Transmission Contracts




(1)
Dept. of Accounting and Commercial Law, Hanken School of Economics, Vaasa, Finland

 




10.1 General Remarks


Electricity cannot be supplied without connecting wires and transmission capacity. Physical transmission contracts are contracts for the supply of transmission capacity.

A bilateral transmission contract is a contract between (a) a transmission service provider (usually the TSO that manages the grid or the operator of a merchant cable in countries that permit such business1) and (b) a transmission service customer (a distributor, an electricity producer that is directly connected to the grid, or a direct consumer that has a point of connection to the grid).


Mutual Rights and Obligations, Ancillary Services

A bilateral transmission contract lays down the parties’ mutual rights and obligations. (1) The transmission service provider: (a) undertakes to facilitate the transmission service customer’s grid connection (the connection of the customer’s equipment or plant used for the consumption, conveyance, or generation of electricity through lines at the point of connection); (b) undertakes to keep a certain amount of transmission capacity available for the service buyer for the transport of electricity between two locations according to the agreed schedule or schedules; and (c) provides ancillary services that facilitate the transport of electricity. For these services, the transmission service provider (d) collects payments (charges, tariffs, the price).2 (2) The service buyer (a) obtains the right to supply or extract electricity according to particular schedules; (b) undertakes to pay the price; (c) undertakes to supply or extract electricity according to the schedules; (d) undertakes to purchase the necessary ancillary services from the transmission service provider; and (e) undertakes to provide its own ancillary services.

In the US, the transmission service provider’s ancillary services are defined in the Pro Forma Open Access Transmission Tariff. Ancillary services are defined as “services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Transmission Provider’s Transmission System in accordance with Good Utility Practice”.3 The transmission provider is required to provide and the transmission customer to purchase the services. The ancillary services are defined as (1) Scheduling, System Control and Dispatch Service; (2) Reactive Supply and Voltage Control from Generation Sources Service; (3) Regulation and Frequency Response Service; (4) Energy Imbalance Service; (5) Operating Reserve—Spinning Reserve Service; and (6) Operating Reserve—Supplemental Reserve Service.4

To fulfil its own obligations in liberalised markets, the transmission service provider/system operator needs to purchase services from balancing service providers (Sect. 4.​10). These services can be called the ancillary services of grid users.

ACER defines the transmission customer’s ancillary services as “services necessary to support transmission of electric power between generation and load, maintaining a satisfactory level of operational security and with a satisfactory quality of supply. The main elements of ancillary services include active and reactive power reserves for balancing power and voltage control. Active power reserves include automatically and manually activated reserves and are used to achieve instantaneous physical balance between generation and demand. Further elements of ancillary services may include black start, inertial response, trip to houseload, spinning reserve and islanding capability”.5

In the EU, the TSO must use market-based methods used for the procurement of Frequency Containment Reserves (FCR), Frequency Restoration Reserves (FRR), and Replacement Reserves (RR). Moreover, each TSO must use standard products and specific products for this purpose.6


Characteristic Issues

There are characteristic issues managed in transmission contracts in addition to the generic issues, which are managed in all transactions and the issues managed in all long-term contracts.

The characteristic issues include: (a) connecting the customer’s assets to the transmission assets at the point of connection so the flow of electricity is possible (subject to energisation) (Sect. 10.2); (b) energising the point of connection to enable electricity to flow (Sect. 10.3); (c) scheduling the flow (Sect. 10.4); (d) exchange of information and metering (Sect. 10.5); (e) compliance with technical requirements (Sect. 10.6); (f) prevention of the flow (Sect. 10.7); (g) firmness and transferability (Sect. 10.8); (h) the allocation of the cost of losses (Sect. 10.9); (i) the setting of grid charges (Sect. 10.9); (j) the choice of sanctions for unauthorised use (Sect. 10.10); and (k) allocation of liability (Sect. 10.11).7

These issues are only partly regulated in Articles 32, 12, and 15 of the Third Electricity Directive. The purpose of the Third Electricity Directive is not to regulate transmission contracts as such.


Contract Types

The characteristic issues are addressed one way or another in all such contract relationships. The way they are addressed can depend on the particular type of transmission contract, and the contract types can depend on the model for the allocation of transmission capacity.

Generally, it can be distinguished between three conceptual models for the allocation of transmission capacity: the contract path model, the flow-based model, and the point-to-point model with implicit flows.

Of the three models, the contract path model is simple but problematic. Its starting point is the fiction that electricity moves over the contracted path of transmission lines. Of course, electricity does not really move over the contract path. The exception is a direct line, that is, a single transmission line connecting the power plant to the load. A direct line can also be a direct current (DC) or high-voltage direct current (HDVC) line.8

One can therefore distinguish between three main contract types for independent transactions for the supply of transmission capacity: (1) contracts for the use of a direct line or a closed circuit system (the contract path); (2) other explicit bilateral transmission contracts (the flow-based model); and (3) implicit transmission contracts (the point-to-point model with implicit flows).


System Operator’s Rules, Balance Contracts

For technical reasons, system operators must either adopt or apply rules setting out operational requirements for connection to the system.9 Because system operators are responsible for maintaining balance in the grid, they must also adopt balancing rules (Sect. 9.​2).10

For reasons of risk management, system operators make sure that these rules are incorporated into the transmission contract by reference. Acceptance of the TSO’s rules is often called the “balance agreement” (Sect. 4.​5.​7). There are also particular balancing contracts or control reserve contracts that facilitate real-time balancing (Sects. 4.​10 and 9.​3).

The terms of transmission contracts are constrained by the system operator’s rules (which influence actual flows).


Open Terms

Some of the customer’s contractual obligations must be relatively open because of the system operator’s own compliance obligations. In particular, the customer must comply with the detailed operational requirements for connection to the system as applied from time to time. These detailed requirements can be complemented by an open term such as the customer’s duty to observe due skill and care or good electricity industry practice.11


Firm or Non-firm Transmission Services

Firmness is a related question. Electricity transmission services can be firm or non-firm. The difference relates to reservation priority and priority when the flow is interrupted. (a) Depending on the agreed terms of the contract and the governing law, firm transmission services could be defined as transmission services that “may not be interrupted for any reason except during an emergency when continued delivery of power is not possible”.12 In EU law, one can distinguish between physical and financial firmness. Capacity holders must be compensated for any curtailment.13 (b) In contrast, non-firm transmission services may be interrupted for the benefit of firm transmission schedules or for other reasons.

When its services are firm, the system operator should of course be able to manage the risk that it cannot fulfil the contract. The TSO can do it in many alternative ways. EFET has given the following examples: (1) rescheduling or re-dispatching (either domestic or cross-border); (2) countertrading; (3) coordinating dispatch or re-dispatch of power plants and transmission asset management with neighbouring TSOs; (4) repurchasing transmission rights (either on its auction platform or on the secondary capacity market); (5) purchasing energy calls or selling energy puts; (6) curtailment (payments financed by revenues from prior sale of firm transmission rights); (7) creating additional price areas; and (8) conducting physical improvements to the transmission system.14


Transferable or Non-transferable

The question of firmness is connected with transferability. Long-term transmission contracts are a way to reduce risk, but it is possible that the transmission capacity becomes surplus to requirements. One may ask whether electricity transmission contracts are transferable or non-transferable. If contracts are not transferable, greater transmission capacity may need to be built to reduce congestion and transmission prices.15 If the contracts are firm and transferable, they have a higher market value.16


Fixed or Variable Obligations

In principle, all obligations can be fixed or variable.17 There are core obligations that necessarily have to be fixed because of the nature of electricity transmission, core obligations that are fixed because of benefits to both parties, and core obligations that are fixed because of the bargaining power of a party.

Both parties can benefit if some of the core obligations are fixed. (a) Disclosure of information belongs to the core fixed obligations because of the nature of electricity transmission. (b) Moreover, the system operator can make more effective use of the transmission network where the transmission service buyer has an obligation to supply electricity to the grid (or an obligation to extract electricity from the grid) rather than a mere option to do so. A fixed obligation makes it easier for the system operator to schedule other flows, in particular counter flows.18 (c) Investors in power plants can prefer firm transmission rights rather than a mere promise of being allowed to participate in a short-term spot market for transmission services.19

The obligations of sellers and buyers are fixed on electricity spot markets such as Nord Pool Spot20 and EPEX Spot.21


Microgeneration

There are particular aspects relating to the regulation of the connection of microinstallations (microgeneration) to the grid (Sect. 10.2.3).


10.2 Connecting the Customer’s Assets to the Transmission Network



10.2.1 General Remarks


There are no electricity flows from or to the transmission service buyer’s assets, unless its relevant assets are connected to the transmission service provider’s transmission assets. The customer thus needs a contract facilitating grid connection. The contract on grid connection can be part of the transmission contract or a separate contract preceding the transmission contract. An agreement on grid connection does not yet give the customer any right to supply electricity, extract electricity, or use the grid for the purposes of the transmission of electricity.

There are two kinds of assets that will be connected under the contract on grid connection, namely the customer’s relevant assets and the transmission assets. (1) The customer’s relevant assets are assets that are: (a) used for the consumption, conveyance, or generation of electricity; and (b) connected to the agreed point of connection. The assets may consist of lines, equipment, or a plant. They may be owned or managed by the customer. (2) The transmission assets consist of the grid (or the direct line) and assets that form part of the grid (or the direct line).

In the EU, the connection of generation assets to the grid (that is, a transmission, distribution, or closed distribution network) is regulated in detail by ENTSO-E Network Code on Requirements for Grid Connection applicable to all Generators (NC RfG). Each owner of a power generating facility must ensure that it complies with the requirements under the Network Code throughout the lifetime of the facility.22 NC RfG is complemented by ENTSO‐E Network Code on Demand Connection. The latter sets up a common framework for network connection agreements between network operators and demand facility owners or distribution network operators.23 In situations where generation and demand co‐exist in a demand facility or closed distribution network, the one Network Code applies to pure generation and the other to pure demand.24


10.2.2 Contract Terms


The transmission service provider (the TSO) and the customer must agree on a number of things to connect the assets:25 the characteristics of assets; the allocation of costs the right to connect assets; TSO approvals; compliance with technical requirements; product safety; compliance with general standards; and land rights.


Existence of Assets

First, the necessary assets must exist and fulfill the technical requirements. These requirements can be derived from the regulatory framework or contract. Technical requirements are partly based on regulation. The technical requirements must be “objective and non-discriminatory” in the EU.26 They are partly harmonised by the Network Code on Requirements for Generators (NC RfG).27

If the necessary assets do not yet exist or do not yet fulfill the technical requirements, the assets must be built and installed or improved. It is necessary to regulate the allocation of responsibilities and the distribution of these costs.

One may ask whether the TSO has a duty to connect the customer’s relevant assets to the grid where the transmission assets do not yet exist. Obviously, it would be impossible to connect the assets in this case. It would be possible to lay down a duty to ensure that the relevant transmission assets are in place and allocate costs caused by the delay.

The allocation of responsibilities and costs can also be from mandatory law. The Third Electricity Directive provides that each TSO is responsible for “ensuring the long-term ability of the system to meet reasonable demands for the transmission of electricity”28 and for “contributing to security of supply through adequate transmission capacity”.29


Allocation of Costs

Second, there is thus the question of allocation of costs. The Third Electricity Directive does not state exactly how these costs should be allocated, but it is clear that the method of allocating them must be objective and non-discriminatory.30

In Germany, the existence of both a duty to connect assets and a duty to pay for the costs31 have placed a heavy financial burden on system operators in the case of offshore wind farms (Sect. 5.​8.​2).

In the US, the Pro Forma Open Access Tariff gives the transmission provider a right to defer providing service until it completes construction of new transmission facilities or upgrades whenever it determines that providing the requested service would, without such new facilities or upgrades, impair or degrade reliability to any existing firm services.32 Moreover, the obligation to provide the requested transmission service can be terminated in the event that the facility additions remain unfinished.33

The allocation of costs can depend on whether the costs are related to the upgrade of the transmission grid, the distribution grid, or a radial line. Upgrades in the transmission grid and in the distribution/regional grid are treated differently in different countries. (a) Costs related to the upgrade of the transmission grid are generally socialised. In other words, the costs are borne by network companies that can recover them via network tariffs. (b) The costs of upgrades of the distribution network are often allocated to the customer that caused the upgrade. (c) However, there are different ways to regulate this issue. Costs are allocated in different ways in Germany, Sweden, and the US.

In Germany, the costs of upgrades of the distribution network are socialised. In Sweden, project developers pay the costs for the upgrade of a radial line while costs for upgrades in the meshed grid are shared between the owner of the production plant and Svenska Kraftnät. Project developers in Sweden have to pay most network investment costs.34 In the US, the Pro Forma Open Access Tariff provides that the transmission provider will use due diligence to expand or modify its transmission system to provide the requested firm transmission service, but only provided the customer agrees to pay the costs.35

The grid connection assets may need to be changed for capacity, security, or other reasons. In the absence of mandatory legislation, the parties may agree on the allocation of these costs and that changes in the connection assets are considered in the tariffs or the transmission pricing methodology (for the regulation of transmission pricing, see Sects. 5.​7.​3 and 5.​8.​3).


Right to Connect Assets

Third, the TSO permits the customer to: (a) connect particular customer assets to the grid at the points of connection; and to (b) remain connected for the purpose of the transfer of electricity between the grid and the customer’s assets.


No Connection Without Prior Approval

Fourth, the customer must not connect any equipment to the grid without the prior approval of the TSO. The TSO needs to control the design and specifications of equipment connected to the grid. The TSO may also require prior testing according to a testing plan, which it has approved in advance. Moreover, the TSO may require the replacement of equipment.


Compliance with Technical Requirements

Fifth, both parties agree to comply with the relevant technical requirements. They include the technical requirements of: connection; the operation of the connection; and the maintenance of the connection.

Because the technical requirements are vital for safety and reliability, the agreed obligations of the customer to comply with the technical requirements have a relatively broad scope. According to the agreed terms, the customer is responsible for any equipment that can affect the security or operation of the grid. The customer is thus made responsible both for assets physically connected to the grid and for assets that are not physically connected to the grid but can affect the security, management, operation, or performance characteristics of the grid.

The contract lays down the most important requirements. However, the TSO needs to reserve the right to change the requirements because of its own general duties. The customer wants to limit the changes to what is necessary. The contract may thus provide, for instance, that the TSO may unilaterally impose any reasonable technical requirements in accordance with good electricity industry practice.

The technical requirements that the parties must regulate relate to, for instance: the connection of instrumentation and control circuits; the grid interface (the provision of grid interface switchgear; the insulation of equipment at the grid interface; earthing arrangements for the grid interface); the control of voltage levels and imbalances (the equipment must be designed and maintained so voltage levels and imbalances can be controlled); and the clearance of faults.

In addition to such technical requirements relating to connection, the parties must regulate maintenance obligations. They undertake a general duty to maintain equipment so it always complies with the applicable standards.

There are also several operating requirements. Each party must ensure that its equipment: (a) has no adverse effect on the grid or the ability of the TSO to manage the grid; (b) can be operated within the minimum and maximum system voltages; (c) has no adverse effect on other customers or their ability to manage their equipment; (d) is designed and installed so maintenance can be carried out; (e) does not present a safety hazard to the other party or other customers (or their respective employees and agents) or the general public; (f) does not cause a contract party to breach any legislation; (g) performs its intended function to the required standard; (h) does not cause the maximum short circuit power and current limits specified in the contract to be exceeded on or nearby to the grid; (i) is capable of being operated and operates within the limits that the customer has disclosed to the transmission service provider; and (j) meets any other requirements imposed by the transmission service provider in writing acting reasonably and in accordance with good electricity industry practice.36


Product Safety

Sixth, each party agrees to ensure product safety. The customer ensures that the connection, operation, and maintenance of the customer’s assets will not adversely affect the grid or the management of the grid. The transmission service provider ensures that the grid connection and the maintenance and operation of the grid do not adversely affect the customer’s assets or the use or management of the customer’s assets.


General Standards

Seventh, each party agrees to comply with other applicable general standards.


Land Rights

Eighth, the parties must agree on land rights. There must be a physical place for the point of connection and the necessary equipment and structures.


10.2.3 Microgeneration


Microgeneration (distributed generation)37 is connected to the low voltage distribution level or the medium voltage distribution level (for grid levels, see Sect. 5.​4).38 The DSO is responsible for the connection of microgenerators to the distribution grid.39 The introduction of net metering and net billing is designed to increase microgeneration.


Preferential Treatment

As microgeneration is often generated from renewable sources or waste or CHP, it benefits from preferential treatment than electricity generated from conventional sources.

Each DSO has a general obligation to operate and develop the distribution system in its area,40 including an obligation to connect customers to its network.41 Microgeneration must therefore be connected to the grid (for the allocation of costs, see Sect. 5.​8.​2). Even microgeneration must comply with the terms of NC RfG.42

Discrimination is prohibited,43 but a Member State may “require the distribution system operator, when dispatching generating installations, to give priority to generating installations using renewable energy sources or waste or producing combined heat and power”.44 These installations can also benefit from preferential feed-in tariffs and other preferential treatment (Sect. 3.​7.​7 and Chap. 7).

It is nevertheless to be noted that there is no exemption from the regulation of grid connection,45 there is no exemption from the regulation of imbalances and the duty to have a balance responsible party,46 and there is no preferential treatment for the provision of balancing services (although EU law facilitates wider participation in this respect).47


Closed Distribution Systems and Power Generating Facilities

In practice, it is possible that a microgeneration unit is integrated with other microgeneration units or electrical appliances. One may ask whether they form a distribution system or a closed distribution system, that is, a person’s own network that serves the owner itself.48 Depending on the Member State, closed distribution systems may partly be exempted from some of a DSO’s obligations.49 Can a microgenerator that uses its own network be regarded as a DSO50 or as an operator of a closed distribution system (CDSO)?51

According to the wording of the Third Electricity Directive, regulated distribution requires the existence of a “customer” to whom electricity is distributed.52 This seems to: (a) exclude systems that do not supply any person other the undertaking itself; but (b) include systems that serve even one or more outsiders.

This leaves the definition of closed distribution systems. A closed distribution system is a qualified distribution system. It is “a system which distributes electricity within a geographically confined industrial, commercial or shared services site … if: (a) for specific technical or safety reasons, the operations or the production process of the users of that system are integrated; or (b) that system distributes electricity primarily to the owner or operator of the system or their related undertakings”.53 Such sites include, for instance, “train station buildings, airports, hospitals, large camping sites with integrated facilities or chemical industry sites … because of the specialised nature of their operations”.54

The system can also be regarded as a power generating facility. A power generating facility is neither a distribution system nor a closed distribution system. A microgenerator can customarily be regarded as a power generating facility owner rather than as a DSO or CDSO in the light of definitions in NC RfG:



  • A power generating facility owner is defined as a natural or legal entity owning a power generating facility.


  • A power generating facility is defined as a facility to convert primary energy to electrical energy which consists of one or more power generating modules connected to a network at one or more connection points.


  • A power generating module is either a synchronous power generating module55 or a power park module.56


10.3 Energising the Point of Connection


One can distinguish between connection and energisation. On one hand, electricity cannot flow across the connection point between the system of the transmission service provider and the customer’s system unless the systems are connected. On the other, there will be no electricity flows unless the connection point is energised. A connection point is energised by moving a switch or adding a fuse. A metering point or a metering system is energised by adding a meter.

NC RfG provides that the operational notification procedure for connection for each new Type D Power Generating Module consists of: an Energisation Operational Notification (EON); an Interim Operational Notification (ION); and a Final Operational Notification (FON).57 An Energisation Operational Notification is issued by the relevant network operator.58 It will entitle the power generating facility owner to energise its internal network and auxiliaries for the power generating modules by using the grid connection that is defined by the connection point.59


10.4 Allocation of Transmission Capacity and Scheduling


The customer uses the transmission capacity allotted to it. Because of the balance requirement and scarce transmission resources, the transmission system operator must ensure that there is a mechanism for the allocation of transmission capacity and for the scheduling of electricity flows. It is necessary to agree on the flows in advance.

The allocation of transmission capacity depends on the market (Chap. 5). (a) The use of implicit auction mechanisms means that transmission capacity is allocated implicitly and the customer does not need to agree on the allocation of transmission capacity separately. (b) On the other hand, there are also explicit bilateral transmission contracts (the flow-based model). In this case, the parties must agree on the allocation of transmission capacity explicitly.

According to the CACM Regulation, implicit allocation is the main rule for cross-zonal capacity allocation in the day-ahead and intraday timeframes.60

Explicit allocation could be used as a transitional arrangement under ENTSO-E Network Code for Capacity Allocation and Congestion Management (NC CACM) that preceded the CACM Regulation.61 The CACM Regulation limits the use of explicit auctions as a transitional arrangement to intraday markets.62

NC CACM contained a particular rule on explicit requests for capacity: “The explicit request for capacity can only be submitted by a Market Participant for an interconnection where the Explicit Allocation is applicable. For each explicit request for capacity the Market Participant shall submit the volume and the price to the Capacity Management Module. The price and volume of Explicit Allocated Capacity shall be made publicly available”.63

Explicit auctions are the main rule for long-term cross-zonal capacity allocation according to ENTSO-E Network Code on Forward Capacity Allocation.64

In principle, the allocation of transmission capacity and the obligations of the TSO can be firm or non-firm (Sect. 5.​6.​5).

ENTSO-E Network Code on Forward Capacity Allocation and the CACM Regulation lay down firmness deadlines. The firmness deadlines depend on the duration of the contract (long-term,65 day-ahead,66 or intraday67). There are special rules for force majeure and emergency situations.68


Characteristic Terms

We can focus on explicit contracts. In bilateral transmission contracts, the transmission service provider agrees to make transmission capacity available. The availability of transmission capacity is limited to: the agreed circuit(s) of transmission lines; the agreed points of supply (injection, delivery) and extraction (off-take, receipt); and the agreed schedule.

The customer agrees to submit schedules in advance. In other words, it must notify the TSO of the flows.

In the EU, ENTSO-E Network Code on Operational Planning and Scheduling requires the use of a scheduling agent. Schedules are submitted to the TSO by the scheduling agent.69

In the US, the Pro Forma Open Access Transmission Tariff provides that schedules for the transmission customer’s firm point-to-point transmission service must be submitted to the transmission provider no later than 10 a.m. on the day before the commencement of the transmission service—or a reasonable time that is generally accepted in the region and is consistently adhered to by the transmission provider.70


10.5 Exchange of Information and Metering


There are extensive disclosure duties because of the nature of electricity transmission and the balance requirement. The transmission contract will lay down obligations to provide information about: the relevant assets; the operation of the relevant assets; demand or supply (the anticipated supply of electricity or the anticipated demand for electricity); and conveyed electricity (metered quantities).

For metering and disclosure of information, the transmission customer needs metering and communications equipment, which is compatible with transmission service provider’s equipment. The equipment must be installed and maintained.71


10.6 Compliance with Technical Requirements

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