1. The Nordic Electricity Sector

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"A Powerful Competition Policy"

1. The Nordic Electricity Sector [2]

1.1 The Reform of the Nordic Electricity Sector

In 1989-90 England and Wales were the first in Europe to liberalise their electricity markets. Since then, all the Nordic countries apart from Iceland have introduced market-based power trading.

The development of a common Nordic power market started out with the Norwegian 1990 Energy Act. The Act, which entered into force on 1 January 1991, reformed the electricity sector of Norway dramatically by moving from heavy regulation to liberalisation.

The objectives of the regulatory reform were, among others, to

• smooth out artificial price differences between different areas and different consumers,
• improve consumers utilisation of electric power,
• increase efficiency in both production and distribution of electric power,
• secure efficient building of new production capacity, in the right scale and order.

Prior to the reform there were substantial differences between the power prices in different regions. In 1989 the highest price was two and a half times as high as the lowest at the same time. Such differences could lead to undesirable decisions concerning investments in new production capacity. In high-price areas expensive projects could be effectuated while cheaper projects were rejected in low-price areas.

It was generally held that both the total volume of investments in production capacity and the ranking of the various projects were not efficient. There was a built-in tendency in the system to focus on the need to secure supply of electricity regionally, by means of investing in production facilities located near by. Alternatively, regional supply could have been secured by purchasing electricity on a national market, and thereby inducing perhaps more cost efficient investments in projects located elsewhere.

Basic elements of the reform were

• abrogation of the local monopolies of supply, consumers were free to buy electricity from a wide range of suppliers in all parts of Norway,
• establishment of common carriage principle,
• regulation of transmission tariffs,
• obligations for vertically integrated companies to split trade/production and transmission into separate divisions and have separate budgets and accounts
• divestment of Statnett SF (the Norwegian Power Grid Company) from Statkraft, which was thus transformed into a pure generating company,
• establishment of organised spot, future and regulation markets.

1 January 1996 the Swedish electricity market was reformed. New rules introduced competition on trade and production of electricity. The network remained a regulated monopoly. The objective of the reforms was, among other things, to increase the opportunities to choose and to lay the foundations for increased competition in power supply. From 1 November 1999 electricity prices were fully liberalised.

The Finnish Electricity Market Act came into force in 1995, and the electricity market was opened to all Finnish electricity users in November 1998, when standardised settlement was introduced for electricity consumers whose consumption was low. One of the main objectives of the reform was to use economic regulatory instruments and market economy mechanisms for creating the conditions for secure energy supply and competitive prices.

The electricity market in Denmark has been gradually liberalised since 1999, when it was opened to electricity customers with a consumption that exceeded 100 GWh annually. From 1 January 2001, all electricity users with a consumption of in excess of 1 GWh were given freedom of choice of electricity suppliers, and from 1 January 2003 all consumer are allowed to purchase electricity wherever they want.

On 1 March 2002 the last of the inter-Nordic cross-border tariffs were lifted when the Swedish Government decided to abolish the border tariff between Sweden and Denmark.

In 1996 Norway and Sweden set up a common market for electricity in the Nordic region. Statnett Marked AS expanded its area of operations and was renamed Nord Pool ASA – the Nordic Power Exchange. Nord Pool was the first multinational power exchange in the world. Statnett and Svenska Kraftnät each owns 50 percent of the Nordic power exchange.

Finland joined Nord Pool in 1997, Denmark West (Jutland) in 1999 and Denmark East (Zealand) in 2000. On 2 January 2002 Nord Pool split off the physical spot operation into a separate company, Nord Pool Spot AS, which from 1 July 2002 is owned by Nord Pool ASA (20%), Statnett SF (20%), Svenska Kraftnät (20%), Fingrid (20%), Eltra amba (10%) and Elkraft system (10%).

Norway, Sweden, Finland and Denmark now have access to a common Nordic wholesale power market.

In continental Europe, work is in progress in the EU to create an internal energy market. The Electricity Market Directive was adopted in December 1996. The aim of the Directive is to create common rules for the generation, transmission and distribution of electricity. According to the Directive, the market for electricity will gradually be opened to competition.

1.2 The Nordic Electricity Sector

1.2.1 Transmission

Electricity is transmitted from power stations to consumers by a network of power lines. The network is normally classified into three levels: national grid, regional networks and local networks. The consumption and generation of electricity must be in balance at every instant, which is achieved by balance control. Every country has a system operator who is entrusted with the task of maintaining this balance and being responsible for the national grid.

An objective for the Nordic national grid companies is that the market conditions for the infeed of electricity on the Nordic national grids should be harmonised, so that competitively neutral rules can be safeguarded for the players.

The possibilities for trade within the Nordic region and between the Nordic region and neighbouring regions depend on the capacity of the transmission lines. The transmission capacity between countries in northern Europe is listed in the table below.

Transmission capacities between countries in northern Europe

Source: Elkonkurrensutredningen (2002)

The listed capacities are maximum technical capacities. Often capacities available to the market are smaller due to internal bottlenecks in the Nordic system. This is often the case for "Øresundsforbindelsen", which connect DK2 and Sweden. Because of internal bottlenecks in Sweden (Snitt 4) the Swedish TSO, Svenska Kraftnät, at times reduces import capacity into Eastern Denmark from 1.700 MW to 1.300 MW. Furthermore, the capacity reduction is announced in time for the generator in DK2 to act on the smaller import possibilities.

The capacity between Germany and DK1 is permanently lower than the maximum technical capacity listed in the table. Due to internal bottlenecks on Jutland and Funen the local TSO reduces import capacity.

Transmission capacity in and out of countries differs because of internal factors related to electricity generation, transmission and consumption in each country.

The flow of electricity may exceed the limits of a grid's capacity. There are two main ways to deal with such "bottlenecks", either by means of "price areas" or by use of "counter-purchase".

Price areas are used to deal with major or long-lasting bottlenecks in the grid (see 1.2.4). Counter-purchases is a system in which the system operator pays producers to increase or reduce production to create balance in the market.

In Norway, price areas are the main tools for dealing with bottlenecks within the borders and with bottlenecks across the borders to Sweden, Denmark West (Jutland) and Finland. Counter-purchase is used when smaller adjustments are needed. Sweden and Finland use price areas to deal with external bottlenecks and counter-purchases to deal with internal bottlenecks. Denmark is divided into two price areas but these areas are not interconnected.

The national transmission system operators (TSOs) of Sweden (Svenska Kraftnät), Norway (Statnett SF), Denmark West (Eltra), Denmark East (Elkraft) and Finland (Fingrid) are responsible for maintaining the balance between production and consumption. The continuous balance is handled through national regulating markets organised by the TSO's.

Nordel is a co-operation organisation between the Nordic TSOs.

1.2.2 Consumption and Production

Since 1990 the total consumption of electricity in the Nordic countries has increased by an average of 1.4% per year, confer the table below:

Source: The Electricity Market 2002, The Swedish Energy Agency

Electricity consumption in the four countries totalled 394 TWh in 2001. The highest increase has occurred in Finland with an annual average rate of 2.6 % since 1990.

In Norway and Finland the industry sector accounts for a large part of the consumption.

Viewed in an international perspective, all Nordic countries, with the exception of Denmark, have a relatively high average per capita electricity consumption per year: Denmark (6600 KWh), Finland (15700 KWh), Norway (26700 KWh), Sweden (16700 KWh). Important reasons for the high per capita consumption are the high proportion of electricity-intensive industry and the cold climate.

Generation of electricity in the Nordic countries is based on hydropower, nuclear power and conventional thermal power. There are also a few oil-fired condensing power stations, gas turbines and wind turbines. The following table shows production of electricity in the Nordic countries based on different types of production technologies:

Source: The Electricity Market 2002, The Swedish Energy Agency

In 2001, electricity generation in the Nordic countries totalled about 390 TWh. Since 1990, electricity generation in these countries has risen by 44 TWh, or about 14 per cent. Norway and Sweden are the largest power producers of the Nordic countries.

In 2001 generation of hydropower totalled 213 TWh, which accounted for 55% of total production of electricity. There are very large variations in precipitation from year to year.

Generation is very dependent on variations in water inflow. Water inflow is the volume of water flowing from the entire catchment area of a river system into reservoirs. In the wettest years, precipitation is more than twice as high as in the driest years. The total normal year generation of hydropower in the Nordic countries is between 180 and 190 TWh. 1996 was a very dry year with a total electricity production of 167 TWh, while 2000 was a very wet year with production of 234 TWh. Average production in Norway is 119 TWh. The difference between the two years was thus 67 TWh. The year 2000 was a wet year in Norway and a new production record of 143 TWh was set. Average production in Sweden is 64.2 TWh. 2000 and 2001 were wet years in Sweden.

The electricity generated by nuclear power totalled 91TWh equalling 24% of total generation in the Nordic countries. Production is determined by the availability of the plant and by its maximum output. Availability is determined by the scheduled and unscheduled outages and by the annual overhaul shutdowns during summers. The maximum electrical output is restricted by the thermal loading and by the capacity of the generators.

Nuclear power production in Sweden was particularly low in 2000 equalling 55 TWh as compared to 69 TWh in 2001. According to the Swedish Energy Agency's report "The Electricity Market 2001" this can be partly explained by the large inflow of water, but also that producers, according to the report, lowered nuclear production in order to uphold electricity prices. Closure of the first reactor in Barsebäck also contributed to the reduction of nuclear production.

Production in conventional thermal power plants was 79 TWh - 20% of total production in 2001. These plants generate electricity by burning various fuels. The fuels used in the Nordic countries are coal, oil, natural gas, peat and bio fuels. Power is generated in combined heat and power stations, condensing power stations, and gas turbine power stations.

Wind power totalled 5 TWh equalling1% of total production.

The following figures describe the relative use of different sources of energy in the production of electricity in the Nordic countries in 2001.

In Norway production of electricity is almost totally based on hydropower (99%), in Denmark on conventional thermal power (88%). Hydropower accounts for half of the Swedish production and conventional thermal power for half of the Finnish production.

The table below shows installed net power capacity in the Nordic countries at the end of 2001.

Source: Nordel Annual Report 2001

Hydropower accounts for more than 55% of the total installed capacity the Nordic market. Just below 60% of the installed power is in Norway and 35% in Sweden.

Nuclear power accounts for 14% of total installed capacity. 78% of the capacity is in Sweden.

Conventional thermal power accounts for 30% of total installed capacity. Finland and Denmark have 78% of the capacity.

1.2.3 The Electricity Market

Power trade between countries is determined by production and consumption patterns in each country, in addition to the capacity of the transmission network linking countries and the conditions for its use. One basis for power trade is the opportunity for mutual benefits deriving from differences in the production systems of different countries.

Power exchange between the Nordic countries makes use of the advantages to be gained from interconnecting hydropower and thermal power systems. In countries with thermal power-based systems, the capacity of the power plants determines how much electricity can be generated. In hydropower-based systems, the limiting factor is the quantity of energy available. The pattern of demand for electricity, and thus the amount that must be generated, is generally the reverse of the fluctuations in inflow. When inflow is high, production is often low, and vice versa. The energy sources on which electricity generation in thermal power countries is based (oil, coal, natural gas and uranium), can generally be acquired in whatever quantities are needed, and do not limit power production.

In countries with thermal power-based systems, it is expensive to build thermal power plants to meet short-term peaks in demand, and it is both time-consuming and costly to adjust production up and down in existing thermal power plants. But thermal power plants can deliver relatively inexpensive electricity outside peak consumption periods, i.e. at nights and at weekends. Electricity generation by hydropower plants can be adjusted up and down rapidly and at low cost to meet short-term fluctuations in consumption or unexpected changes in power supplies. Trade reduces the need for costly adjustment of thermal plants, because excess supply of electricity can be exported and in case of a shortage of supply electricity can be imported. Trade also reduces the need to build new power plants and multi-annual water reservoirs.

The creation of an integrated Nordic market is also advantageous to competition. One of the reasons is that the largest national producers have most of their production capacities located in their home country. In such a situation an enlargement of the market means an increase in the number of producers and reduced market concentration. See also chapter 3.

Electricity prices are determined by supply and demand in the Nordic market. Production costs are lowest for hydropower. When price increases other technologies will be used in increasing "marginal cost order" (the industry supply curve): nuclear power, combined heat and power generation, condensing power stations (coal, oil), natural gas turbines. The marginal technology determines the price. In a year when hydropower production is close to the average level, electricity prices will largely be determined by the costs of producing electricity from coal. In periods when the consumption load is higher, power plants with higher production costs, such as oil condensate plants or gas turbine plants, will determine the prices. These are peak-load power plants, and are only used to produce electricity for short periods at a time.

Although hydropower has low operation costs, it still plays an important indirect role in the price determination. The reason is that it is possible to shift production between time periods by means of water reservoirs. One unit of water produced today means one less unit of water available for production tomorrow. The value of that unit lost tomorrow is called the water value. If the price today is above the water value production will increase and more water will be used. If the price today is below the water value production will decrease and water will be stored.

The ability to store water means that variations in consumption and water inflow will cause variations in hydropower production. This will shift the industry supply curve inwards or outwards, causing changes in the market price of electricity. This is illustrated in the figure below. Increased hydropower production causes the industry supply curve to shift outwards and thus the price to fall, even if hydropower is not the marginal technology.

This ability to shift the industry supply curve is not confined to hydropower plants. For instance, reduced production by a nuclear power plant will shift the curve inwards. The main difference between hydropower and nuclear power is the degree of flexibility. Nuclear power is inflexible, while hydropower is very flexible also in the short term. We will return to this subject in chapter 4.

1.2.4 Nord Pool

In the wholesale electricity market, grid companies, large industrial enterprises and other large actors buy and sell electricity. Electricity is either traded bilaterally between market actors or on Nord Pool. A number of electricity transactions are standard bilateral contracts, which is still the main instrument for selling and buying electricity. But a growing proportion of contracts are traded in the Nord Pool's physical and financial derivatives markets.

Nord Pool operates the following marketplaces and market services:

• A spot market for physical contracts, Elspot
• A financial derivatives market – futures and option contracts
• Clearing services for contracts traded in OTC and bilateral markets.

Development of Nord Pool's markets

* Introduced 1997
Source: Nord Pool Annual Report 2002.

In 2002 physical electric power trading at Nord Pool amounted to 124 TWh, which is 32 per cent of total consumption in the common Nordic market.

About 280 participants from Norway, Sweden, Finland and Denmark, as well as some other European countries and the USA, trade through Nord Pool. Participants are power producers, retailers, grid owners, brokers, market makers, traders and industrial companies.

Physical trade between the Nordic countries is based on Nord Pool's Elspot market, which is a market for physical delivery the next day. Hence, the market is referred to as a day-ahead market. Prices for sales and purchases are determined hourly throughout the day. Each participant bids a price-quantity curve for each individual hour of the day. The price-quantity curve provides information on how much the participant wants to produce or consume at given price levels. These bids are not observable for any player except the Exchange.

After the noon deadline for participants to submit bids, the Nordic Power Exchange's spot market gathers all buy and sell orders into two curves for each power delivery hour: one aggregate demand curve and one aggregate supply curve. The spot price for each hour is determined by the intersection of the aggregate supply and demand curves. The equilibrium price is also known as the system price. This is the spot price for physical delivery of electricity, equal in Norway, Sweden, Finland and Denmark. The system price is also used as a reference price for trade in the electricity derivatives market.

The system price is determined by supply and demand in the Nordic region, without regard for physical capacity limits in the transmission grid. However, the Nordic transmission grid has capacity limits, and trade on Elspot will in certain periods generate congestions in the transmission grid, so-called bottlenecks. Nord Pool handles bottlenecks by separating the market into different Elspot price areas. The permanent price areas in the Nordic region are Sweden, Finland, Denmark West (DK1) and Denmark East (DK2), South Norway (NO1) and Middle/North Norway (NO2). Last winter Norway was divided further into four price areas.

The System Price is the reference price for handling potential grid congestions. Within Elspot price areas the system operators handle congestions by means of "counter-trade", based on bids from producers.

In Sweden and Finland, Elbas, is used as a short term market operating after closing of the spot market. Due to the lengthy time span of up to 36 hours between the Elspot price fixing and delivery, participants need market access in the intervening hours to improve their balance of physical contracts.

Variations in precipitation and temperature can result in large variations in the spot price. This means that the economic risk associated with electricity trading is high. To reduce the risk, producers, consumers and other actors in the market can enter into long-term physical and financial contracts.

Nord Pool's financial derivatives market covers the market for futures, forward and option contracts. Futures and forward markets are financial markets for price hedging and risk management. The system price in the spot market is the reference price for future and forward contracts traded on the Nordic power exchange. Power derivatives enable market participants to hedge purchases and sales of power with a time horizon of several years. Such products can be traded on the Nordic power exchange, but there are also other markets that organize trade with these products. Through power derivatives trade actors can hedge purchases and sales of power with a time horizon of up to four years.

Financial electricity market contracts traded at the Nordic Power Exchange are standardised products that are financially settled; there is no physical delivery of electric power. Settlement is conducted between Nord Pool's clearing service and individual market participants.

In addition there are bilateral contracts, both long-term and forward contracts. The market players are free to agree on standardised or non-standardised, long-term or forward contracts, either on a bilateral level or through the commodity exchange, Nord Pool.

1.3 The Danish Electricity Sector

The Danish generation and wholesale market has been gradually liberalised and from 1 January 2003 the end-user market has also been opened.

Geographically the Danish market is placed between bigger power markets to the south (Germany) and to the north (Norway and Sweden). The Danish thermal production is primarily based on coal and gas.

There is an excess of generation capacity in Denmark and a lack of production capacity in the

countries to the north. Denmark is therefore expected to strengthen its position as a power exporter in the future.

1.3.1 Network Operation

The structure of ownership in the Danish electricity sector is very fragmented. About 100 grid companies (owned by the consumers directly or by municipalities) each have a small share in one of the two transmission companies in east and west Denmark. No company has a majority influence in any transmission system operator (TSO).

Generation has to be legally separated from transmission, and each activity has to be carried out in separate companies. Furthermore, the management of the two kinds of companies has to be done by different people, and the same people are not allowed to be board members in the two types of companies. Generation companies are not allowed to own a significant share of transmission companies. But the grid companies own the transmission system, the trans.mission system operators as well as the two large generation companies. Thus, ownership integrates the industry vertically.

The Danish electricity market consists of two separate geographic markets: Denmark West (DK1) and Denmark East (DK2). The two markets are not interconnected but are part of the joint Nordic power market. Interconnectors between DK1 and Norway and Sweden connect DK1 with the Nordic market. An interconnector joins DK2 with Sweden. Both DK1 and DK2 are connected to the German power market. Correlation analysis shows that the two Danish price areas are not integrated with the Nordic market in hours where interconnectors are congested by imports, and that Denmark is never integrated with the German power market.

Total import capacity into both Denmark West and East is approximately 2000 MW. In 2001 the maximum consumption was 3 700 MWh/h in Denmark West and 2 700 MWh/h in Denmark East (2001).

Under normal conditions 90-95 percent of the time the Danish power market is part of the much larger Nordic market. Bottlenecks occur more frequently in some years than in others depending mainly on fluctuations in regional supply. In wet years – where the supply of hydro-produced electricity is large – the imports from especially Norway into western Denmark congest the interconnector relatively often. In 2001 the interconnectors from Norway and Sweden into western Denmark were simultaneously congested in 7 percent of the time. The interconnector between eastern Denmark and Sweden were blocked simultaneously in 5 percent of the time.

The transmission capacities between the two Danish submarkets and the Nordic area plus Germany indicates that the Danish electricity market is a relatively open market.

The interconnectors from Denmark West to Norway in the north and partly to Germany in the south were until 1 January 2001 occupied by long-term contracts between generators in the three countries. This disturbed trading across the borders. With the intervention of the European Commission the agreements were abandoned. Still a part of the interconnector between Denmark East and Germany is occupied by long-term contracts between generators in Sweden, Denmark and Germany. This reduces the capacity that is available for competitors in the market and seems to be an obstacle for integration between Germany and Denmark.

Denmark has two transmission system operators, namely Eltra, which is responsible for the national grid in Jutland and Funen, and Elkraft, which is the national grid company in Zealand. Just like other national grid companies, Eltra and Elkraft own the 400 kV grids and the links with Sweden and Germany. The transmission line systems of Eltra and Elkraft are not currently interconnected with one another.

The tariffs of the transmission system operator is regulated by an ex ante approval procedure. The grid companies' tariffs are determined by income caps set up by the regulator. The tariffs are separated into an entry charge (generation) and an exit charge (consumption). The main part of the charge is put on the exit charge. Tariffs vary across the day but not by location. All charges are put on flow (contrary to fixed tariffs or capacity). It is the general view that the tariff systems by the TSOs are transparent and facilitates an easy access to the network.

1.3.2 Production

Denmark's power generation is primarily based on coal-fired and natural gas-fired combined heat and power (CHP) stations and condensing power stations. A minor proportion of power generation is based on bio fuels. Among the Nordic countries, Denmark has the highest proportion of electricity generated by wind power.

Environmental problems have played an important role in the energy policy in Denmark. This has resulted in high subsidies to renewable power production – wind and small scale CHP. Analysis has shown that the large subsidies given to the production of renewable power have been an expensive and rather ineffective way to obtain a reduction in CO²-emissions. The bill is being paid by the end-users through an obligation to buy renewable power.

Currently, 40 percent of the consumption of electricity is allocated outside the market. This in addition to the high Danish energy taxation means that the functioning of the power market does not have a crucial influence on the price of power at the household level.

Two generators dominate the Danish market: Elsam A/S in DK1 and Energi E2 A/S in DK2. The two companies are the result of politically driven mergers between a number of companies before the introduction of merger control in the Danish Competition Act 1 October 2000. Ten companies have become only three. The total installed capacity of Elsam and Energi E2 is 7 000 MW and 5 500 MW (including windmills) in DK1 and DK2 respectively. Of the total installed capacity in DK1, Elsam owns approximately 50 percent. In DK2 Energi E2 A/S owns approximately 80 percent. However, for competition policy considerations the relevant market shares of the two generators are closer to 100 percent of DK1 and DK2. If the interconnectors are blocked by imports the two companies hold a dominant position in the two markets. This happens most frequently in peak load hours with low non-commercial generation (windmills and small scale CHP).

Production of electricity takes place on (1) large production units mostly in combination with heat (2) windmills and (3) smaller CHP-units. Production from windmills and CHP-units is bought on non-market terms by the TSOs. The price, of this non-market electricity is, however, to some extent reflecting consumption patterns.

The Danish government has announced that all power consumption will be allocated through the market in the future. This will make the legal obligation to buy the renewable power production obsolete. When the prioritised production system is changed and all the production is sold on the market, there will be more generators competing. The two generators, Energi E2 and Elsam, will, however, continue to hold a dominant position in the Danish market in the foreseeable future.

1.3.3 New Capacity

It is the business of the TSO's to examine and plan the need for expansions of the transmission system. The TSOs (in co-operation with the transmission companies who also work under authorisation) have to apply for projects according to the plan. The TSOs (with the government authorities) have a crucial influence when deciding expansions of the transmission system.

Expansion of generation capacity has to be approved by the regulating authority. In reality the incentive to enter into generation is limited due to the existing excess thermal capacity in both Denmark West and Denmark East.

Except for the construction of subsidised renewable power production no plans for the construction of new generation has come up in Denmark in recent years. The main reason is the present low price of electricity compared to long run costs (reflecting a situation with excess capacity). A new large plant – decided 8-10 years ago – started production in 2002. The plant is located at the coast near Copenhagen. The reasons for this location are easy access to fuel/water and the demand for the production of heat (CHP-production) in the well-organised district heating system.

A key issue in setting up new generation capacity in Denmark will definitely be location considering the present lack of sites – especially because of local resistance due to environmental problems. In this way, location can become a barrier to entry in the market. At the moment, it is not a requirement for the incumbent generators to offer sites to competitors when plants are shut down.

1.4 The Swedish Electricity Sector

The per capita electricity consumption in Sweden is relatively high compared to other countries. In 1999, Sweden was in the fourth place in the world, after Norway, Iceland and Canada. A common feature of countries that have high per capita electricity consumption is that they have access to inexpensive hydropower and have a high demand for heating by being in a relatively cold climatic zone.

In 2001 hydropower accounted for half of the Swedish electricity production, nuclear power for 44% and fossil-fired and bio fuel fired production for just over 6%.

1.4.1 Network Operation

The Swedish national grid is still a regulated monopoly. It is the responsibility of the Swedish Energy Agency to ensure that the grid is operated efficiently, that the grid tariffs to customers are reasonable and the grid companies do not act in such a way as to stifle competition in the sale of electricity.

The largest electricity producers, a couple of municipalities and industrial companies, own the regional grids. Local grids are owned by approximately 200 network companies, which are either part of power producing combines, municipalities or economic associations.

The dominating flow of power in the national grid is from the north to the south, where electricity consumption is high. Svenska Kraftnät (SvK) applies a spot tariff on the national grid. This means that a customer who is connected to the grid has access to the entire electricity market and can do business with any other player for the same network charge.

SvK has the responsibility for the central transmission network, which is owned by the state. SvK is also the transmission system operator and responsible for maintaining the balance between production and consumption in all parts of the country.

The Swedish tariffs have been adjusted to the conditions in most European countries, where the infeed from electricity generators account for a smaller proportion of the national grid tariff.

SvK co-operates with approximately 40 operators, which all have balance responsibility. This means that these balance provider companies accept economic responsibility for the Swedish electrical system being supplied during every hour.

The connections from north to the south have certain bottlenecks. The most important ones are between northern and central Sweden and between central and southern Sweden. Bottlenecks in Sweden are solved by counter-purchases. If the transmission capacity of the national grid is insufficient for transmitting the electrical energy to meet the actual demand, SvK uses counter-purchase as a method to reduce the physical energy flow on the grid, without the trade of customers being affected.

Individual ownership or control of the transmission links to Poland and Germany may create opportunities for exerting market power.

1.4.2 Production

The Swedish electricity market is characterised by few firms with large market shares. In the year 2001 six companies accounted for nearly 93 percent of the national production of electricity. The six companies concerned were Vattenfall, Sydkraft, Birka Energi, Fortum Kraft (previously Stora Enso), Skellefteå Kraft and Graninge. These six companies have now been reduced to five since Fortum bought the remaining part of Birka Energi. Birka Energi was created as a result of the merger between Stockholm Energi and Gullspång Kraft in 1998. Today the name of the company is Fortum.

The number of major companies has thus been reduced but their share of the production has basically not changed in the years between 1996 and 2000. However the ownership of these companies has changed and become more international. Swedish companies have also been expanding internationally.

The Swedish nuclear plants are all jointly owned by the larger power companies, confer the table below.

The nuclear power companies are Forsmarks Kraftgrupp AB, the Ringhals group (Barsebäck Kraft AB and Ringhals AB) and OKG AB. Fortum owns Skandinaviska Energiverk, which owns 78.1% of Mellansvensk Kraftgrupp. In addition Fortum owns 8.9% of Mellansvensk Kraftgrupp, meaning that Fortum owns a total share of 22.2% of Forsmark Kraftgrupp AB. Sydkraft owns 5.3% of Mellansvensk Kraftgrupp as well as 8.5% of Forsmarks Kraftgrupp AB, which gives Sydkraft a total ownership interest in Forsmark of 9.9%. Skellefteå Kraft owns 7.7% of Mellansvensk Kraftgrupp, which gives Skellefteå a total ownership interest in Forsmark of 1.9%.

Source: The Swedish Energy Agency: The Electricity Market 2002
SOU 2002:7 Elkonkurrensutredningen

Each owner reports its production requests for the next year (the planning period) to the operator of the nuclear company. Vattenfall is the operator (O) of the Forsmark, Ringhals and Barsebäck nuclear plants. Sydkraft is the operator of OKG. The requests take place within the restrictions that determine possible production volumes, such as planned revisions and technical restrictions. During the operating period (one year) the owners may present requests for changes of production. The nuclear company co-ordinates the owners' requests and orders changes of production.

The river regulating companies is also under joint ownership. The organisation Vattenreguleringsföretagen consists of the companies responsible for about half of Sweden's hydropower reservoirs. One of its tasks is to coordinate and maintain the use of the rivers. The hydropower plants along the river jointly own each river regulating companies. The major companies own plants in several rivers, which creates an opportunity to gain insights into certain business related information e.g. concerning cost structure.

The deregulation of the electricity market has led to various attempts at repositioning by the power companies so as to better meet the new challenges. Against this backdrop there has been a noticeable restructuring of the market. During the past years there has been a number of mergers in the Swedish electricity market. Most of these mergers have concerned larger companies buying smaller companies with limited market shares. The individual mergers have thus only meant small increases in market concentration.

1.4.3 New Capacity

In the past few years, the earlier surplus generation capacity in Sweden has been reduced. The oil-fired condensing power stations that were previously used as reserve capacity have been decommissioned, and the first nuclear reactor in Barsebäck has been shut down. The second Barsebäck reactor will not be shut down before the end of 2003 since the conditions for shutting it down before the end of 2003 have not yet been met. The conditions include that the loss of generation capacity can be compensated by reduced electricity consumption and new generation capacity.

Peak consumption has increased somewhat, meaning that the margins for achieving balance during peak periods have been lowered.

There are barriers to entry on the Swedish market for the production of electricity. Only limited new hydropower capacity is possible and no new capacity in nuclear power is allowed. A number of environmental concerns will influence the expansion in both hydropower and other technologies. The process of building new capacity is not only time consuming but it is also capital intensive.

1.5 The Norwegian Electricity Sector

Per capita energy use in Norway is somewhat higher than the OECD average. The proportion of energy use accounted for by electricity is considerably higher than in other countries. The main reasons for the high proportion of electricity use are that Norway has had access to rich supplies of relatively cheap hydropower and that the government investment has focused on hydropower development. A large energy intensive industrial sector has developed as a result and electricity is widely used to heat buildings and water.

1.5.1 Network Operation

There are several grid companies in Norway. A grid company may own a local, regional or central grid. In all, 178 companies are engaged in grid management and operations on one or more levels. Of these, 42 are solely grid operators, whereas the remaining companies are also engaged in electricity generation and/or trading. 136 companies are vertically integrated in the sense that they are engaged both in operations that are exposed to competition (production and/or trading) and in grid management.

The state, through Statnett SF, owns about 87 per cent of the central transmission grid. Private companies, counties and municipalities own the remainder. Statnett is the operator of the entire central grid. Municipalities and counties own most of the regional and distribution grids.

The authority to make decisions pursuant to the Energy Act has largely been delegated to the Norwegian Water Resources and Energy Directorate (NVE), which is subordinate to the Ministry of Petroleum and Energy. Because the grid is a natural monopoly consumers are obliged to buy grid services from the owner of the local grid. The NVE is responsible for monitoring and regulating grid management and operations. Firstly, the NVE determines an income cap for each grid owner. Secondly, it determines how the point tariff structure must be developed.

Point tariffs means that a grid customer pays the same transmission charge regardless of whom electricity is bought from or sold to. An individual customer only pays a transmission tariff to the local grid company. Consumers pay one tariff to tap electricity from the grid (tariff for consumption), and generators pay another tariff to feed electricity into the grid (input tariff). Point tariffs provide easy market access for customers and thus promote the establishment of a nationwide power market.

Statnett is the Norwegian transmission system operator (TSO), and is therefore responsible for short and long term system co-ordination. This means that the enterprise co-ordinates the operation of the entire Norwegian power supply system. This includes ensuring that the amount of electricity generated is at all times exactly equal to the amount consumed.

The balancing market is a market organised by Statnett to maintain a stable frequency and a continuous balance between production and consumption. The balancing market opens after prices and quantities have been determined in the Elspot market. Statnett receives quotes from major producers or consumers that are willing to alter their power generation and/or consumption plans at short notice. This ensures that it is possible to adjust the amount of power in the grid either up or down right up to the hour of delivery.

In western and southern Norway and in Nordland county, electricity production exceeds consumption in the region. In Eastern Norway, on the other hand, electricity consumption is much higher than the amount generated in the region. This means that electric power must be transported from western and northern regions to the south and east of the country.

The currently available transmission capacity from Norway to its neighbours is about 4000 MW.

1.5.2 Production

Norwegian power generation is based mainly on hydropower. Norway is the sixth largest hydropower producer in the world and the largest in Europe.

A total of 156 companies are engaged in Norwegian electricity generation. Norway has a total installed capacity of 27596 MW at 740 hydropower plants larger than 1 MW. An additional capacity of 271 MW is provided by thermal power plants. The installed capacity of wind power plants is 13 MW. The mean annual production capability of hydropower plants is calculated on the basis of installed capacity and the expected annual inflow in a year when precipitation is normal. The estimate of hydropower production in a normal year is about 119 TWh, based on the period 1970 – 1999.

The state-owned Statkraft is the largest producer in Norway. Based on NVE's database Statkraft has an annual average production capacity of 34.7 TWh and an installed capacity of 8356 MW. If we include Statkraft's direct ownership shares in other producers of electricity it will have an annual average production capacity of 49 TWh and an installed capacity of 11900, which gives the company market shares exceeding 40%. Thus, Statkraft is a dominant producer in Norway. There are widespread cross-ownership in the Norwegian power industry, which increases market concentration even further, confer the calculations in chapter 3.

Recently, the Norwegian Competition Authority prohibited Statkraft's acquisition of Agder Energi and Trondheim Energiverk. However, the Ministry of Labour and Government Administration accepted the acquisition of Agder Energi on condition that Statkraft divest its interests in E-CO and Hedmark Energi. The Ministry upheld the prohibition of the acquisition of Trondheim Energiverk.

In addition to the fact that power companies have substantial ownership shares in each other, the companies also jointly own hydropower production plants. Joint ownership concerns more than 80 plants with a total annual production capacity of 35 TWh and an installed capacity of 9300 MW. This means that approximately 30% of the production capacity in Norway is jointly owned by two or more companies. In most of the cases one of the owners has the operation responsibility.

The 10 largest power plants in Norway account for about one quarter of the country's production capacity. The table below lists the 10 largest power plants in Norway as of 1 January 2002.

The two last columns show that Statkraft holds direct ownership interests in the nine biggest water power plants in Norway. Statkraft's share of the installed capacity amounts to 3614 MW, which is 58% of the combined capacity installed in these ten plants.

Considering that Statkraft has an indirect ownership position in BKK (49.9%), Agder Energi (45.5%), SKK (66.6%) and E-CO Vannkraft (20.0%) its share of the installed capacity is 4207 MW, which is 67% of the combined capacity of the ten plants.

It should also be noted that Statkraft has a majority position in 7 of the 10 plants and, thus, a controlling position. It also has a considerably control over two of the three remaining plants, considering its ownership positions in Agder Energi and SKK. Only in Aurland I another company than Statkraft is the major owner. This is also reflected in the fact that Statkraft is operator (O) of 7 of the 10 plants.

Source: The Energy Sector and Water Resources in Norway 2002, Ministry of Petroleum and Energy.

Vertically integrated companies are engaged in both grid and production and/or trading activities. Like grid companies, they sell electricity to end users in the area where they own the distribution grid, and often compete for customers in the areas served by other grid companies.

In all, 136 companies are engaged both in operations that are exposed to competition (production and/or trading) and in grid management and operations. They are required to keep separate accounts. Such accounts are an important part of the basis of the regulatory system. One aim is to ensure that costs related to production and sales of electricity are not charged to grid management and operations (cross-subsidisation). Bills to customers must include separate prices for transmission services and electricity supplies.

1.5.3 New capacity

The largest hydropower development projects were carried out between 1970 and 1985. There was little increase in production capacity in the 1990s. The increase came from the upgrading and expansion of older power plants, which made better use of the capacity of existing power plants, and from the construction of some new small-scale power plants.

Entry into power production is severely restricted. New generation facilities imply large investments, which require high prices to be profitable. Such investments are strictly regulated through concession laws. The Norwegian hydropower projects that are currently being planned are generally small and some of them disputed. Expansion of existing power plants is more likely, but only already established actors can do this. The incentives for established actors to invest in new production capacity will be reduced if they possess market power.

The current concession law discourages entry into hydro generation through acquisition of existing capacity. The provisions oblige private undertakings to return acquired waterfalls to the State after a period of 60 years. These provisions do not apply to state or municipal companies. Therefore a difference is created between the discounted value of a private company and a state or municipal company. The provisions favour Norwegian state and municipally owned producers over foreign or privately owned producers. Due to complaints to EFTA's Surveillance Authority this rule is up for revision in the Norwegian parliament.

The government has granted concessions for building three natural gas-powered electricity plants in Norway. In 1997, the company Naturkraft AS was granted construction and operating licences for two plants at Kollsnes in Hordaland and Kårstø in Rogaland. According to the plan, each of the two CCGT plants is to have an installed capacity of about 400 MW, corresponding to an annual production of about 3 TWh each. There is, however, reasonable doubt about whether the return on these investments will be positive at the current price level. Whatever the investment outcome will be, the capacity of the proposed natural gas generators will not be significant compared to existing capacity in the market.

Five wind power projects have been licensed by the Norwegian Water Resources and Energy Directorate (NVE), but have not yet been constructed. The NVE has received notifications of further 15 projects with a potential annual production totalling 3.7 TWh.

Currently, three ferro-alloy plants generate electricity totalling about 200 GWh/year from waste heat. It is estimated that a further 1 TWh/year could be generated by means of heat recovery from the ferro-alloy industry.

1.6 The Finnish power market

Power generation in Finland is based on conventional thermal power, nuclear power and hydropower. The fuels mainly used in Finnish thermal power stations are bio fuels, coal, natural gas and peat. A small proportion of the electricity generated is based on fuel oil.

Finland has two nuclear power stations in operation, with a total of four reactors. These power stations account for around 30% of the total electricity production in Finland.

Finland has a high share of imports from its neighbouring countries. In 2001 the net import was approximately 10TWh. There have been some discussions of whether to increase production capacity by increasing nuclear power capacity. Another alternative is to increase natural gas-fired power stations. These two alternatives are mentioned in the Finnish national climate strategy of March 2001 as a means to reduce the use of coal and thereby the emission of CO².

Finland has around 120 companies and 4090 power stations that generate electricity. These companies and power stations are mainly classified into two groups. The two major players of the Finnish electricity generation are Fortum and PVO/TVO, accounting for more than 60% of the market.

Fingrid has the system responsibility and owns the national grid in Finland, and also the links with foreign countries. Fingrid ensures that the electricity system in Finland performs well technically, and that reliability is maintained. All parties on the electricity market is responsible for balance between electricity generation and electricity consumption being maintained at all times. Today, there are more than 30 balance provider companies. After the electricity exchange has closed and up to two hours before the delivery time, there is scope available for trading with balance power on the Elbas market. In the event of unbalance during the operating hour, Fingrid applies balance control.

In January 2002 the Finnish government reached a principal decision to erect a fifth nuclear power reactor. The same year the decision was approved by the Finnish parliament.

Footnotes

[2] This chapter is based on different sources, foremost:

• Nordel Annual Report (2001)
• The Swedish Energy Agency (2002)
• Ministry of Petroleum and Energy (2002)
• SOU 2002:7
• OECD (2002)

Version 1.0 October 2003 • © Danish Competition Authority.
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