Setting the Scene

To begin with, there would be neither wholesale markets nor competition without high-voltage transmission. It is less costly to move electricity through high-voltage transmission lines. This is because of losses in transformation and distribution.¹ In the absence of high-voltage transmission, generation would have to be located very close to demand. The best economic option for electricity generation would be a regulated local monopoly.² High-voltage transmission allows a more favourable location of generators, and also allows the possibility of economies of scale in generation.

Generators can control their output voltage by adjusting their magnetic field. The voltage is lowered by resistance in electric lines (impedance). Transformers in the distribution system can adjust their output voltage and adjust for the drop in voltage caused by the line losses.

Electricity is supplied at a certain frequency. The system frequency is determined by the running speed of the generators. Where electricity demand exceeds the driving power of the generators, the rotational speed of the generators drops and the frequency of the voltage decreases. Moreover, the power capacity of a generator decreases when its rotational speed drops.³

Because of economies of scale in electricity production and transmission as well as the existence of transaction costs, electricity producers have an incentive to sell electricity to large customers with stable loads at the high-voltage level. Where electricity and transmission prices reflect costs, high-voltage customers pay less than low-voltage consumers. There should thus be a price difference between the wholesale level and the retail level. Charging the same price would mean that high-voltage consumers pay subventions to low-voltage consumers. From a legal perspective, this means that price differences between wholesale and retail markets are not discriminatory as such.⁴

Before the restructuring and unbundling of electricity markets, the participants in the wholesale market were mainly vertically integrated firms each of which had a local or regional monopoly. Electricity trade was thus trade between monopoly firms and mainly consisted of long-term supply contracts.⁵ After the restructuring of markets, more participants have been able to enter the wholesale market.

The wholesale market has many functions. (a) Generally, the wholesale marketplace provides information about the price of electricity. The spot market determines the reference price for day-ahead or intraday deliveries of electricity in the wholesale market. The financial market provides reference prices for the physical delivery of electricity in the future.⁶ Changes in the prices of spot contracts, options, and futures in the wholesale market indicate that the prices charged from end consumers will change as well.⁷ For this reason, electricity exchanges are important for all electricity consumers whether they participate in the wholesale market or not. (b) The wholesale marketplace provides a distribution channel for electricity producers and a source of supply for electricity suppliers and large electricity consumers such as industrial firms.⁸ (c) Wholesale market products help system operators to ensure security of supply and maintain system frequency in real time. (d) The products traded in the wholesale market can enable an efficient portfolio and risk management.⁹ This will also foster investment in electricity generation and transfer infrastructure and increase security of supply.¹⁰

Electricity contracts are settled physically and/or financially in the wholesale market.

Contracts that are settled physically (physical contacts) can be short-term contracts (spot contracts) or long-term contracts (forwards or other long-term contracts). (a) The spot market is the market for exchange-traded short-term electricity contracts that are settled physically. The spot market can be used to achieve a transparent, competition-driven price for a short period of time in advance. The spot market reacts to short-term changes such as the weather or technical problems.¹¹ There is a day-ahead market for each hour of the following day. There is also an intraday market enabling market players to balance their positions ahead of physical delivery. The intraday market is becoming increasingly important because of increased use of intermittent sources of electricity (such as wind power with uncontrolled increases or decreases in output). (b) Long-term contracts can be relatively simple forwards or more complex long-term contracts such as total supply contracts, base-load contracts, delivery schedules,¹² peak-load contracts, or reserves.¹³ They can also be contracts in which the price is linked to an index for electricity (the market price on an exchange) or fuel (such as oil, gas, or coal),¹⁴ or structured contracts (Sect. 8.​2). (c) The spot market is complemented by the balance market or market for control reserves (Sect. 4.​10).

Financial contracts are settled financially (in cash or by the delivery of underlying physical contracts). The financial market (contract market) enables market participants to transfer the price risk. Alternatively, market participants may speculate against price developments in the future. Customary financial contracts include options, futures, and swaps.

In practice, contracts called futures are either contracts for difference and settled in cash, or contracts which lead to the physical delivery of electrical energy. The same can be said of forwards. (For the terminology and the difference between futures and forwards, see Sects. 8.​2.​3 and 11.​2).¹⁵

Electricity is traded on electricity exchanges or over the counter (OTC). OTC trading of electricity means all wholesale trade outside electricity exchanges. While exchange-traded electricity contracts must always be standardised and many OTC-traded contracts are relatively standardised in practice, OTC contracts can also be negotiated individually between the parties.¹⁶ Such individually-negotiated contracts are customarily long-term contracts made directly between the buyer (distributor or a large industrial customer) and the seller (a large energy generator) for large amounts of power (Chap. 8).

Cross-border trade has an effect on electricity prices. Cross-border electricity flows make it easier to meet peak demand when there is not enough generation capacity, or to balance supply and demand when there is excess supply. Moreover, cross-border electricity flows help to optimise the use of different kinds of utilities, and to benefit from regional differences in the mix of primary sources of energy.¹⁷ Cross-border trade is constrained by the availability of interconnector capacity.¹⁸

For example, interconnector capacity makes it possible to import electricity to Finland from Sweden, Russia, Estonia, or Norway when Finnish power demand exceeds generation.¹⁹

Most of the electricity generated in Norway is hydropower. With sufficient interconnector capacity, Norwegian hydropower could complement the increased use of intermittent generation technologies in other countries.

The variable production costs of hydropower are low. However, higher prices could be imported to Norway from other Nordic countries and from the European continent through interconnectors.²⁰ For the same reason, Swedish electricity prices are lower in the North and higher in the South.

Cross-border trade could be increased if there were storage capacity on the other side of the border. When the price of electricity is negative in Germany, an Austrian firm that has invested in pumped hydro storage (PHS) plants in the Alps could switch on the pumps and get paid for extracting electricity from the German grid. When German electricity prices are high, the firm could produce hydropower and get paid for supplying electricity to the German grid.

Prices on electricity exchanges can function as reliable price indicators provided that there is enough liquidity. The prices are important not only for participants trading on the particular exchange but also for parties to bilateral contracts such as supply contracts between producers and industrial customers. The most liquid products are customarily derivative contracts traded on organised trading venues. They attract the broadest group of users and investors.

In the future, prices determined on electricity exchanges will become even more important because of unbundling, the increased integration of national electricity markets, market coupling, and the allocation of cross-border transmission capacity through auctions. Market coupling means that available day-ahead cross-border capacity is considered in determining the energy price (Chap. 6). In addition, market coupling enables cross-border price arbitrage.²¹

The vertically integrated market model tends to reduce liquidity. Unbundling tends to increase it. On the other hand, liquidity might also be increased by increasing interconnector capacity, the participation of large consumers and financial institutions in the wholesale market, higher utilisation of clearing and exchange-based trading, as well as reliable reference prices.²² The collapse of Enron in 2001–2002 and the following exit of a number of active wholesale market participants reduced liquidity in the UK.²³

The system operator is responsible for maintaining balance in the grid. For this reason, it must estimate future generation and load. However, actual generation and actual consumption become known in real time. The system operator fills the gaps in the balancing market (Sect. 4.​10).

The balancing market is facilitated by the TSO’s contractual framework. (a) As a rule, a market participant has no access to the physical market without accepting the TSO’s contractual framework. Acceptance of this framework is often called a “balance agreement”. (b) In addition, there are particular contracts for the provision of market participants’ “ancillary services” in the balancing market for the balancing of the system (Chap. 9). Since there are many different products for the balancing of the system, there are in fact many balancing markets.²⁴ (c) A new European regulatory framework facilitates the integration of balancing markets (Sect. 4.​10).

The wholesale market for electricity is complemented by the market for transmission capacity (Chap. 5). The marketplace for transmission capacity resembles the electricity wholesale market in that there are both physical and financial markets for transmission capacity. There is no electricity trade without transmission capacity and no effective physical market without non-discriminatory network access.²⁵

Scarce physical transmission capacity must be allocated. In an efficient electricity market, the available transmission capacity should be transparent for market participants and there should be an efficient method for allocating it. In the internal market, this requires the harmonisation of security, planning and operational standards.²⁶

Physical transmission capacity can be allocated in various ways (Chap. 5). Generally, the method for capacity allocation goes hand in hand with the pricing method. The methods can be market-based or not market-based. (a) Market-based allocation methods mean implicit or explicit auctions. They are widely used in European electricity markets. (b) However, many methods are not market-based. They include, for instance, the reservation of transmission capacity under long-term bilateral contracts. In gas markets, it has been customary to use pro rata allocation and the first-come-first-serve method.²⁷

The physical transmission market is complemented by the financial market. The availability of derivatives on electricity transmission capacity can improve access to transmission capacity and safeguard investment in transmission networks.

Cross-border flows require both internal and cross-border transmission capacity.²⁸ Although the volume of cross-border electricity trade was not large in the past,²⁹ cross-border electricity flows have become increasingly important.

German transmission bottlenecks provide an example of the effect of internal congestion on cross-border flows. While wind power capacity and new conventional power plants are mainly located in the north, demand rises mostly in the south. There are similar issues in Sweden. While hydro reservoirs are concentrated in the north of Sweden, most of the consumption is in the south.³⁰

For many reasons, the electricity wholesale market thus consists of many markets. (a) Physical wholesale markets are national or regional. European markets used to be national, because the European market is mostly divided into the control areas of national TSOs with scarce cross-border interconnection capacity between the areas.³¹ Market coupling projects have increased the geographical scope of markets. (b) Most physical electricity used to be traded OTC, but electricity exchanges are becoming increasingly important. In principle, the liberalised market model could consist of bilateral contracting complemented by an electricity exchange (for instance, the Nordic countries, Germany, and the Netherlands) or mandatory centralised auction in which all power, except industrial self-generation, is offered (for example, the UK and Spain).³² (c) There are different markets for different physical products. One can distinguish between a market for long-term bilateral supply contracts, physical spot markets (day-ahead markets, intraday markets), and markets for balancing energy and reserves. (d) Physical markets for electricity are complemented by other markets. There is a market for transmission capacity. The method of allocating transmission capacity and the pricing method depend on the country.³³ There is also a market for emission rights. (e) In financial markets, products can again be traded OTC or on an exchange.

Table 2.1 shows what products customarily are traded in the physical electricity wholesale market.

Electrical energy is generated and sold in bulk by electricity producers.³⁶ The generation business is the heart of the electricity supply industry. Electricity generation used to be the largest component of an end consumer’s electricity costs. Generation is also combined with a high level of risk for electricity producers.³⁷

There are two kinds of electricity suppliers: (a) electricity wholesalers supply electricity to other electricity firms³⁸ or large end consumers; and (b) electricity retailers supply electricity to end consumers.³⁹ Electricity retailers can also be called load-serving entities (LSE).

Electricity suppliers must either buy or generate the electricity that they intend to supply. One can distinguish between (a) vertically integrated firms that generated electricity and (b) pure electricity suppliers.

In the past, many electricity suppliers were vertically integrated utilities. There is more room for pure electricity suppliers in unbundled electricity markets.

The entry barriers are low. Unlike electricity generation, electricity supply is not capital intensive. An electricity supplier does not need to own any network facilities or power plants. It can outsource meter reading and billing. In other words, an electricity supplier needs little more than a telephone and a computer to operate a supply business. Electricity supply is a high turnover, but low capital and low margin business. Compared with electricity generation and transmission/distribution, electricity supply is the smallest component of an end consumer’s electricity bill.⁴⁰ It includes metering and billing.

One could say that the supply company negotiates with the generation sector on behalf of end consumers. The supply company represents the electricity industry’s main interface with end consumers.

End consumers try to obtain adequate security of supply at low cost. There is a difference between large consumers and small consumers.

Large consumers tend to be commercial or industrial firms or public sector entities that can buy electrical energy at the high-voltage grid level. If they are directly connected to the transmission grid, they may be able to offer balancing services (demand response or demand side response⁴¹) to the system operator.

Small consumers customarily are residential (household) consumers or small firms.⁴² They pay the local distribution system operator (DSO) for grid access and distribution capacity and buy electricity from a retailer. Their participation in the electricity market is usually limited to choosing the retailer and consuming electricity. In unbundled markets, the DSO is the retailer.

System operators provide a wide range of important services. Transmission rights must be defined and allocated to system users. Transfers may need to be rescheduled by a party responsible for dispatching to make them consistent with available transmission capacity. It is necessary to cover losses and balance the system in real time. It is necessary to meter energy flows and to arrange payments for imbalances and ancillary services.⁴³ The system operator must also be notified by system users in advance of scheduled electricity transfers.

One can distinguish between commercial transmission and commercial distribution of electricity. Electrical energy is transmitted in bulk to wholesalers and large industrial customers at a high voltage level.⁴⁴ It is distributed in smaller quantities to retail customers at a lower voltage level.⁴⁵

One can also distinguish between transmission firms and transmission system operators. They have different functions: (1) A transmission firm owns transmission system assets such as lines, cables, transformers, and reactive compensation devices. For instance, a merchant line is a particular interconnector.⁴⁶ (2) The transmission system is operated according to the instructions of a transmission system operator (TSO). Generally, transmission planning is more difficult in liberalised markets.⁴⁷ (3) Whether a transmission firm or a transmission system operator may own electricity generation plants depends on regulation.

In the EU, the main rule is that the first and second of these three functions are combined and the third separated. Each undertaking that owns a transmission system must act as a transmission system operator. The transmission firm/transmission system operator must not perform any of the functions of generation or supply.⁴⁸

There can also be independent system operators.⁴⁹ An independent system operator (ISO) is independent of the owner of transmission assets and owns computing and communication assets.

A Member State of the EU may designate an independent system operator under certain circumstances.⁵⁰ The terminology is different in the US (see Sect. 3.​5.​5).

A distribution system operator (DSO) owns and operates a distribution network.⁵¹ Compared with electricity transmission, electricity distribution: has more customers; must adapt to larger variation in load; requires a larger investment for the same amount of supplied energy; can cause lower interruption costs; and requires less monitoring.

Each power distribution firm enjoys a monopoly for the distribution of electricity to retail customers in a given geographical area. For this reason, electricity distribution is a regulated business. The distribution firm can try to maximise the regulated profit. Competition can be increased, if the operation and development of the distribution network is separated from the supply of electrical energy to retail customers. In the EU, this is addressed by the unbundling regime.

An organised market for electrical energy has a market operator. A market operator has two main functions. It runs the computer system that matches bids and offers submitted by buyers and sellers. In addition, it runs the market settlement system by monitoring the delivery of energy and transmitting payments from buyers to sellers. The market operator tries to run an efficient market to encourage trading.

Regulators are government bodies. They determine or approve market rules, investigate suspected abuses of market power, and set the prices for products and services provided by monopolies. The regulator tries to ensure: that the overall electricity sector operates in a fair and economically efficient manner; that the overall electricity sector operates in a reliable manner (adequacy and security); and the quality of supply.

A market participant may prefer to use a broker for various reasons.⁶¹ First, trading on electricity exchanges is limited to members, and not all market participants are exchange members. Non-members can trade through a broker that is a member. Second, using brokers may reduce search costs (a component of transaction costs) in OTC markets, because brokers tend to be well-informed. They would not be able to match parties without a network of clients and information about their specific needs. Third, a market participant may prefer to remain anonymous. For instance, a market participant that needs to purchase or sell large quantities of electricity may want to keep its total trading quantities secret to avoid an adverse impact on price. Moreover, each market participant has internal limits for trading with other market participants, and small internal limits may prevent it from dealing with a market participant whose quota is full. Using a broker enables an electricity firm to divide its total supply or demand between various contract parties.

A broker that has an established analysis unit and a customer base may be in a position to move to portfolio management.⁶²

The services of portfolio managers include: pure advisory services (the portfolio is managed by the customer); portfolio optimisation (the customer outsources the management of the whole portfolio but takes the decisions itself); portfolio management (the customer outsources the management of the whole portfolio); and load-serving total supply contracts (vertical integration).⁶³

Portfolio management is a service that could be used by industrial consumers that have limited resources and cannot afford a separate analysis unit.⁶⁴ On the other hand, even large industrial consumers can outsource part of their work in this way. The same can be said of electricity suppliers.⁶⁵

An electricity producer tries to make a profit from the supply of energy and the provision of ancillary services. An electricity producer owns and/or operates one or more plants. This can be a single plant, a portfolio of plants with the same technology, a portfolio of plants with different technologies, or a portfolio of plants with different locations. Different plant types are needed for different segments of electricity production.

Depending on the market segment, an electricity producer must choose between intermittent generation technologies (such as wind or solar) and dispatchable technologies (that will generate electricity during all hours of the year)⁷⁹: (a) Base-load plants should have low fuel costs and be able to run 24 h/day at fixed load. The start-up time and the ramp-up rate are less relevant for base-load plants. Nuclear power is an example of base-load generation. (b) Intermediate load plants should be able to ramp up rapidly and deliver close to constant output during, say, 15 h. (c) Peaking plants should need relatively low investments (as they will be used rarely) and be able to run, for instance, less than 4 h with plenty of output variation. (d) Balancing and regulating plants must be flexible. For instance, hydropower is suitable for this purpose.⁸⁰ (e) Back-up capacity in smart grids should be provided by power generation that has seemingly conflicting characteristics: high fuel efficiency, quick starting, and a fast response to load steps.⁸¹ This could be achieved, for instance, by cascading a number of parallel high-performance generating units⁸² (that is, switching parallel generators on and off depending on power demand).⁸³

The plant type is connected with the availability and liquidity of contracts. To illustrate, the absence of long-term supply contracts and liquid forward contract markets can reduce electricity producers’ incentives to invest in capital intensive generation technologies and increase the popularity of less capital intensive technologies (such as combined-cycle gas turbines, CCGT). The availability of long-term supply contracts and the existence of a liquid forward contract market can make it easier for electricity producers to invest in capital intensive technologies.⁸⁴

The plant types influence market prices. The lack of base-load plants, which customarily require a large capital investment, means that marginal prices are higher during a larger part of the year.⁸⁵ Moreover, the choice of the RES-E support mechanism will influence investment in different types of plants and therefore also market prices.⁸⁶

Changes in market regulation have had an impact on the choice of technologies and investment trends as electricity producers’ exposure to market and legal risk has increased. Electricity producers are less likely to invest in capital intensive technologies with long construction times. They are more likely to prefer technologies with short lead times that can be built in small incremental steps. To manage commercial risk and regulatory uncertainty, they may prefer to postpone investment decisions until risk can be replaced by information.⁸⁷ Moreover, the preferential treatment of RES-E has had a very large impact on investment.

One can distinguish between pure electricity producers and so-called integrated firms. A pure electricity producer—for instance, a merchant power plant (Sect. 8.​2.​3)—sells its power in the wholesale market. An integrated firm is an electricity producer that supplies electricity to end consumers.

Firms become integrated firms because of commercial benefits. They could include, for instance, (a) reductions in transaction costs,⁸⁸ wholesale market volatility, operating costs, and counterparty risk,⁸⁹ and (b) increased business opportunities. However, it is important for many electricity producers to integrate into electricity supply to end consumers to (c) secure off-take (customers and consumption). An electricity producer may need to secure its market. Electricity producers used to compete on price since there was hardly any room for product differentiation before the boom in “green” electricity. Electricity resellers and large end consumers are very price-sensitive. Smaller consumers are less price-sensitive and less likely to change their supplier when prices change. Vertical integration can reduce risk and make it easier for the electricity producer to invest in generation installations.

Electricity firms can choose even other integration models. One can distinguish between vertical integration, horizontal integration, and integration across value chains.

Electricity producers integrate vertically in two directions and not just downstream. An electricity producer can integrate into power plant fuel supply. (a) Integrating a fuel supply and electricity generation business may provide a hedge against volatile fuel prices. To illustrate, a UK company with its own supply of gas can choose to sell the gas directly, export the gas to continental Europe, or use it to generate electricity, depending on what will offer the highest profits. Integration into coal supply is less attractive for electricity generators because of the lack of alternative markets for coal other than electricity generation.⁹⁰ (b) Fuel suppliers can integrate vertically and enter the generation market to ensure a market for their product and to obtain a better price. Industrial firms may enter into electricity generation to ensure security of supply and to reduce costs. They can sell surplus power or purchase additional power.⁹¹

Electricity producers can also choose horizontal integration. To illustrate, an electricity producer can offer new products to its customers by supplying complementary services.

The provision of distribution or transmission services is an example of integration across value chains. In complete vertical integration, there is one firm for the production of electricity and the operation of the transmission and the distribution system.

Electricity producers are electricity suppliers as well. Electricity suppliers are electricity wholesalers or electricity retailers. (a) A wholesaler either generates or buys electricity to supply it to other electricity firms⁹² or large end consumers. Electricity producers have an incentive to sell electricity to large industrial customers with stable loads. (b) A retailer that does not generate electricity must buy electricity on the wholesale market and resell it downstream to retail customers.⁹³ This enables it to earn a profit from the difference between wholesale and retail prices (buy low, sell high).

Both electricity producers and electricity suppliers need to trade in the wholesale market. (a) A pure electricity producer sells its generation in the wholesale market. (b) An integrated firm needs to trade when it is long or short. Where an integrated firm is long in generation (meaning that its generation output is greater than its own supply requirement), it needs to sell this surplus output. Where an integrated firm is short in generation, it needs to buy to fill the gap. (c) An integrated firm would often trade even where its total generation matched its supply requirements. The reasons can be summed up as:

Large electricity producers that are integrated firms can choose the level of integration for their generation and supply activities. In other words, they can organise their business in different ways. Their choices are applications of the “make-or-buy” decision.⁹⁶ Vertical integration tends to reduce trading on the market.⁹⁷

Generally, one can distinguish between three integration strategies or models: fusion; fission; and semi-integration.⁹⁸ The electricity producer can thus coordinate generation and supply activities in two main ways. It can: (a) coordinate them internally (the fusion model); or (b) let the generation unit and the supply unit trade on the market (the fission model).

The fusion model (internal coordination, “make”) means that the firm’s generation and supply units maximise internal transactions and minimise external trade. Contracts in external markets are only resorted to when there is excess capacity or demand. This can also mean the centralisation of trading competencies. Trading competencies can be accumulated in a single unit that serves the whole company and balances its portfolio on behalf of both the supply and the generation side.⁹⁹

This can be illustrated with the business of fully integrated utilities according to DG Competition: “Typically, within fully integrated utilities, specialised affiliates are dedicated to the different activities, such as generation, trading, supply and network operations. Usually, the entire output of the generation affiliate is sold under intra-firm arrangements to the affiliated trading entity which in turn manages the undertaking’s overall portfolio i.e. sells electricity to the supply affiliate(s) and sells it to or buys it from third parties through bespoke bilateral contracts or traded wholesale markets. Integrated companies can produce more or less electricity than is required for their own customer portfolio. The larger integrated companies often generate more electricity than they need for their final customers”.¹⁰⁰

The fission model (market-based transactions, “buy”) means that the firm’s generation and supply units are allowed to trade freely in the open market, without any preference for internal trade. In this case, trading competencies are decentralised. Since the generation and supply units are not coordinated internally, the work of central management is more focused on financial matters.¹⁰¹

The semi-integrated model means that the firm has organised an internal market for preferential internal trading.¹⁰²

Electricity producers and suppliers can also co-operate with similar firms to reduce costs and increase economies of scale. To illustrate, suppliers can form joint-purchasing organisations or co-operate in the supply of electricity to end consumers.¹⁰³ An electricity producer can also increase co-operation with a downstream electricity supplier. Rather than selling electricity to a downstream electricity supplier for resale to end consumers, the electricity producer could pay the downstream supplier a commission.¹⁰⁴

An electricity producer can choose between scale (mergers in the same field of activity, vertical integration) or scope (integration across value chains). (a) Since product differentiation is difficult because of the physical characteristics of electricity and since there is transmission congestion on interconnectors, the introduction of liberalised and competitive markets could increase cross-border mergers that increase economies of scale and enable electricity producers to sell locally-generated electricity in more and more countries.¹⁰⁵ (b) The alternative is integration across value chains. To illustrate, an integrated electricity firm can take over a gas firm and invest in the production of heat as well. In this way, it can become an integrated energy and heat distribution company.¹⁰⁶ An integrated electricity firm can also prefer to take over a distribution system.

The business models of electricity producers or integrated firms are important from a policy perspective. If these business models are made attractive, security of supply can be increased and retail prices reduced.

This is because of the nature of electricity producers’ business. Electricity producers cannot make a profit unless their production costs are lower than the market price.¹⁰⁷ To increase their profits, electricity producers must produce larger volumes of electricity at a low cost. For this reason, they have incentives to invest in new generation installations and to reduce production costs in competitive markets.

From a policy perspective, there is a fundamental difference between electricity producers and energy merchants. Energy merchants try to be price neutral and make a profit regardless of whether electricity prices are high or low. Electricity producers need to invest in better generation installations. Lower market prices are more likely to be the result of long-term investments made by electricity producers than attributable to the trading and risk management activities of energy merchants.

As will be discussed in this book, the regulation of electricity markets has other goals than supporting the business models of electricity producers or integrated firms. (a) The preferential treatment of RES-E means that markets are not competitive and that investments are not allocated between different technologies based on the cost of production. As a result, electricity prices are higher than they could be. (b) Moreover, the regulation of electricity markets is not designed with the perspective of electricity producers in mind. It focuses more on end consumers, suppliers, transmission, financial markets, or the environment.

One can see traces of the convergence of business models.

If electricity markets were fully liberalised in the EU, electricity producers would have incentives to adopt the business model of an energy merchant.¹⁰⁸ This is because generation installations are large long-term investments and it is important for electricity producers to manage their exposure to risk.

On the other hand, there are factors that provide incentives to move towards the business model of energy merchants even in the absence of fully liberalised and competitive markets in the EU. Such factors include: increased customer churn¹⁰⁹; the fact that investments in generation are to a large extent driven by regulation; the preferential treatment of RES-E; and the high exposure to political and legal risk. The preferential treatment of RES-E fosters investment in RES-E, but laws may change. At the same time, the preferential treatment of RES-E hampers investment in other forms of generation. In other words, electricity producers have further incentives to look for business models that help them reduce the risk exposure of the firm.

The convergence of business models is not one-way traffic. There are incentives for energy merchants to move towards the business model of electricity producers in the EU. The unbundling regime means that electricity merchants cannot control both generation and transmission assets (as Enron did in the US gas markets). The preferential treatment of RES-E can mean that it is easier for many electricity producers to sell their production and to sell it at premium prices. Moreover, the business model of energy merchants is constrained by the regulation of capital markets. In particular, the MiFID regime with its authorisation and regulatory capital requirements for investment firms (Sect. 4.​8) as well as increased requirements as to clearing and collateral (EMIR). As a result, the business of energy merchants has become more regulated and capital intensive. Part of the business model is constrained by the market abuse regime (REMIT) that limits the use of information for the purposes of arbitrage.

Both may need to move towards the generation of RES-E, vertical integration, distribution, and the provision of a broad range of complementary services.

In any case, electricity producers can use the same portfolio approach, the same structured contracts, and the same derivatives as energy merchants.

The evolution of business models in the European electricity industry has been discussed in Midttun A (2001).¹¹⁰ Recent business model trends can be illustrated with the cases of Vattenfall and DONG Energy, the effects of the preferential treatment of RES-E, and the case of E.ON. We can nevertheless start with the US case of Enron, the archetype of an energy merchant.

The origins of Enron lie in the US natural gas industry. The well-known Enron case generally shows how the choice of different business models and contract types can be influenced by market changes. Similar mechanisms are relevant for electricity producers.

Vattenfall is an example of the move from complete vertical integration to unbundled markets and electricity generation from renewable sources combined with coal-powered generation. The Vattenfall case shows that the business models of electricity producers are heavily influenced by regulatory choices and the structure of the market. Vattenfall’s evolution can be summarised as follows:

The case of DONG Energy is an example of a move from the business model of a diversified energy merchant to a less diversified and more generation-focused business model.

The preferential treatment of RES-E has increased the supply of zero-marginal cost electricity in the EU. On one hand, this can reduce average wholesale electricity prices and demand for conventional generation. On the other, conventional generation can provide reserve capacity if it can operate flexibly. It will need to start and stop more frequently and be used at different capacity levels.¹²⁷

The preferential treatment of RES-E has also increased competition and the scope of services provided by market participants. To illustrate, one can identify four types of corporate wind power ownership: large utility companies and developers with a portfolio of generating capacity; independent wind farm developers; wind turbine manufacturers and companies involved in the supply of component parts; and companies providing specialist services.¹²⁸

Moreover, the preferential treatment of RES-E has increased levels of microgeneration and self-generation by end consumers.

Electricity producers need to adapt their business model to market changes caused by the preferential treatment of RES-E.

First, depending on the market, electricity producers may try to choose between being remunerated for energy and ancillary services or compensated for their installed or available capacity.¹²⁹

Second, electricity producers may need to invest in RES-E themselves or find themselves reduced to the role of providers of a residual service (that supply energy when other sources are not available) and suppliers of balance energy (that provide ancillary services to the system operator). Their incentives and the choice of generation technology depend on the RES-E support mechanism in each Member State.¹³⁰

Third, electricity producers may also choose to provide services to microgenerators and self-generators.¹³¹ Electricity firms can facilitate microgeneration and end consumers’ own generation by means of virtual power plants (Sect. 8.​2.​3) or other structured contracts (Sect. 8.​2.​4) and by providing other services.

There will be stronger incentives for end consumers to invest in their own generation capacity, because: the high costs of the preferential treatment of RES-E are allocated to end consumers; own generation can reduce these costs¹³²; own generation can enable consumers to sell surplus generation and benefit from the preferential treatment of RES-E; and the increased share of RES-E generation makes it necessary for large consumers to manage risk and increase security of supply.¹³³

Fourth, electricity producers may need to increase vertical integration, do more business outside the EU, or diversify to other business areas.

Fifth, electricity producers may need to decide what to do with their traditional other activities.

The case of E.ON shows how a traditional integrated firm may need to take bold action to adapt to market changes caused by the preferential treatment of RES-E. In 2014, E.ON went further than Vattenfall and DONG Energy.

In the physical sense, electricity must always be supplied to the grid at a certain grid and voltage level at a certain point. The voltage and current at any point are determined by the behaviour of the system as a whole (that is, impedance) rather than by the actions of any two individual parties to a supply contract.¹⁵⁰ The same applies when electricity is extracted from the grid.

Even in the legal sense, physical settlement requires a place for the performance of the obligation to supply electricity. Electricity is “delivered” at a certain grid and voltage level at a certain delivery point and in accordance with the standards of the system operator.¹⁵¹

“Delivery” is a term customarily used in sale of goods. However, it could be slightly misleading to use it in the context of electricity supply contracts. There are two main differences between sale of goods and electricity trading in this respect. The first relates to place and the second to its legal relevance.

In sale of goods, the buyer is expected to receive exactly the same goods supplied by the seller. The goods cannot simultaneously be in more than one place, and there cannot be more than one place for the physical handling of the goods at a certain point in time. It is possible and meaningful to agree that the goods must possess the required characteristics in a certain place, or attach the passing of risk to that place. This place is customarily called the place of delivery.¹⁵²

In electricity markets, however, it is not possible to identify such a place for technical reasons. (a) It would be impossible to identify the location of goods that do not exist in the first place. In electricity markets, the main rule is that a particular electricity consumer does not really receive any physical “goods” supplied by any particular electricity producer. Electric charge spreads itself over a conducting surface and electrical energy transmitted in the grid is homogeneous in the physical sense. (b) Moreover, the place where electricity is supplied to the grid is not the place where electricity is extracted from the grid. There are entry points for electricity flows into the grid and exit points for electricity flows from the grid. There is a boundary point at which a plant or appliance is connected to the grid. Generators and end consumers do not share the same grid connection. Moreover, a central counterparty—the contract party in a very large number of trades—would not have a grid connection at all. It would not be meaningful to choose the point of the central counterparty’s grid connection as the place of delivery in transactions with a central counterparty.

In practice, it is sufficient to identify the grid and the grid level, or—where buy and sell orders are matched on an exchange—the “bidding area”. Matching bids must necessarily relate to electricity flows in the same grid and at the same grid level. Since grids traditionally have been regional or national, the points of entry and exit customarily are in the same country in electricity spot markets and the bidding area is located inside the borders of one country or a smaller region.¹⁵³ Market coupling makes it possible to choose entry and exit point in different zones.

The second difference between sale of goods and electricity supply contracts relates to the legal relevance of the place of delivery. In sale of goods, the place of delivery is the place where: goods are handed over to the buyer or a carrier¹⁵⁴; goods must comply with the agreed or implied specifications¹⁵⁵; and risk passes to the buyer.¹⁵⁶ In electricity trading, however, the place of delivery does not have to be connected with such issues. Electricity cannot be “handed over” to the buyer, because electricity can neither be stored nor transferred without wires (or other conducting material). Moreover, a consumer that extracts electricity from the grid does not really consume electricity supplied to the grid by a certain electricity producer, because electric charge is spread evenly and electricity is supplied to the grid and extracted from the grid at different points.

There are nevertheless actions or functions that can be connected to a place of delivery. First, electricity should be supplied to the grid. The place of delivery can be used as the point where the supplier supplies the agreed volumes to the grid for the purpose of matching the extraction of electricity by its contract party—a downstream distributor or end consumer, or the transmission or distribution system operator—somewhere else in the grid. Second, the place of delivery can be used to allocate responsibility for the availability of transmission capacity. Electricity cannot be transferred without grid connection and transmission capacity. Third, the place of delivery can be used to allocate the responsibility for costs and risks.

A delivery point is used in the EFET General Agreement: “In accordance with each Individual Contract, the Seller shall Schedule, sell and deliver, or cause to be delivered, and the Buyer shall Schedule, purchase and accept, or cause to be accepted, the Contract Quantity at the Delivery Point; and the Buyer shall pay to the Seller the relevant Contract Price”.¹⁵⁷ The delivery point is used for risk allocation: “Seller shall bear all risks associated with, and shall be responsible for any costs or charges imposed on or associated with Scheduling, transmission and delivery of the Contract Quantity up to the Delivery Point. Buyer shall bear all risks associated with, and shall be responsible for any costs or charges imposed on or associated with acceptance and transmission of, the Contract Quantity at and from the Delivery Point”.¹⁵⁸

The function of the place of delivery can depend on the competition model (Sect. 2.6). In the vertically integrated market model with one electricity company responsible for the generation and distribution of electricity, the point of delivery can be used roughly in the same way as in sale of goods as the consumer has just one contract party.¹⁵⁹ In the liberalised (unbundled) market model, however, the electricity producer customarily does not control electricity flows in the grid.

The following term of the EFET General Agreement reflects the vertically integrated market model rather than the liberalised market model: “Delivery shall be effected by making available the Contract Quantity at the Contract Capacity at the Delivery Point. Delivery and receipt of the Contract Quantity … shall take place at the Delivery Point”.¹⁶⁰

The place of delivery can further influence the scope and application of other rules applicable to electricity markets. To illustrate, the prohibition of market abuse under REMIT (Sect. 4.​7) does not apply unless there are “wholesale energy products” that fall within its scope, and the physical supply contracts that fall within its scope include: “contracts for the supply of electricity or natural gas where delivery is in the Union”.¹⁶¹ In this case, “delivery” can be given an autonomous interpretation in the light of the purpose of REMIT.

Electricity flows are constrained by the available system capacity. When demand for transmission or distribution capacity exceeds the available capacity, there is congestion. Congestion can be caused by technical constraints or economic restrictions (such as priority feed-in rules or contract enforcement limits). An efficient system is sometimes congested, because the costs for building new system capacity can exceed the costs of congestion at the times of peak flows.¹⁶⁵

When managing transmission and distribution capacity and congestion, system operators must take into account loop flows. Loop flows make it more difficult to determine actual flow-based paths (parallel flows) when multiple users compete on the same transmission system.

Regulators and TSOs must choose a model for capacity allocation and pricing. There is a long list of models to choose from (Chap. 5).

In normal market conditions, the chosen model should preferably give such locational and temporal signals for electricity supply (feed-in) and extraction (load) that reflect the costs caused by grid users. The absence of such signals implies that costs are socialised and leads to an inefficient infrastructure use. The existence of proper signals contributes to a more efficient use of transmission infrastructure—in particular where the transmission system is well interconnected and has several alternative sources of supply.

Regardless of the model for capacity allocation, somebody should be responsible for ensuring that the necessary transmission/distribution capacity is available. (a) The allocation of responsibility is clear in vertically integrated markets. In this case, one electricity firm controls both the supply of electricity and the grid. (b) In the liberalised and unbundled electricity markets of the EU, the parties must buy transmission/distribution capacity from a transmission/distribution system operator.

In principle, parties to a bilateral supply contract can freely allocate the responsibility for the availability of transmission/distribution capacity and its costs.¹⁶⁶

In the EFET General Agreement, the Delivery Point is used to allocate the responsibility for the availability of transmission/distribution capacity between the parties.¹⁶⁷ The main rule is that the responsibility for the availability of transmission/distribution capacity changes at the Delivery Point.¹⁶⁸

Parties to an electricity supply contract can allocate quantity risks (volumetric risks) in many ways.

The agreed volumes can be fixed or variable. (a) When the quantities are fixed, security of off-take/consumption is increased for the supplier. For the consumer, security of supply is limited to the agreed minimum quantities. (b) When the volumes are variable, security of supply and security of consumption can depend on the level of discretion and its allocation between the parties. If the quantities extracted by the end consumer are left to its own discretion, security of supply is increased for the consumer. The volumetric risk is then transferred to the supplier.¹⁷¹ It would be less common to leave the quantities to the discretion of the generator. There can be exceptions such as the right to sell RES-E to the DSO/TSO in Germany.

In unbundled electricity markets, even electricity wholesalers and retailers must manage quantity risks, because the quantities extracted by end consumers and the quantities fed into the grid by electricity producers vary. Both can nevertheless be estimated in advance to some extent. It is, therefore, possible for electricity retailers to match the estimated downstream load profile with a mix of upstream contracts that share the same profile.

To illustrate, where a retailer expects that its customers will consume 100 MWh during a certain hour of operation, it can purchase two contracts of 30 MWh and 70 MWh, respectively, before the hour of operation.

Where it can estimate its customers’ consumption for several consecutive hours, it can make a block-order for a block of consecutive hours (for block-orders, see Sect. 4.​5.​4).¹⁷²

There must a party responsible for the operation and management of the transmission or distribution system as well as for balance management. In unbundled electricity markets, the system operator—customarily the TSO—is responsible for balancing the transmission system.¹⁷³

System operators must balance power generation to load at any time during real-time operations. For this reason, they can also be made responsible for dispatching power plants and for the use of interconnectors.

The Third Electricity Directive provides that the TSO must use published criteria for this purpose. The criteria must be objective, applied in a non-discriminatory manner, and ensure the proper functioning of the internal market in electricity. The criteria must also be approved by the regulatory authority.¹⁷⁴

To be able to balance the system, the system operator must: meter the quantities produced and consumed by each party; compare these with the quantities covered by bilateral contracts; ensure that there is balancing energy (physical settlement); and provide financial settlement for the differences and balancing energy.

This can be illustrated with the following example. A retailer expects its customers to consume 100 MWh during a certain hour of operation. It purchases 100 MWh before the hour of operation and pays its suppliers for 100 MWh. However, it turns out that the retailer’s customers have only used 85 MWh during this hour of operation. There must be a trade that creates a balance between the retailer’s total trading and its customers’ consumption. There must be a balancing trade even where the retailer’s customers use 110 MWh or 10 MWh more than the retailer bought before the hour of operation.

System operators and market participants use a balancing energy or real-time market after the closure of the spot market. While individual trades may be voluntary on this market, participation may be mandatory for some market participants. A party may not get access to the transmission grid or a spot exchange without a contract on balancing arrangements (see Sects. 4.4.4 and 4.4.5 on clearing and settlement and Sect. 9.​2 on balance responsibility).

In the EU, this requirement is also based on the Third Electricity Directive. A TSO must adopt rules for balancing the electricity system¹⁷⁵ and even a DSO may have to adopt such rules.¹⁷⁶ A supplier must follow the applicable trading and balancing rules.¹⁷⁷ The provision of balancing services is controlled by the regulatory authority that also approves their terms.¹⁷⁸

The requirement on balancing arrangements can also be illustrated with the regulatory practices in the Nordic spot market (Nord Pool Spot), the continental European spot market (EPEX Spot) and the market for England and Wales. (a) Nord Pool Spot. Each Participant and Client must in its own name or through another company have entered into an agreement on balance responsibility with the relevant balance responsible party or TSO.¹⁷⁹ (b) EPEX Spot. An Exchange Member can be a party that has entered into a Balance Responsible Agreement with a Balance Responsible,¹⁸⁰ or the Balance Responsible that has concluded an agreement with a TSO on balance responsibility.¹⁸¹ (c) BSC. In England, the National Grid Company (NGC) must apply the Balancing and Settlement Code (BSC) according to the terms of its own licence. The BSC provides for a balancing mechanism that enables the NGC as the system operator to buy or sell additional energy and to deal with operational constraints of the transmission system. Neither electricity producers not suppliers will be granted a Generation and Supply Licence unless they sign the BSC Framework Agreement (which gives contractual force to the BSC).¹⁸²

Both the TSO and market participants may need to pay for balancing energy. The TSO pays for balancing energy both (a) when it needs up-regulating energy and (b) when it needs down-regulating energy. Competitive market mechanisms are increasingly sought for market participants’ balancing services (also known as the ancillary services of market participants).¹⁸³

After the closure of the spot market, participants can submit bids in the balancing energy market. The bids specify, for a specific volume and for immediate performance, the prices market participants require or offer to (a) increase their generation or decrease their consumption (up-regulating energy), or (b) decrease their generation or increase their consumption (down-regulating energy). The up-regulating price is customarily higher than the day-ahead exchange price for the particular hour (the market price), and the down-regulating price is customarily lower than the market price.

The TSO sells balancing energy to traders whose purchases and sales are imbalanced. A trader must ensure that it is buying and selling the same amount of energy during each hour. If there is an imbalance, the trader must settle balancing energy with the TSO.

The TSO also sells balancing energy to market participants whose customers consume more than planned and to market participants that produce less electricity than planned. (a) Where the customers of a retailer have used more energy than the quantities that the retailer bought before the hour of operation, the retailer has to buy additional quantities from the TSO and the TSO will invoice the retailer for the additional quantities. (b) A supplier may also need to buy balancing energy when it does not have the electricity it has sold because of a technical failure or otherwise. Where the supplier is an electricity producer whose plant breaks down just before the hour of operation starts, it cannot buy electricity from another supplier. As its customers extract electricity from the grid anyway, the supplier must buy balancing energy from the TSO. The supplier’s customers must pay the supplier. The supplier must pay the TSO for balancing energy.

While the balancing energy market is partly based on voluntary transactions, curtailment is not. An electricity producer connected to the grid may be curtailed by the system operator during emergency situations to ensure system reliability and operational security (Sects. 5.​5 and 10.​7.​3).¹⁸⁴

Parties to a supply contract will therefore have to regulate the effect that curtailment or the system operator’s other actions will have on their mutual obligations. For instance, curtailment could be defined as a force majeure event in the contract.

The EFET General Agreement makes the actions of a network operator a force majeure event.¹⁸⁵ As a result, a party is relieved from liability under the EFET General Agreement even in situations in which a party would not be relieved from liability under the CISG in sale of goods law.¹⁸⁶

In the US, curtailment is defined as a force majeure event in the Pro Forma Open Access Transmission Tariff.¹⁸⁷

Curtailment is not mentioned as a force majeure event in ACER’s CACM Framework Guidelines and the CACM Regulation.¹⁸⁸ On the contrary, there is a distinction between force majeure and curtailment, because the force majeure provisions have been drafted with the TSO’s obligations in mind.¹⁸⁹ One may ask whether curtailment can be regarded as an “unforeseeable” event for others (see Sects. 10.​7.​2 and 10.​7.​3).

Because of the balance requirement, the performance of physical delivery or off-take obligations may not be a feasible remedy in the event of their breach. While payment delays or delays in the furnishing of collateral do not change these obligations as such,¹⁹⁰ delays in the performance of obligations relations to physical electricity flows may change the obligations.