator must act in an expeditious manner and redispatching or countertrading is not possible”. Moreover, any such procedure must be applied in a non-discriminatory manner and market participants who have been allocated capacity must be compensated for any curtailment (except in cases of force majeure).93
The CACM Network Codes must contain provisions to this effect.94 There is a common definition of force majeure95 (see also Sects 8.4.6, 10.7.2 and 10.7.3 in this book). Force majeure events are defined so narrowly that they should be rare.
There are also firmness deadlines after which curtailment is not permitted. The firmness deadlines depend on the duration of the contract (long-term,96 day-ahead,97 or single day98). There are special rules for force majeure and emergency situations.99 Generally, TSOs must bear the costs of curtailment or redispatching,100 but there is a cap.101 There are also transitional arrangements “until the introduction of price coupling in the day ahead timeframe”.102 Price coupling in the day-ahead timeframe is facilitated by the CACM Regulation.
The use of curtailment is secondary to redispatching and countertrading for legal reasons.103
Redispatching
Redispatching means the alteration of the initial generation and/or load pattern to relieve congestion by measures activated by the system operator.104 It is customarily based on the prices that electricity producers communicate to the system operator for up and down regulation. Compared with curtailment, redispatching can be more market-based.
Coordinated redispatching involves two or more system operators that redispatch units on both sides of the congested interconnector. It requires harmonisation of market rules in adjacent areas.
The costs are first allocated to the system operator. Depending on the market, they can be allocated to market participants at a later stage. Where the costs are included in transmission tariffs, they are socialised. Alternatively, they can be charged to specific users that have caused congestion.105
Countertrading
Countertrading is a simple market-based method. As electricity flows in opposite directions can be set off, the TSO can buy electricity in the control zone downstream of congestion and sell it back in the control zone upstream.106 In other words, the TSO buys additional power from generators in areas that were due to import more than the transmission system could carry, and sells power back to generators in areas that were due to export too much.
As the price of electricity tends to be higher downstream of congestion (in the import-constrained area), the TSO makes a loss buying expensive electricity to sell it back in the low price area (in the export-constrained area). The loss is covered by transmission tariffs.107
Electricity producers, on the other hand, can make a profit. In the import-constrained area, where spot prices tend to be high, they can sell electricity to the TSO at a high price and earn more than producers would earn in an unconstrained area. Electricity producers may be given perverse incentives in the export-constrained area, where producers who buy back their power will pay less than the price in the unconstrained market, and thus have the opportunity to earn more than producers in an unconstrained area would earn.108
Examples
There are various examples of the use of physical congestion alleviation methods in Northern Europe.
In the Nordic electricity market, market splitting is complemented by countertrading. Cross-border congestion is managed by implicit auctions (Sect. 5.3) in the day-ahead market. After day-ahead allocation, the remaining transmission capacity is set for the intraday market and balancing:
Market splitting and countertrading. It is necessary to manage congestion between the Nordic bidding areas and internal congestion in one area. (a) Congestion between the various bidding areas is managed through market splitting. Market splitting gives participants an opportunity to trade and benefit from the differences between low price areas and high price areas. (b) TSOs manage congestion by countertrading in the real-time balance market. As TSOs have to pay for countertrading, it increases their costs. The costs are normally covered by the grid tariff.109 Because of the allocation of costs to the TSO, they signal to the TSO that it should reinforce the network.110
Countertrading, adjacent areas. Countertrading can be used where transmission needs to be reduced between two adjacent areas within, say, Sweden. The TSO can order an increased level of electricity production in the area with a shortage of production and a decreased level of production in the area with a surplus.
Countertrading, single area. Countertrading can also be used to manage congestion within a single price area such as Finland or after the closure of the day-ahead market.111
Curtailment. When Sweden still was one bidding zone, intra-zonal congestion was managed by curtailment of cross-border flows and countertrading.112 Sweden was later divided into four bidding zones.
In Germany, the lack of market splitting has reduced locational signals for generation investments and contributed to congestion. To increase locational signals in the absence of market splitting and nodal pricing, Monopolkommission (the German Monopolies Commission, an expert committee) has proposed the allocation of a greater share of the transmission costs to generation (G-component).113
5.6 Models for Capacity Allocation in the EU
5.6.1 General Remarks
We have discussed various models available for the allocation of transmission capacity (Sect. 5.3 and 5.4), including models for congestion alleviation (Sect. 5.5). What models have been adopted at EU level? (The related pricing issues are discussed in Sects. 5.7 and 5.8).
EFET Principles
EFET has proposed principles for the regulation of transmission capacity allocation at EU level in the interests of European energy traders.115 The five key principles are as follows: (1) TSOs should auction physical transmission rights or financial rights with equivalent effect; (2) TSOs should auction the maximum of available capacity over appropriate timeframes; (3) transmission rights should be firm; (4) TSOs should not discriminate against holders of transmission rights purchased in advance of day-ahead and intraday timeframes; and (5) transmission rights need to be fungible in a secondary, traded market.116
The EFET key principles have largely been implemented in EU electricity markets law (see Sect. 5.6.5). The trend in EU law is the increased use of market-based mechanisms (auctions) for the allocation of transmission capacity. On the other hand, there is still no proper secondary market for physical or financial transmission rights (Chap. 12).
Regulation
The allocation of transmission capacity is addressed by the Framework Guidelines on Capacity Allocation and Congestion Management (CACM Guidelines) published by ACER in July 2011. The Framework Guidelines are based on the Third Electricity Directive and Regulation 714/2009.
The CACM Guidelines are implemented by the more detailed CACM Network Codes.117 (a) The CACM Regulation is such a network code. It “lays down detailed Guidelines on cross-zonal capacity allocation and congestion management in the day-ahead and intraday markets”.118 (b) ENTSO-E Network Code on Forward Capacity Allocation requires the introduction of harmonised allocation rules for PTRs and FTRs according to the principles laid down by the CACM Guidelines.119 There may be regional specifities in the harmonised allocation rules when it is “appropriate”.120
Spatial Characteristics
The allocation mechanism depends on the nature of transmission capacity. It is necessary to distinguish between the allocation of intra-zonal, cross-zonal, or cross-border transmission capacity. Consequently, various models for the allocation of transmission capacity are used in the EU.
Time Frame
The allocation mechanism can also depend on the duration of the contract. One should distinguish between intraday, day-ahead, long-term, and very long-term transmission capacity allocation.
Definition of Zones
Before allocating cross-border transmission capacity between zones, it is necessary to define the zones. Bidding zones reflecting supply and demand distribution are regarded as “a cornerstone of market-based electricity trading”.121
According to the ACER’s CACM Guidelines, the CACM Network Codes to be developed must define a zone as “a bidding area”. When defining the zones, the TSOs must be guided by the principle of overall market efficiency. In the absence of significant internal congestion within or between control areas, one or several control areas may constitute one zone. Zone definitions concern all timeframes (long-term, day-ahead, and intraday) and zone delimitations should be coordinated with balancing zones.122
The CACM Regulation enables the review of an existing bidding zone configuration.123 The CACM Regulation also lays down the criteria to be considered if a review of bidding zone configuration is carried out. They relate to network security, overall market efficiency, and the stability and robustness of bidding zones.124
Definition of Available Capacity
It is also necessary to define the available capacity. The available capacities have been determined in the same way in the Member States, including in Norway and Switzerland. First, available capacities have depended on ETSO’s definitions.125 ETSO has issued common definitions of cross-border transmission capacities for international exchanges of electricity within the internal electricity market (IEM).126 Second, the methods to define available capacities have been addressed by the CACM Guidelines. Third, they are regulated by the CACM Regulation.
According to ACER’s CACM Guidelines, the principles for the development of the CACM Network Codes include that they must not discriminate between exchanges internal to a zone, cross-zonal exchanges, and cross-border exchanges.127 Moreover, long-term capacity calculation methodologies must be fully compatible with the adopted short-term capacity calculation.
There has been a move from NTC-based to flow-based market coupling in the EU. The CACM Network Codes must require the use of either a flow-based (FB) method or an available transfer capacity (ATC) method at each zone border for a given timeframe:
For short-term capacity calculation in highly-meshed networks, the flow-based method is to be preferred to the ATC-method.
For short-term capacity calculation in less meshed networks (such as the Nordic power system), ATC is the preferred method.
Long-term capacity calculation methodologies must be fully compatible with the adopted short term capacity calculation.128
In contrast, the nodal approach was not chosen as it would have required radical changes.129
The CACM Regulation requires the use of a common grid model to implement single day-ahead and intraday coupling. Capacity calculation for the day-ahead and intraday market timeframes should be coordinated at least at the regional level.130 The two permissible approaches when calculating cross-zonal capacity are the flow-based approach and the coordinated net transmission capacity approach131:
The available capacity should normally be calculated according to the flow-based calculation method.132 The flow-based approach should be used as a primary approach for day-ahead and intraday capacity calculation where cross-zonal capacity between bidding zones is highly interdependent.133
The coordinated net transmission capacity approach should only be applied in regions where cross-zonal capacity is less interdependent and it can be shown that the flow-based approach would not bring added value.134
Capacity calculation regions applying a flow-based approach shall be merged into one capacity calculation region provided that certain conditions are fulfilled.135
5.6.2 Access to Intra-Zonal Transmission Capacity in the EU
A (bidding) zone is the geographical area within which market participants can exchange electrical energy without grid constraints.136 It is not necessary to allocate transmission capacity if the grid is regarded as a copper plate. The question therefore is about grid access, dispatching,137 and curtailment. Intra-zonal allocation models have largely been left to the discretion of Member States.
Grid Access
The Third Electricity Directive makes each TSO responsible for ensuring the long-term ability of the system to meet reasonable demands for the transmission of electricity.138
For this reason, the main rule is third-party access to transmission and distribution systems. Third party access must be “based on published tariffs, applicable to all eligible customers and applied objectively and without discrimination between system users”.139 Moreover, the power of the TSO to decide on the dispatching of generation installations is “without prejudice to the supply of electricity on the basis of contractual obligations”.140
The TSO/DSO may refuse access where it lacks the necessary capacity. “Duly substantiated reasons” must be given when access is refused, and they must be based on “objective and technically and economically justified criteria”. Where refusal of access takes place, the regulatory authorities must ensure that the TSO or DSO “provides relevant information on measures that would be necessary to reinforce the network”.141
In Germany, the system operator has far-reaching duties. It must provide access and ensure that there is sufficient capacity to the extent that doing so would not be economically unreasonable. What is regarded as reasonable or unreasonable may depend on the different objectives of the EEG and the EnWG142 and on whether the customer is a producer of RES-E143 or generates electricity from other sources.144 There are sanctions for failure to comply with these obligations.145
Special Cases
There are special cases. (a) One is direct lines. Member States must take measures necessary to enable the supply of electricity through a direct line.146 Because of its definition,147 a direct line can only be used for direct supply contracts between the owner of a certain plant and a certain end customer. (b) The other and more important special case is RES-E. RES-E must enjoy either priority access or guaranteed access to the grid.148
5.6.3 Allocation of Cross-Zonal Transmission Capacity in the EU
One can distinguish between short-term, long-term, and very long-term allocation of cross-zonal transmission capacity.
Short-Term Cross-Zonal Transmission Capacity
The regulation of the allocation of short-term cross-zonal transmission capacity is based on the Target Model with implicit auctions (day-ahead allocation) and continuous trading (intraday allocation).149
Generally, TSOs have a duty to foster the allocation of cross-border capacity through non-discriminatory market-based solutions under Regulation 2009/714.150 Cross-border capacity must therefore be allocated by auctions, but continuous trading may be used for intraday trade.151 All interconnection capacity may be allocated through implicit auctioning “in regions where forward financial electricity markets are well developed and have shown their efficiency”.152
The allocation of short-term cross-zonal transmission capacity is regulated by the CACM Regulation. A particular market coupling operator (MCO) function153 uses a specific algorithm to match bids and offers in an optimal manner. The results of the calculation are made available to power exchanges. Based on the results of the calculation, the power exchanges inform their clients of the successful bids and offers. Energy is then transferred across the network according to the results of the MCO function’s calculation. The difference between single day-ahead and single intraday coupling is that intraday coupling uses a continuous process and day-ahead coupling one single calculation.154
The main rule under the CACM Regulation is that capacity should be allocated in the day-ahead and intraday market timeframes using implicit allocation methods.155
However, there are transitional intraday arrangements: “Where jointly requested by the regulatory authorities of the Member States of each of the bidding zone borders concerned, the TSOs concerned shall also provide explicit allocation, in addition to implicit allocation … via the capacity management module on bidding zone borders”.156
Redispatching and Countertrading
In addition to the regulation of short-term capacity allocation, electricity producers are affected by the regulation of grid access, dispatching,157 and curtailment.158 According to the CACM Regulation, TSOs should use a common set of remedial actions to deal with both internal and cross-zonal congestion and coordinate the use of remedial actions in capacity calculation to avoid unnecessary curtailments of cross-border capacities. Cross-zonal redispatching or countertrading must thus be coordinated with control area internal redispatching or countertrading. The usual firmness requirements apply.159
The CACM Regulation requires TSOs in each capacity calculation region to develop a proposal for a common methodology for coordinated redispatching and countertrading. Each TSO has a duty to abstain from unilateral or uncoordinated redispatching and countertrading measures of cross-border relevance.
The relevant generation units and loads have a duty to give TSOs the prices of redispatching and countertrading before redispatching and countertrading resources are committed. Pricing of redispatching and countertrading must be based on: (a) prices in the relevant electricity markets for the relevant timeframe; or (b) the cost of redispatching and countertrading resources calculated transparently based on the incurred costs.160
Long-Term Cross-Zonal Transmission Capacity
Long-term means here at least the yearly and monthly timeframes.161 There have been multiple sets of rules for the allocation of long-term cross-zonal transmission capacity in the Member States. Moreover, there have been different contract practices reflecting freedom of contract.162 The purpose of the Network Code on Forward Capacity Allocation (NC FCA) is to harmonise these rules at the European level. NC FCA applies to the calculation, allocation, and pricing of long-term transmission capacity.
Long-term cross-zonal transmission capacity must be allocated to market participants by the relevant platforms (a) in the form of physical transmission rights (PTRs) in accordance with the use-it-or-sell-it (UIOSI) principle or (b) in the form of financial transmission rights (FTRs).163 The main rule is explicit auctions.164
The use of PTRs and the UIOSI principle is regarded as relatively uncomplicated for the Member States.165 The UIOSI principle means that the holder of the right may either use capacity by nominating it or receive an automatic payout for capacity that it has not nominated.166
On the other hand, the legal nature of FTRs is regarded as problematic. In addition, they would require the existence of implicit auctions and thus power exchanges.167
The use of PTRs (or FTRs), therefore, means explicit auctions. Long-term cross-zonal transmission capacity is auctioned and allocated to market participants based on bids.168 There will be a single platform for allocation and for secondary trading at the pan-European level. The single platform for allocation is a single point of contact for market participants wanting to participate in explicit auctions to acquire long-term transmission rights.169
The calculation of the available long-term capacity must be based on a “coordinated net transmission capacity approach” or a flow-based approach (like the definition of available cross-border transmission capacity). The choice is in the discretion of the TSO.170 One or more Coordinated Capacity Calculators will determine the cross-zonal transmission capacity.171
Very Long-Term Cross-Zonal Transmission Capacity
The Network Code on Forward Capacity Allocation (NC FCA) is not really designed for very long-term capacity allocation.172 For reasons of risk management, it could be necessary for electricity firms to ensure that long-term transmission capacity is reserved for new installations, and Member States may need to facilitate the reservation of long-term transmission capacity to foster investment in energy generation from renewable sources.173 For instance, so-called “projects of common interest”174 may require large long-term investments supported by a long-term contractual framework.
5.6.4 Allocation of Cross-Border Transmission Capacity in the EU
Transmission capacity can be allocated between zones or across borders between different countries. (a) Inside the EU, the allocation of cross-border transmission capacity is governed by Regulation 714/2009 and the CACM Network Codes adopted from the CACM Framework Guidelines.175 It is thus governed by the same regulatory framework as the allocation of cross-zonal transmission capacity. (b) Different rules can apply between a Member State and a third country.
Cross-Border Allocation in the EU
Non-market based methods used to be commonplace in the EU.176 In 2003, the EU emphasised the need for market-based schemes.177 According to a 2006 decision by the European Commission,178 transmission capacity must be allocated by means of explicit (capacity) and/or implicit (capacity and energy) auctions. In addition, continuous trading may be used for intraday trade.179 Each capacity allocation procedure must allocate a prescribed fraction of the available interconnection capacity.180 Regulation 714/2009 now requires market-based methods for cross-border capacity allocation and emphasises the merits of implicit auctions.181
Generally, the allocation of long-term cross-border transmission capacity relies on the contract-path model and a physical transmission rights (PTR) framework.182 It is possible to use the contract-path model, because the number of cross-border interconnectors is limited.
In the past, cross-border interconnections were mostly built for security and back-up purposes rather than for the purposes of the integration of national electricity markets. The limited number and capacity of cross-border interconnectors means congestion. Commercial demand for cross-border transmission capacity can exceed actual network capacity.183
Cross-Border Allocation Between a Member State and a Third Country
The participation of an adjacent third country in the European single day-ahead coupling and single intra-day coupling would require a bilateral agreement. The coupling of third countries would be decided by the European Commission based on an assessment by ACER.
Issues relating to third countries have been addressed in parts of the EU regulatory framework. For instance, the reporting duties of TSOs may include even cross-border transmission capacity.184 Third countries have been mentioned in the Third Electricity Directive but only briefly in Regulation 714/2009.
The CACM Regulation addresses the question of Switzerland: “The Union single day-ahead coupling and intraday coupling may be opened to market operators and TSOs operating in Switzerland on the condition that the national law in that country implements the main provisions of Union electricity market legislation and that there is an intergovernmental agreement on electricity cooperation between the Union and Switzerland”.185 Moreover, “participation by Switzerland in day-ahead coupling and single intraday coupling shall be decided by the Commission based on an opinion given by the Agency”.186 The CACM regulation also addresses the question of cost sharing even where a TSO or NEMO is in a third country.187
Example: The Nordic Market
Congestion is managed by market-based methods in the Nordic market and the main rule is that there are no priority transmission rights for cross-border trade between the Nordic countries.
In the day-ahead market of Nord Pool Spot (Elspot), capacity on interconnectors is allocated by implicit auctions (market splitting).188 Capacity not used in the Elspot market is offered to the intraday market (Elbas that uses continuous trading) and cross-border balancing in accordance with the ACER Framework Guidelines. Market participants may use EPADs (Electricity Price Area Differentials, that is, exchange-traded Contracts for Differences) for hedging against price differences between area prices and the system price.189
PTRs are used on certain interconnectors. Energinet.dk and TenneT TSO GmbH offer PTRs on the border between DK1 and Germany. Emerginet.dk and 50 Hertz Transmission offer PTRs on the Kontek interconnector between DK2 and Germany. Since 1 July 2014, Energinet.dk has allocated PTRs for capacity on the interconnector between DK1 and DK2. The capacity is allocated in monthly auctions. Auction rules applied on the Danish-German border are applied on the interconnector between DK1 and DK2.190
Priority transmission rights are used for the allocation of capacity between Finland and Russia. Market participants can buy rights in auctions arranged by the TSO for one or more years.191 A new trading scheme called direct exchange trade was adopted in electricity trade between Russia and Finland (the EU) in August 2011. Its volume is limited to 100 MW.192
5.6.5 Summary of Regulation in the Light of EFET Key Principles
The regulation of transmission capacity allocation can be summed up in the light of EFET key principles. Generally, the principles are reflected in ACER Framework Guidelines on CACM. The CACM Framework Guidelines regulate the contents of CACM Network Codes that apply to cross-zonal transmission services.
Auctions of Physical or Financial Rights
The first key principle is that TSOs should auction physical transmission rights or financial rights with equivalent effect.193 (a) The Third Electricity Directive did not yet address this issue in detail. As regards cross-border transmission capacity, this issue was to be regulated in network codes.194 (b) Regulation 714/2009 requires the use of market-based methods but—because of its scope195—only for the allocation of cross-border transmission capacity.196 (c) EFET key principles are reflected in ACER Framework Guidelines on CACM that apply to cross-zonal transmission services.
The CACM Network Codes must set out: that TSOs provide a single platform (single point of contact) for the allocation of long-term transmission rights (PTR and FTR) at European level (with regional platforms as a transitional arrangement)197; that TSOs implement capacity allocation in the day-ahead market from implicit auctions and the marginal pricing principle198 including necessary provisions for the implementation of the pan-European intraday target model supporting continuous implicit trading (with direct explicit access to the capacity allowed as a transitional measure).199
Auction of Maximum Capacity
The second principle is that TSOs should auction the maximum of available capacity over appropriate timeframes.200 ACER Framework Guidelines on CACM address this issue in three ways.
First, there must be a method for the calculation of the available capacity. The CACM Network Codes must require the use of either a flow-based method or an available transfer capacity method for short-term capacity calculation at each zone border, and long-term capacity calculation methods that are fully compatible with the adopted short-term capacity calculation methods.201 According to NC FCA, the TSO may choose between “coordinated net transmission capacity approach” or a flow-based approach for long-term capacity calculation.202
Second, there are particular rules on the volume of long-term or intraday transmission capacity that must be allocated. The CACM Network Codes must require that TSOs determine the volume of long-term capacity rights in accordance with the technical capabilities of the network and for each long-term timeframe.203 Moreover, all cross-zonal intraday capacity must be allocated via the pan-European platform.204
Third, there are particular rules on direct explicit access. There may be direct explicit access (e.g. for bilateral supply OTC contracts) to intraday capacity as a transitional arrangement.205
Firmness
According to the third EFET principle, transmission rights should be firm.206 Firmness is regulated in various ways.
When cross-border transmission capacity is allocated on a long-term or medium-term basis, access rights are firm under Regulation 714/2009.207
According to ACER Framework Guidelines, physical firmness is the preferred approach, but financial firmness may be accepted in case of explicit auctions. To ensure firmness, TSOs must also ensure that enough redispatching/countertrade means are available.208 (a) As regards day-ahead capacity allocation, the reduction of allocated capacity must be a last resort measure and a reduction of allocated capacity may only be used “in emergency situations and force majeure, and when all other means are exhausted”. Moreover, costs must not be allocated to market participants.209 (b) As regards intraday capacity allocation, the CACM Network Codes must provide that “the allocated intraday capacity is firm, and that the use of intraday capacity is obligatory when allocated”.210
The firmness of short-term capacity allocation is now regulated by the CACM Regulation. Orders matched in single day-ahead coupling are considered firm,211 and there is a day-ahead firmness deadline for cross-zonal capacity allocation.212 Cross-zonal intraday capacity is firm as soon as soon as it is allocated.213
However, firmness is financial firmness under the CACM Regulation. (a) The CACM Regulation defines firmness as “a guarantee that cross-zonal capacity rights will remain unchanged and that a compensation is paid if they are nevertheless changed”.214 According to the CACM Regulation, any costs incurred efficiently to guarantee firmness of capacity should be recovered via network tariffs or appropriate mechanisms in a timely manner. NEMOs should be entitled to recover their incurred costs if they are efficiently incurred, reasonable and proportionate.215 (b) There are particular rules on firmness in the event of force majeure or emergency situations.216
Non-discrimination
The fourth principle relates to non-discrimination. TSOs should not discriminate against holders of transmission rights purchased in advance of day-ahead and intraday timeframes.217 (a) Generally, non-discrimination is a general principle of EU law. The non-discrimination of electricity firms is one of the purposes of the Third Electricity Directive.218 TSOs have a general obligation not to discriminate as between system users.219 For example, the dispatching of generating installations and the use of interconnectors must be determined based on the criteria which must be “objective, published and applied in a non-discriminatory manner, ensuring the proper functioning of the internal market in electricity”,220 and the tariffs must be non-discriminatory.221 (b) According to Regulation 714/2009, capacity allocation “shall not discriminate between market participants that wish to use their rights to make use of bilateral supply contracts or to bid into power exchanges”. Instead, “[t]he highest value bids, whether implicit or explicit in a given timeframe, shall be successful”.222 (c) These general non-discrimination rules are complemented by the CACM Framework Guidelines. For instance, CACM Network Codes must ensure that there is no “undue discrimination in matching the different types of intraday products”223 and that TSOs “avoid any discrimination between the different types of commercial exchanges, between the relevant time frames and between exchanges internal to countries and cross-border exchanges” when cross-zonal transactions are curtailed.224
Secondary Market
The fifth and last EFET key principle is that transmission rights need to be fungible in a secondary, traded market.225 (a) To start with, there must be a secondary market for the gas market226 and, under Regulation 714/2009, for contracts for cross–border electricity transmission. Cross-border transmission capacity must be freely tradable on a secondary basis, provided that the TSO is sufficiently informed in advance.227 Rights to cross-border transmission capacity must therefore be firm. In addition, they must be subject to the use-it-or-lose-it or use-it-or-sell-it (UIOSI) principles at the time of nomination.228 (b) Secondary trading of cross–zonal transmission capacity is addressed by the CACM Framework Guidelines. There must be a secondary market for long–term transmission rights. The CACM Network Codes must ensure that the TSOs provide “a single platform for anonymous secondary trading at the European level” (with regional platforms as a transitional arrangement).229
To facilitate secondary trading, the CACM Network Codes lay down the nature of PTRs and FTRs. (a) PTRs must be defined as options that are subject to the use-it-or-sell-it (UIOSI) principle (unless appropriate cross-border financial hedging is offered in liquid financial markets on both side of the interconnector). Non-nominated capacity rights are thus resold. (b) FTRs must be defined as options or obligations. (c) Hybrid solutions mixing PTR and FTR components are prohibited.230
Secondary trading is regulated in greater detail in ENTSO-E Network Code on Forward Capacity Allocation (NC FCA).231 It is defined as “the trading of Long Term Transmission Rights through which a Market Participant is able to buy or sell Long Term Transmission Rights which were initially allocated by the Allocation Platform(s)”.232 The Network Code requires a Single Allocation Platform responsible for the operation of auction procedures and the performance of other duties relating to Forward Capacity Allocation.233 Long Term Transmission Rights holders are entitled to “transfer all or part of their Long Term Transmission Rights through Secondary Trading to other Market Participants according to the corresponding Allocation Rules”.234 Market Participants cannot participate unless they are “registered with the Allocation Platforms and meet all eligibility requirements under the corresponding Allocation Rules”.235
For instance, CASC-CWE is a system that sets out the terms and conditions governing the allocation of available transmission capacities via auctions in both directions on the country borders in the regions Central West Europe (CWE), Central South Europe (CSE), and Switzerland.236 The auctions are explicit auctions and thus limited to transmission capacity.237 The available transmission capacities are determined jointly by the concerned TSOs of a country border.238 Capacity is auctioned via a Joint Auction Office in the form of physical transmission rights on a yearly, monthly, and as the case may be, daily basis.239 A market participant that has acquired physical transmission rights may exercise them in relation to the relevant TSOs, provided for example that the market participant nominates the capacities according to the terms applicable in each country. The market participant is required to pay the amount resulting from the auction.240 The valuation amounts of allocated capacities are paid to the Joint Auction Office.241 There are nevertheless reductions242 caused by the UIOSI principle for yearly or monthly capacities. Programming authorisations for yearly or monthly capacities that were not nominated by the participant are automatically resold to the relevant daily allocation.243 The non-nominated programming authorisations for yearly and monthly capacities are financially compensated to the participant depending on the price in the daily allocation.244
TSOs must work out harmonised allocation rules for PTRs and FTRs. The rules for PTRs and FTRs should be consistent with each other.245 NC FCA lays down a list of the minimum contents of the harmonised allocation rules.
The rules must contain at least: (a) harmonised definitions and interpretation; (b) harmonised provisions on eligibility and entitlement, on suspension and renewal, and on costs of participation; (c) a description of the forward capacity allocation process including at least provisions on auction specification, submission of bids, publication of auction results, contestation period and fallback procedures; (d) a description of the types of long-term transmission rights which are offered, including the remuneration principles; (e) harmonised provisions concerning netting policies and financial collaterals requirements specific for FTRs; (f) harmonised provisions for secondary trading; (g) harmonised provisions for the return of long-term transmission rights; (h) principle description of the applicable nomination rules246; (i) harmonised UIOSI provisions in case of PTRs; (j) firmness provisions and compensation rules; (k) harmonised provisions for financial requirements and settlement; and (l) a contractual framework between the allocation platforms and the market participants including provisions on the applicable law, the applicable language, including confidentiality, dispute resolution, liability and force majeure.247
EURELECTRIC and EFET have proposed the use of buy-back schemes.248 According to EFET, TSOs should buy back capacity in the secondary market instead of curtailing in the event of unexpected operational circumstances. EURELECTRIC would prefer TSOs to arrange a reverse auction when it turns out that they have sold too much capacity.
ENTSO-E believes that capacity buy-back “could only be applied with sufficient lead time and could therefore only address cases where the operational problems become obvious well in advance of real time”.249
ENTSO-E has also analysed design schemes that could be applied for such a purpose. They include: (a) voluntary buy-back schemes; (b) a compulsory buy-back approach for the total capacity that needs to be curtailed; (c) a compulsory buy-back approach for a partial amount of the capacity; (d) auction buy-back systems, where price formation is left to the market; (e) a fixed price approach with TSOs determining the price and disclosing it in advance; and (f) a reverse auction capacity buy-back approach with TSOs determining the price without disclosing it in advance.
According to ENTSO-E, the current NC FCA formulation does not preclude the possibility of capacity buy-backs taking place. However, ENTSO-E believes that buy-back schemes are not recommended from a TSO perspective.
Secondary Markets and MiFID II
A TSO may have to comply with MiFID II where it operates a secondary market for financial instruments such as a platform for secondary trading in financial transmission rights.250
5.7 Pricing Models
5.7.1 General Remarks
The model for the pricing of transmission services is connected with the model for capacity allocation (Sect. 5.4). As tarification models are largely unregulated at EU level, transmission tariffs are determined in different ways depending on the Member State251 but may consist of similar components.252 In most Member States of the EU, electricity producers generally do not pay the costs for the use of the transmission grid, or pay just a fraction of the costs (the G-component). Costs are mostly allocated to load (the L-component).253
Perspective
The function of transmission tariffs depends on the perspective. (a) From the perspective of electricity producers, tariffs are a cost for a service. Electricity producers prefer to minimise these costs like any other costs. (b) From the perspective of the TSO, transmission tariffs are designed to cover costs and provide an appropriate return on investment. Costs related to electricity transmission include: infrastructure costs (sunk investment costs, including costs for operation and maintenance); and costs for the use of infrastructure (losses, network constraints, ancillary services).254 (c) From a welfare perspective, transmission tariffs should also provide adequate long-term investment signals.
Signals
The price of transmission can influence the behaviour of electricity producers and end consumers. If prices are low, demand for most goods will be high. If the charges for using the transmission system are low, generation installations and loads can be sited far apart, and the amount of electricity that users wish to transmit between them can be high.255
The model for the pricing of transmission services can thus give locational and temporal signals for electricity supply (feed-in) and extraction (load). (a) The signals contribute to efficient use of the transmission infrastructure where they reflect costs caused by grid users, the transmission infrastructure is well interconnected, and the transmission system has several alternative sources of supply.256 (b) The absence of signals that reflect these costs implies that costs are socialised. The socialisation of costs would reduce the efficiency of the use of infrastructure. It would favour users in high-cost areas at the cost of users in low-cost areas.
Grid connection costs raise similar questions. There are costs for connecting the installation to the grid connection point and costs for upgrades in the distribution network and regional network. There are also network facilities for the provision of services to a single customer (dedicated facilities) and network facilities for the provision of services to multiple customers.257
Incentives to invest in generation installations or transmission infrastructure can depend on the allocation of costs for connecting the installation to the grid. The allocation of these costs can give locational and temporal signals. (The allocation of these costs has had an effect on investments in generation assets in the EU, Sect. 5.7.2)
Allocation of Costs
It is therefore important how the various kinds of costs are allocated between market participants. It is generally assumed, from the welfare perspective, that cost recovery should, as far as possible, be based on the principle of cost causality.258
Provided that there is competition in electricity generation, one might be tempted to argue that residual network costs should be allocated to consumers because they “end up paying the bill anyway”.259 Ultimately, end consumers end up paying all costs.260 Allocating costs to end consumers (the L-component) could help to create a level playing field for electricity producers and reduce entry barriers.
However, electricity producers would not receive any locational signals regarding the cost of transmission if transmission tariffs were only paid by end consumers. It has turned out that a certain share of the tariff (the G-component) should be allocated to producers from a general welfare perspective.261
Transmission Pricing Models
Various pricing models have been used in competitive markets for electricity. In addition to the allocation of costs, the models have broader goals from a general welfare perspective.
The pricing of transmission services should: promote economic efficiency; compensate grid companies fairly for providing transmission services; allocate transmission costs reasonably among all transmission users; and maintain the reliability of the transmission grid.262 According to a working group organised by the Energy Modeling Forum of Stanford University, transmission prices should: (1) promote the efficient day-to-day operation of the bulk power market; (2) signal locational advantages for investment in generation and demand; (3) signal the need for investment in the transmission system; (4) compensate the owners of existing transmission assets; (5) be simple and transparent; and (6) be politically implementable.263
These abstract goals are rarely met. For instance, the models used for the allocation of transmission capacity and for pricing in the national markets of the EU fail to provide sufficient locational signals in many Member States. This is, in particular, the case where transmission tariffs are paid only by end consumers. Moreover, tariffs do not target to recover the same costs in all countries, and tariffs in some cases also include costs not directly related to transmission infrastructure.264
Fixing the Tariffs
Transmission tariffs are fixed or their methodology is approved by the market regulator.
There are two customary methods to fix the tariffs in practice. The traditional method is based on costs (rate of return or cost of service regulation). The most common alternative is the use of a fixed price not based on costs (fixed price regulation). (a) Cost of service regulation is relatively easy to apply. However, it is combined with moral hazard (as there are weak incentives to increase efficiency) and adverse selection (as low-cost firms may pretend to be high-cost firms), and figuring out the costs would require high administrative costs. (b) Even fixed price regulation is easy to apply. It solves the problem of moral hazard. However, the problem of adverse selection remains unsolved.
A menu of cost-contingent contracts267 and simple menus of contracts268 lie between these two extremes. (a) The menu of contracts regulation could solve both the moral hazard and adverse selection problems. However, it is too complicated to be applied in practice. (b) It would be easier to apply the simple menu of contracts method that is a simplified form of menu of contracts regulation.269
Contents
In the following, we will discuss the various costs (Sect. 5.7.2) and the various models for the pricing of transmission services (Sect. 5.7.3). We will then discuss pricing models based on the flow (Sect. 5.7.4), distance sensitivity (Sect. 5.7.5), and geographical electricity price differentiation (Sect. 5.7.6). EU law is discussed in Sect. 5.8.
5.7.2 Costs
Transmission costs consist of many components.270 However, it can be difficult to calculate the costs even where the components are known. One of the reasons is that costs can be defined in different ways. There are different cost concepts, each of them relevant in a particular context. In some cases, the pricing model is not connected with actual costs.
Opportunity Costs
To make this character of costs explicit, economists use the concept of opportunity cost. It relates to a decision rather than to an economic good. Opportunity cost is defined as the benefit lost for not having the resources available for an alternative use. When opportunity cost is defined in this way, it is necessary to compare two scenarios. The opportunity cost of a decision depends on the perspective.271
Fixed and Variable Costs, Welfare
There are also other ways to define costs. One can distinguish between the fixed and variable costs of electricity transmission. Some of these costs are incurred by the TSO. Some costs are costs from a welfare perspective. There are also incremental costs.
First, the TSO will incur high fixed costs for transmission infrastructure. The fixed costs should therefore be allocated between the different categories of grid users.
Second, the TSO will incur some variable costs for the transmission of electricity even though electricity flows by force of nature. In particular, electricity producers must be compensated for the loss of electrical energy during transmission. Like fixed costs, this variable cost should be allocated between different kinds of grid users.
Third, from a welfare perspective, there is a variable cost caused by congestion. (a) Congestion is indirectly caused by the high fixed costs. As transmission infrastructure is costly to maintain and develop, the capacity of lines and nodes is limited and it is reasonable to accept some congestion in parts of the transport grid. (b) The cost caused by congestion is equal to the difference between the maximum welfare obtained without transmission constraints and the welfare that results from the actual dispatch.272
Fourth, there are incremental costs, that is, costs for any new facilities.
The pricing model should reflect the TSO’s fixed and variable costs, costs caused by congestion, and incremental costs.273
For instance, Regulation 714/2009 provides that tariffs for cross-border transmission services in the EU must “reflect actual costs incurred”. Tariff levels must “provide locational signals at Community level, and take into account the amount of network losses and congestion caused, and investment costs for infrastructure”.274
The pricing model can be designed to achieve this in many ways. For instance, nodal pricing is regarded as the best way to allocate transmission capacity when there is enough competition.275 When the buyer and the seller of electricity are located at different nodes (node 1 and node 2), there is a difference between the price of electricity at node 1 and node 2. From the perspective of the buyer and the seller, the difference appears as a transport fee. The “merchandising surplus” can therefore be paid to the TSO. By its very definition, the merchandising surplus is not based on the actual costs incurred by the system operator.276 It can nevertheless indicate willingness to pay for transmission between two nodes.277
Ultra Short-Term, Short-Term and Long-Term Costs (Infrastructure and Use)
One can also distinguish between long-term costs and two kinds of short-term costs. This means the separation of infrastructure costs and costs incurred for the use of the infrastructure.278 (1) Long-term costs relate to investment in new transmission infrastructure. The location of supply and demand can depend on tariff components that reflect these long-term costs. (2) Short-term costs relate to the use of the existing transmission infrastructure. They should cover operations and maintenance. The efficient use of existing transmission capacities and congestion management depend on the parts of the tariff aimed at the recovery of these costs.279 (3) Ultra short-term costs relate to real-time balancing under certainty about electricity supply and demand in the very short run. In this case, the TSO makes dispatch or demand curtailment decisions.280
For instance, various cost concepts have been adopted in Regulation 714/2009 and Regulation 838/2010.281 Regulation 714/2009 identifies long-term costs and the cost of losses. The costs shall be established “on the basis of the forward-looking long-run average incremental costs, taking into account losses, investment in new infrastructure, and an appropriate proportion of the cost of existing infrastructure”.282 Regulation 838/2010 complements Regulation 714/2009 by laying down the concrete methodology and providing for an ITC fund.283
Long-Term and Short-Term Marginal Costs
Costs can be average costs or marginal costs. There can also be a difference between long-term and short-term marginal costs.284 From a welfare perspective, optimal prices in the short term reflect the short-term marginal costs of electricity and its transmission. In the long term, however, optimal prices should reflect long-term marginal costs because long-term investments in electricity infrastructure depend on long-term profitability.285 While short-term marginal costs give correct signals for operations, long-term marginal costs are the appropriate basis for investment decisions.286
The short-term marginal cost of transmission could be defined as the sum of the cost of losses and the opportunity cost of congestion. It could also be defined as the difference between nodal prices. The long-term marginal cost of transmission could be defined as the cost of building more capacity to increase the flows that the grid can accept.287
Allocation of Costs Between the System Operator Generation and Load
One may ask to whom the various transmission costs should be allocated. There are various cost allocation methods (for EU law, see Sect. 5.8).
Obviously, costs cannot be allocated to the TSO as this would not be sustainable in the long term. Even in the short term, the allocation of costs to the TSO would have to be funded. Funding constraints can hamper investment in transmission infrastructure.
In Germany, the TenneT case was an example of funding problems when the TSO was responsible for costs and demand for new transmission capacity was too high.288
Costs can be allocated between generation and load (end consumers).289 In principle, costs could also be allocated to the state in which case transmission services would be subsidised (for state aid, see Sects. 3.7.8 and 8.5.6).
It is necessary to distinguish between transmission costs and costs for grid connection, including between different kinds of costs for grid connection. There are shallow and deep costs for grid connection.
The shallow costs of grid connection include the costs for the network facilities needed to connect a single user. The deep costs include the reinforcement of the grid. Whereas it is easy to identify the beneficiary of shallow costs, it is more difficult to identify the beneficiary of deep costs as deep costs may potentially benefit all grid users.
While shallow connections costs should probably be allocated to that particular user to give locational signals, deep connections costs could belong to the “residual network charges” and be treated like system operation costs.290
5.7.3 Classification of Pricing Models
Various models have been used for the pricing of transmission services in competitive markets for electricity worldwide. Even in the EU, there is “a wide heterogeneity in the current regulatory practice regarding electricity transmission tarification”291 (Sect. 5.8). One of the contributing factors is how the electricity industry was organised prior to deregulation.292
Different Classifications
The models can be classified in many ways. As different classifications focus on different aspects, one and the same model can fall under different classifications.
Cost-Based Transmission Pricing Paradigms
To begin with, one can focus on costs and classify the models based on the costs that they are designed to allocate. The cost-based transmission pricing “paradigms” reflect the distinction between costs for existing transmission infrastructure and costs for new facilities. These paradigms include293:
the rolled-in transmission pricing paradigm (all costs are summed up—“rolled-in”—into a single number, all cost components are included, and cost types are not distinguished; these methods include: contract path pricing, postage stamp pricing, the distance-based MW-Mile concept, and the power flow-based MW-Mile concept);