3.3 Retail markets

Switching rates

Properly functioning retail electricity markets rely on the awareness of consumers to choose their electricity suppliers. Although all consumers were given the option to switch between power utilities in the EU since 2007, it has been mainly the medium-to-large size industrial consumers that switched suppliers in 2010 in most of the EU Member States. In the case of household consumers, progress was slow in 2009-2010, with fewer than 10% of households switching suppliers in the majority of Member States. As far as industrial consumers are concerned, the issue of cost-effectiveness seems to be more relevant than in the case of households, and the competition between power utilities for industrial consumers is likely to be stronger than for household customers. Furthermore, in many countries a significant percentage of households are not sufficiently informed about switching possibilities, which also leads to lower household switching rates than in the case of industrial consumers.

Table 13. Electricity Switching rates for customer types in 2009 and 2010

Source: CEER Source: CEER database; National Regulators

Retail prices for electricity

Although prices between many European wholesale markets have converged to some extent in the last couple of years, significant differences in the retail prices were still being observed in 2011.

Households across the EU paid 0.18 Euro/kWh on average for electricity in 2011, while industrial consumers paid 0.14 Euro/kWh. In absolute terms, households and industries in Bulgaria and Estonia paid the lowest gas prices, while households and industries in Denmark paid the highest prices [1]. The ratio of the highest to the lowest gross price among the EU Member States was 4.2 in the case of households and 3.1 in the case of industrial users. The range between the highest and lowest household price was 0.09 Euro/kWh in the case of households and 0.06 Euro/kWh in the case of industrial users.

Figure 31: Electricity retail prices paid by households and industrial consumers in 2011 (in EUR/kWh)

Source: Eurostat energy statistics

Note: Range for annual consumption of Household group DC: [2500 kWh-5000kWh]; Industry group IC: [500 MWh – 2000 MWh]

The ratio of highest to lowest household prices remained relatively stable at about 3.5 between 2008 and 2011. During that period, Bulgarian households paid the lowest prices for electricity, while households in Denmark paid the highest prices[2].

The ratio of highest to lowest consumer prices for industry fell from 3.1 in 2008 to 2.7 in 2009 and 2.4 in 2010, rising again to 3.0 in 2011. Over the period 2008-2011, industry in Denmark consistently paid the highest electricity prices. Industry in Estonia (2008 and 2009) and Bulgaria (2010 and 2011) paid the lowest industrial prices [3].

As far as household consumers are concerned, retail electricity prices in those Member States that joined the EU after 2004 were below the EU-27 average in 2011, with the exception of Cyprus. Member States that have been part of the EU for a longer period were mainly to be found at the other end of the price range. Consumer prices were among the highest in Denmark and Germany, where the proportion of tax in the final price was the highest among the 27 Member States. A high proportion of taxes in these two countries was closely related to national energy policies aimed at promoting the use of renewable energy sources. Looking at household customer prices excluding taxes, the three highest prices were in Cyprus, Ireland and Malta. Cyprus and Malta are considered to be energy islands, and their power generation is overwhelmingly based on oil-fired plants, which is one of the most expensive forms of electricity production. The high prices in Ireland are also partly due to the fact that it has only one interconnection.

After correcting the retail prices for purchasing power standard (PPS), the picture is much more balanced, with Hungary and Slovakia being the countries where household consumers paid the highest prices in 2011. Households in France, Greece, Luxembourg and Estonia paid the lowest consumer prices, corrected for PPS.

In the case of industrial customers, taxes other than VAT also contribute to high end-consumer prices in some countries (e.g.Denmark, Italy or Germany). In Cyprus and Malta, the same factors apply for high industrial prices as in the case of household prices (energy islands and high share of oil-fired power generation). However, it is not as easy to distinguish between the two groups of Member States which joined the EU either before or after 2004 in the ranking order of industrial electricity prices, as it is in the case of households, because industrial retail electricity prices in several 'new' Member States were higher than the EU-27 average.

The next map shows the European retail electricity prices paid by households with an annual consumption between 1,000 kWh and 2,500 kWh, which represents less than the national average in most of the EU Member States. The highest prices were paid in those countries where taxes and levies contributed a considerable share of the final consumer price (e.g. Germany, Denmark), or in countries with limited or non-existent interconnections to other countries (Ireland, Cyprus and Malta). In the eastern part of Central Europe, particularly in those countries that joined the EU during the last decade, prices are generally lower than in the western part of the continent. This might be due to the widespread practice of regulated prices and to the incorporation of socio-politically motivated price subsidies in the electricity tariffs.

Further integration of wholesale power markets reduced the price differentials between many EU countries, as can be seen in the case of the Nordic markets and in the Central West European markets. However, significant price differences were observed between the household retail electricity prices of these countries. This can be explained by differences in network costs and taxation, the latter of which falls within the remit of the national legislations in each Member State. Some countries continue the practice of indexing the retail electricity price to fossil fuel prices, which does not allow changes in prices at the wholesale level to be reflected in retail electricity prices.

Industrial users with annual consumption between 20 MWh and 500 MWh paid retail prices above the EU average of 0.154 Euro/kWh in eleven of the Member States. Again, the highest prices were observed in countries where tax accounted for a larger share of the final consumer price (e.g. Germany, Denmark, Italy, the Netherlands), or in countries with limited or non-existent interconnections to other countries (Ireland, Cyprus and Malta). Unlike in the case of household retail prices, some of the Nordic countries (Norway, Finland and Sweden), along with Luxembourg and France, are among those with the lowest retail prices for industrial consumers.

Map 3.1: Electricity prices paid by households, all taxes included, 2nd semester 2011

Map 3.2: Electricity prices paid by Industry, all taxes included, 2nd semester 2011

We turn now to examine the changes in annual average prices between 2010 and 2011. Prices increased for both households and industrial customers in most of the EU Member States, in line with wholesale power prices in the majority of the European electricity markets (See Table 9). In the case of households, however, both prices fell in Luxembourg and Hungary, while decreases in industrial prices were also experienced in Hungary, the Netherlands, Romania, Slovenia, Luxembourg and Poland. In Malta, there was no change in either household or industrial customer prices.

Between 2010 and 2011, retail household electricity prices in the EU rose by an average of 6.7% i.e. slightly higher than the increase in industrial prices (6.1%). Seventeen Member States posted higher increases in household electricity prices than in industrial prices. This difference could be due to the increasing impact of levies and value-added type taxes (and/or decreasing price subsidies) in household prices, while industrial customers continue to benefit from reimbursement of VAT.

Figure 32: Change in electricity retail prices between 2010 and 2011

Source: Eurostat Energy Statistcs

Note: Range for annual consumption of Household group DC: [2500 kWh-5000kWh]; Industry group IC: [500 MWh – 2000 MWh] .Industrial prices are VAT-excluded. Data for industrial prices in Austria are missing.

Retail electricity price data are available only half-yearly and wholesale price data in the majority of the European power trading platforms date back only a couple of years. There is therefore insufficient data to carry out a proper correlation analysis in the trend in half-year averages of wholesale and retail power prices. Nevertheless, both household and industrial net retail prices (without taxes) seem to be strongly correlated with wholesale power prices in the Nordic countries. On the other hand, there is less of a correlation apparent in the Central Western Europe region, while the correlation was mostly weaker in other countries of the EU than in these two regions. In many countries there was a time lag of half a year between changes in wholesale and retail prices.[4]

The distribution of cost factors within consumer electricity prices, broken down by energy and supply costs, network costs and taxes and levies, showed considerable variation among the EU Member States, as well as between household and industrial prices. Energy and supply costs, reflecting the costs of power generation, had a stronger impact on the final price paid by industrial customers than in the case of households. As the next chart shows, there were only five Member States in 2011 where the share of energy and supply costs exceeded 50% of retail electricity prices paid by households, while in the case of industrial customers there were only four countries in which the share of energy and supply costs remained below 50%.

Network charges were normally higher for households than for industrial customers, both in absolute amounts and in terms of their relative share in the final price. This is not surprising, given that distribution system operators apply higher charges for households, to reflect higher power transportation costs.

In eight EU Member States, industrial customers were faced with electricity prices where the tax share exceeded 10%. Industrial electricity retail prices in Italy and Germany had a tax component above 25%[5]. High shares of taxes and levies in industrial retail prices often reflect national energy policies that are designed to shift the power generation mixes in the direction of an energy source composition that is more climate-friendly and more sustainable, by promoting an increase in shares of renewable energy use. In the case of household consumers in the large majority of EU Member States, non-recoverable taxes and levies (including VAT) accounted for around 20% or more of consumer prices.

Notes: Prices for households are all taxes included. Prices for industrial consumers are VAT-excluded.. Consumption bands Dc and Ic according to Eurostat classification. Ic denotes an industrial consumer with an annual consumption in a range of 500 MWh - 2000 MWh and Dc denotes a household consumer with an annual consumption of 2.500 KWh - 5.000 KWh. Data for industrial prices in Austria, France and Hungary broken down into cost factors are missing. Data for household prices in Hungary and France broken down into cost factors are missing.

Part III: Country reports

Key Issues ₊ Austria should continue efforts to implement day-ahead implicit flow-based electricity transmission capacity allocation procedures for the CEE region in line with the Joint Declaration by ACER and the region’s National Regulatory Authorities. Given the high utilisation levels at the Czech/Austrian border due mainly to high loop flows, Austria should consider building new electricity interconnectors. ₊ With regard to gas, Austria is highly dependent on imports. Austria should continue efforts to tackle gas network congestion problems. It should also implement reverse-flow arrangements on the HAG pipeline.

Austria

1. General

1.1. Crude oil and petroleum products were the main energy source in the energy mix with around 38 %, while renewables accounted for 26 %. The most important renewables are biomass and waste followed by hydro power. Out of 71 TWh of electricity produced in Austria, 68 % comes from renewables (chart 2 below), mostly hydro power (58 % of total generation). Austria’s indicator for the 2020 renewables target has improved in recent years, from 25.1 % (2006) to 30 % (2010), the aim being 34 % by 2020.[6] The share of cogeneration[7] in the overall electricity production was 15.4% in 2010, which was identical to the share measured in 2005.

Charts 1 and 2 Source: Eurostat

2. Regulatory framework

2.1. General. Following the opening of infringement proceedings in September 2011 for non-transposition, Austria has notified full transposition of the Third Energy Package Directives.

2.2. National Energy Regulator. The Austrian National Regulatory Authority, E-Control, in operation since 2001, employed 109 staff in 2011 with an annual budget of EUR 16.2 million. In 2011, E-Control’s powers were increased to monitor price developments. It also obtained more effective sanction mechanisms and the power to launch sector inquiries and to request specific information from companies, as provided for in the directives. However, following the first case of such a sector inquiry in 2011 (on retail margins in electricity), this power was challenged by all retail companies. A decision by the high courts is still pending.

2.3. Unbundling. Austrian Power Grid AG (APG) is the main Austrian electricity TSO, owning approximately 94 % of the Austrian high-voltage electricity grid (6 454 km) and operating it as well. APG has been certified as an Independent Transmission Operator (ITO). Austria’s gas TSO Gas Connect Austria GmbH has also been certified as an ITO. The certification procedures for Trans Austria Gasleitung GmbH (TAG), Baumgarten Oberkappel Gasleitungsges. m.b.H. (BOG) and Nabucco are still pending. At distribution level in the electricity sector, there are approximately 130 DSOs. Legal ownership unbundling has so far been the preferred unbundling model, leaving DSOs rather limited control over the power grids, which they rent from a vertically integrated producer and/or supplier.

3. Wholesale markets

3.1. Electricity. Austria’s wholesale trading market is joined with Germany and forms a single price zone (both OTC and PX). In this wider market, Austrian traders have a relatively small market share. However, foreign wholesale traders are not very active in Austria, limiting themselves to sales to larger customers consuming between 10-20 GWh. In all, 11 domestic wholesale traders are active in the country. APG is a member of the Central Auction Office (CAO), which brings together the eight TSOs of the Central East European (CEE) region. CAO was established with a view to ensuring coordinated congestion management in the region. It holds daily, monthly and yearly cross-border transmission capacity auctions. APG has agreed intra-day capacity allocation procedures with all its neighbouring TSOs.

Since there are no declared congestions between Austria and Germany, the two countries share a common wholesale electricity market. Through Germany, Austria is partially coupled with the central west European market. On the other hand, it is not yet coupled with its eastern and southern neighbours. In spring 2012, however, ACER and the National Regulatory Authorities in the CEE region (including E-Control) jointly declared their willingness to implement implicit flow-based capacity allocation procedures in the region by the end of 2013.

The average Austrian day-ahead wholesale price on EXAA[8] in 2011 was EUR 51.9/MWh for baseload power (15.6 % higher than in 2010).[9] Relevant factors influencing the wholesale price include the situation in neighbouring countries (notably Germany and the Czech Republic).

3.2. Gas. To satisfy its national gas demand, Austria is highly dependent on imports, its domestic production being limited to 1.7 bcm/y in 2010. In that year, Austria imported 78 % of its national consumption, with 67 % from Russia, 18 % from Germany and the rest from Norway. Both Russia and Norway sell their gas to Austria on the basis of long-term ‘take or pay’ contracts. There is some wholesale trading at the physical trading hub Central European Gas Hub (CEGH) in Baumgarten. Also, Austrian gas traders are active on the NCG and TTF. Furthermore, implementation of the entry-exit access scheme to the gas transmission system, eliminating gas transport along the contractual path and hence the differentiation between gas transit and transmission pipelines, is progressing. Still, the transmission system is highly congested, so access to capacity for new entrants wanting to trade in the Austrian market is limited. In 2009, there was no firm capacity at the Oberkappel and Baumgarten entry points (through West Austria Gasleitung [WAG] or Trans-Austria Gasleitung [TAG]) and no firm capacity was available at Control Area East, despite capacity often being under-utilised. In 2011, spot gas was sold at the CEGH for EUR 23.8/MWh on average (26.6 % higher than in 2010). Despite relative good price alignment with other European hubs, traded volumes were lower compared to other European hubs, with traded day-ahead volumes of 2 TWh, accounting for 7 % of gross inland consumption.[10] The lack of liquidity of the CEGH is largely due to few sellers of significant volumes.

4. Retail markets

4.1. Electricity. In 2010, market concentration at retail level was moderate to high. The market share of the three largest household suppliers was 58 %, with the five largest suppliers having 71 %. Of the roughly 140 retailers, many operate only at local or regional level. The close cooperation between Wien Energie , ENV and BEWAG through Energieallianz had already increased market concentration at the outset of Austria’s market liberalisation. According to E-Control, several suppliers did not pass on a decrease in network tariffs in early 2011, which points to insufficient competition. In 2011, only 1.5 % of household customers switched. Electricity prices are not regulated in Austria, neither for households nor for industrial customers. Since 2008, retail prices have risen gradually in contrast with wholesale market prices. In 2011 the share of network costs in household prices (without taxes) was 44 %, around average for the EU, while energy and supply costs accounted for 56 %.

4.2. Gas. Market concentration at retail level is high. The combined market share of the three largest suppliers was 74 % in 2010, with the largest market share held by Energieallianz (61 %). The twelve gas suppliers in Austria are all majority-owned by regional governments and are partially interlinked. Switching is low, with 1.1 % of all end-customers switching supplier in 2011. Since market opening, only around 6 % of all final customers have changed supplier. Gas prices are not regulated in Austria, neither for households nor for industrial customers. Generally speaking, there is only little correlation between retail and wholesale prices in the Austrian gas market. In particular, decreases in wholesale prices such as during financial crises are passed on only to a limited extent to household consumers. Since 2006, the number of alternative suppliers in the retail market for small commercial and household customers has increased in eastern Austria. Switching rates grew particularly in the last quarter of 2011, triggered by higher potential savings.

Charts 3 and 4

Source: Eurostat

Notes: VAT is refundable for industry. Since 2007, Eurostat has applied a new methodology for the calculation of retail prices. The Eurostat categories are as follows: DC — electricity households (2 500 kWh — 5 000 kWh), ID — electricity industry (2 000 MWh — 20 000 MWh), D2 — gas households (20 GJ — 200 GJ), i4 — gas industry (100 000 GJ — 1 000 000 GJ).

4.3. Consumers. Overall consumer satisfaction with the retail electricity market ranks second highest in the EU. However, consumer satisfaction with the retail gas market is below the EU average.[11] E-Control provides the Tarifkalkulator, a price comparison tool for both electricity and gas. It is responsible for complaint handling and dispute settlement between consumers and service providers, and also for dealing with disputes concerning access to the grid. The regulatory commission at E-Control can issue a binding decision on the legality of any refusal of system/network access. There is as yet no definition of vulnerable customers, but a protection mechanism does exist. In early 2010, E-Control published a cost-benefit analysis for the roll-out of smart meters. A Ministry of Economics decree calling for the roll-out of smart meters for 95 % of all end consumers by 2019 entered into force in April 2012.

5. Infrastructure

5.1. Electricity. The need for more interconnections with Italy, Slovenia and Switzerland is considerable. The current high levels of utilisation at the Czech/Austrian border may be the result of high loop flows, caused by the generation situation in Germany.

The construction of a 12km 132 kV interconnector between Arnoldstein and Tarvisio was a positive development in 2011. This was built as a merchant line and TSOs were not directly involved in it.

5.2. Gas. Austria exports approximately 80 % of the natural gas it physically imports, with most of these exports going to Italy. Other exports go to Germany. Physical reverse-flow capabilities from Germany to Austria have been operational since April 2011 and from Italy to Austria since October 2011. A new interconnection between the Baumgarten hub and the entry point of the Czech gas pipeline system at Lanzhot is being explored. Austria is part of two major pipeline projects in the region: Nabucco and South Stream. It has large storage capacities, both below and above ground, totalling 7.1 bcm. The reverse-flow projects in Baumgarten and Überackern and along the TAG pipeline, which were co-financed by the EEPR programme, were implemented in 2011. Possibilities to reverse flows on the HAG pipeline should also be put in place.

KEY INDICATORS FOR THE ENERGY MARKETS IN AUSTRIA IN 2010

Error! Not a valid link.Sources: Eurostat, CEER, National Regulatory Authority, EC calculations.

NA: not available or not applicable

(1) Companies are considered ‘main’ if they produce at least 5 % of national net electricity generation.

(2) Retailers are considered ‘main’ if they meet at least 5 % of total national electricity consumption.

(3) The HHI (Herfindahl-Hirschman Index) is a commonly accepted measure of market concentration. It is calculated by squaring the market share of each firm competing in the market and then summing the resulting numbers (the higher the index, the more concentrated the market). Moderate concentration: 750–1800; high concentration: 1800–5000; very high concentration: above 5000.

(4) Entities are considered ‘main’ if they handle at least 5 % of natural gas (indigenous production or imported).

(5) Retailers are considered ‘main’ if they sell at least 5 % of the total natural gas consumed by final customers.

Key Issues ₊ With regard to electricity, the high level of concentration at generation and wholesale level still gives rise to concern, as about 70 % of all generation remains in the hands of the incumbent. To provide a stable framework for investment, any remaining uncertainty about the life expectancy of existing nuclear plants should be removed as a matter of urgency. ₊ At retail level in both electricity and gas, competition is still relatively weak, though switching seems to have increased recently and the market share of the incumbent has decreased. Measures strengthening competition in retail markets, as recommended by the Council, are needed to activate consumers and remove obstacles to switching, such as local collective tendering initiatives, have started to stimulate competition to the benefit of consumers. While taking into account universal service obligation and effective protection of vulnerable customers, market measures such as price freezes, which have a negative impact on competition and investment, should be rolled back as soon as possible. ₊ Distribution costs in Belgium account for a large proportion of the domestic and SME consumer bill. Proper regulatory oversight needs to be put in place also at regional level to ensure that all network tariffs reflect efficient costs and are incentive-based. Regulators must be given sufficient resources to do so. ₊ With regard to gas, swift implementation of the new market model introducing a virtual trading point and a genuine entry and exit system will further facilitate wholesale trading and lead to more efficient use of the Belgian transmission system at the heart of the EU.

Belgium

1. General overview

Most of the energy consumed (42%) consists of crude oil and petroleum products. Gas (28 %) and nuclear energy (20 %) are also significant in the energy mix, while solid fuels and renewable energy sources (RES) are less so. Renewable energy accounts for 4.2 % of consumption, about half the EU-27 average. The power generation (95.1 TWh) mix in Belgium is dominated by nuclear generation (50.4 %) and natural gas (34.9 %), while RES and solid fuels accounted for only 8.3 % and 4.4 % respectively. The country’s 2020 RES target indicator for the energy sector (the share of RES in Gross Final Energy Consumption) is 13 %, below the EU-27 average (20 %). Between 2006 and 2010, the share of RES grew slowly, from 2.7 % to 5.2 %. The share of electricity from cogeneration[12] reached 16% in 2010, almost doubling since 2005 (8.5%).

Charts 1 and 2

Source: Eurostat

2. Regulatory framework

2.1. General. Following the opening of infringement proceedings in September 2011 for non-transposition, Belgium has notified full transposition of the Third Package Directives.

2.2. National Energy Regulator. The Belgian National Regulatory Authority, Commission de Régulation de l’Électricité et du Gaz (CREG), in operation since 2000, employed 72 staff in 2011 with an annual budget of about EUR 15 million. CREG has challenged the new Belgian energy law transposing the Third Package Directives at the Belgian Constitutional Court, arguing that it does not grant CREG sufficient powers or autonomy. There are also three regional regulators (VREG for Flanders, CWAPE for the Walloon region and BRUGEL for the Brussels region). Cooperation between the four regulators is essential to ensure there is a consistent, effective regulatory framework across the country. The regional regulators need to be reinforced to exercise proper regulatory oversight over distribution network charges due to the further regionalisation of distribution tariffs competences.

2.3. Unbundling. The Transmission System Operators (TSOs) at federal level are ELIA for electricity and Fluxys for gas. In 2010, Electrabel/GdF/Suez withdrew from ELIA and Fluxys, moving towards ownership unbundling. Both companies are currently being certified.

3. Wholesale markets

3.1. Electricity. The three biggest producers together generated around 95 % of the total power produced. In the case of large-scale customers connected to the federal grid (voltage higher than 70 kV), Electrabel's share was 90.2 % in 2011. At the wholesale trade level, the market share of the three biggest firms (ECS, Electrabel, SPE) was 85.9 % in 2011. At generation and wholesale level, markets are highly concentrated. Integration with neighbouring markets was successfully carried out through the Trilateral Market Coupling, involving Belgium, the Netherlands and France. In 2010, Belgian and French markets (Belpex and EPEX) were coupled 87 % of the time, and Belgian and Dutch markets were coupled 73 % of the time. In November 2010, market coupling was extended to the entire Central West European Area. In 2011, the annual average wholesale day-ahead baseload power price was EUR 49.4 /MWh, slightly higher than the average for 2010 (EUR 46.3 /MWh). The ratio of traded volume of power and gross electricity consumption was 15 % in 2011. The annual traded volume of day-ahead contracts on the Belpex platform was around 10-12 TWh between 2008 and 2011, representing 13.4 % of national electricity consumption in 2010 (14.3 % in 2011), lower than the volumes traded on the APX platform in the Netherlands.

3.2. Gas. Belgium does not produce gas. In 2010, annual gas imports amounted to 20 bcm, with pipeline imports accounting for 16.2 bcm and LNG imports for 3.3 bcm. In 2010, the main suppliers were Norway (37%), the Netherlands (30%) and Qatar (14%). Though gas is imported mainly through long-term contracts, Belgium has a physical wholesale gas trading platform at Zeebrugge. In the past, development of the hub has suffered from the lack of an entry-exit tariff system and from large amounts of transmission capacity being locked in transit contracts. This situation is likely to improve considerably with the introduction of a new market and transmission model on 1 October 2012. This has introduced an entry-exit model and a newly-established virtual trading point, the Zeebrugge Trading Point (ZTP), thus significantly improving trading opportunities for energy companies. Today, however, on a number of interconnection points, contractual congestion (capacity booked, but not used) is still a problem. The gas market in Belgium is characterised by a high degree of concentration. At wholesale level, the three largest suppliers (Distrigaz, ECS, SPE) covered 86 % of the market by available gas.[13] In 2011, the annual average day-ahead gas price at Zeebrugge was EUR 22.5 /MWh, significantly higher than in 2010 (EUR 17.2 /MWh), reflecting an increase in global LNG prices after the Fukushima nuclear accident. Annual traded volume of day-ahead gas contracts in 2009 amounted to 143.4 TWh, reaching 185.5 TWh in 2010, then falling back to EUR 158.4 /MWh in 2011. The average monthly churn rates have fluctuated within a range of 4-6 for most of the last three years. Even though liquidity is increasing, OTC trade accounts for most Zeebrugge transactions.

4. Retail markets

4.1. Electricity. Market concentration was high with a dominant supplier — Electrabel Customers Service (ECS). In 2011, for customers connected to the distribution and local transmission grid, ECS had a market share of 45 % (Electrabel, supplying bigger customers, has a 17 % share of this market). Until 2012, electricity prices had not been regulated for domestic or industrial consumers. However, in March 2012, the Belgian government introduced a temporary freeze of the indexing of the energy components of electricity and gas prices for residential customers and SMEs for nine months, starting in April 2012. The government said the freeze was intended to implement structural measures to stabilise prices and foster competitiveness. However, the measure negatively impacts on the investment climate and disproportionately affects new entrants who are obliged to source large volumes on the wholesale market. It should be ended as soon as possible. In the case of household consumers, in 2011, energy and supply costs accounted for 48% of the net price, with network costs accounting for 52 %. In the case of industrial prices, the ratio was quite different (67 % vs. 33 %). The significant difference between the cost structures of the two customer categories reflects the fact that network costs were almost three times higher for domestic consumers, while energy and supply costs were similar for households and industrial consumers. Regulated distribution charges, which currently include of the costs of public service obligations, should be reviewed so that they reflect costs more accurately, and they should be incentive based. Switching of suppliers is increasing steadily. In Flanders, 6.68 % of customers switched in 2010, rising to 8.16 % in 2011. The number of green contracts has risen notably; in Wallonia and the Brussels region, the switching rate was around 4 %. For gas, the figures are similar. There are indications that switching increased rapidly in the first half of 2012 due to growing consumer awareness.

4.2. Gas. Market concentration remained very high. The dominant supplier is ECS. At federal level, the three biggest gas suppliers on the retail market covered 94 % of consumption. Until 2012, gas prices had not been regulated in Belgium, but the government decision to freeze retail prices as described above also applies to the gas market. Following the price fall in the wholesale market, retail prices decreased in 2009 and started to rise again in 2011 in line with wholesale prices. In the case of industrial prices, a similar trajectory was observed, though the impact of the decrease in wholesale prices in 2009 was stronger on retail prices. Retail prices followed changes in wholesale prices with a time lag of a couple of months. In gas, switching rates are even higher for Flanders: 7.06 % in 2010 and 9.22 % in 2011.

Charts 3 and 4

Source: Eurostat.

Notes: In industry VAT is refundable. Since 2007, Eurostat has applied a new methodology for the calculation of retail prices. The observed Eurostat categories are the following: DC — electricity households (2 500 kWh — 5 000 kWh), ID — electricity industry (2 000 MWh — 20 000 MWh), D2 — gas households (20 GJ — 200 GJ), i4 — gas industry (100 000 GJ — 1 000 000 GJ).

4.3. Consumers. Consumers' assessment of the gas retail market is the lowest in the EU, with particularly low scores on trust in providers (lowest of all countries) and comparability (third lowest). In addition, consumers experience considerably more problems than their counterparts elsewhere in the EU. The electricity retail market is also assessed below the EU average (19th place out of 27).[14] There are 12% more complaints in both electricity and gas markets than in the EU on average. Regulators provide an online price comparability tool for electricity and gas, and this is generally considered as effective. The Flemish regional energy regulator reported that in the first half of 2012, 1.3 million people took the comparability tool test. Since 2010, consumers can seek information and make complaints regarding electricity and gas at a single point of contact, managed by the Federal Mediator and Ombudsman (Service de Médiation Fédéral de l’Energie). Alternative Dispute Resolution (ADR) procedures can be initiated by the Federal Mediator and Ombudsman or by the regional mediator in Wallonia or the ‘chambre des litiges’ in Brussels and Flanders. Vulnerable consumers and low-income consumers can benefit from social tariffs. A cost benefit analysis for the roll-out of smart meters has been conducted. However, there is no legal framework in place to roll these out and all three regions (Wallonia, Flanders and Brussels Region) privilege a coluntary roll out of smart meters rather than a mandatory one.

5. Infrastructure

5.1. Electricity. In terms of investment in generation capacity, a number of expansion and reinforcement projects are ongoing. By 2011, a total of 946 MW were under construction, 3 455 MW were authorised and 2 502 MW were planned. The development of off-shore wind parks requires further grid development. Further efforts are needed to enhance interconnection capacity and to integrate the physical electricity grid with neighbouring markets. However, in the summer of 2012, the testing of the flow-based market coupling mechanism was postponed.

5.2. Gas. The country’s only storage facility, in Loenhout, was expanded in 2010. The increase in entry capacity at the Eynatten and ‘s Gravenvoeren interconnection points helps to alleviate the congestion that has occurred for years at these points. In addition, the east-west axis of the Fluxys network was reinforced and the Zelzate interconnection point at the Dutch border is now bi-directional.

KEY INDICATORS ON THE ENERGY MARKETS IN BELGIUM IN 2010

Sources: Eurostat, CEER, National Regulatory Authority, EU calculations.

(1) Companies are considered as 'main' if they produce at least 5 % of the national net electricity generation.

(2) Retailers are considered as ‘main’ if they meet at least 5 % of the total national electricity consumption.

(3) The HHI (Herfindahl-Hirschman Index) is a commonly accepted measure of market concentration. It is calculated by squaring the market share of each firm competing in the market and then summing the resulting numbers (the higher the index, the more concentrated the market). Moderate concentration: 750–1800, high concentration: 1800–5000; very high concentration: above 5000.

(4) Entities are considered as 'main' if they handle at least 5 % of the natural gas (indigenous production or imported).

(5) Retailers are considered as ‘main’ if they sell at least 5 % of the total natural gas consumed by final customers.

Bulgaria

1. General overview

Solid fuels, with lignite and brown coal making up more than 90 %, represented almost 39 % of gross inland energy consumption, followed by petroleum products (22.6 %). Solid fuels were also dominant in electricity generation, accounting for 48.5 % in Bulgaria’s power mix. Nuclear accounted for 32.7 % of the country’s electricity production of almost 47 TWh in 2010. The third most important power source was renewables (RES), with a share of 13.8 %. Bulgaria’s 2020 RES target is 16 %. From 2006 to 2010, its RES indicator increased from 9.3 % to 13.8 %. The share of cogeneration[15] was 8% in 2010, being slightly higher than in 2005 (6%).

Charts 1 and 2

Source: Eurostat

2. Regulatory framework

2.1. General. Following the opening of infringement proceedings in September 2011 for non- transposition, Bulgaria has notified only partial transposition of the Third Energy Package Directives. Moreover, one other infringement procedure is still open on the Second Energy Package concerning the lack of transparency in conditions for third-party access to natural gas transmission networks and the lack of an adequate system of penalties in the event of breaches of the Gas Regulation.[16]

2.2. National Energy Regulator. The Bulgarian National Regulatory Authority, the State Energy and Water Regulatory Commission (SEWRC), in operation since 1999, employed 128 staff in 2011 with an annual budget of BGN 3.6 million [EUR 1.87 million]. SEWRC has 4 territorial divisions. Its budget is insufficient to cover oversight of all the sectors it is responsible for and there are concerns about the stability of its management. The government has intervened in regulatory and management matters.

2.3. Unbundling. Both TSOs for electricity and gas are legally unbundled. While the electricity TSO, ‘Electricity System Operator EAD’ (ESO), is a subsidiary of the electricity supply incumbent ‘Natsionalna Elektricheska Kompania’ EAD (NEK), the gas TSO, ‘Bulgartransgaz’ EAD, no longer has any direct corporate links with the gas supplier incumbent ‘Bulgargaz’ EAD. All these companies are fully owned subsidiaries of ‘Bulgarian Energy Holding’ EAD, which in turn is fully state-owned. The TSOs have not yet been certified. Bulgaria plans to implement the Independent Transmission System Operator (ITO) model for both TSOs. The electricity distribution network is privatised and owned by CEZ, EVN and Energo Pro. The distribution and supply businesses are legally unbundled. There are 29 gas distribution companies. They are not legally unbundled because they each have fewer than 100 000 customers.

3. Wholesale markets

3.1. Electricity. The most important market player on the Bulgarian electricity market is the state-owned, vertically integrated group, BEH. It owns the Kozloduy nuclear power plant and a major lignite-fired power plant, Maritza East II, along with the main hydro producer and wholesaler NEK. Altogether, the BEH group produces around 60 % of total electricity output in Bulgaria. At production level, besides the BEH group, there are six other producers in Bulgaria, operating medium to large thermal power plants. These producers generate approximately 27.5 % of electricity output (according to the data available for 2011).

3.2. Regulated and free markets coexist at wholesale level, where NEK plays a central role on both. On the regulated market, NEK purchases electricity under quota obligation at regulated prices from independent producers and partly from own generation mix, and sells it at regulated prices to four distributors supplying households and SMEs. NEK also purchases electricity from combined heat and power generators (CHP) and from renewable energy sources (RES) at feed-in tariffs established by SEWRC. Separately, NEK purchases electricity at non-regulated prices on the free wholesale electricity market from thermo power producers under long-term contracts.

3.3. NEK owns the transmission network (high- and medium-level voltage network) and supplies large industrial customers as a supplier of last resort. NEK’s subsidiary ESO operates the network and organises the balancing market, where NEK also plays a key role.

3.4. There is no power exchange and no organised day-ahead market in electricity. Since 2010, rules for trading in electricity (including day-ahead trading) have been tested. Testing was also started in 2012 for launching a power exchange. A quota system paralyses the functioning of the wholesale market, as generators are obliged to sell their output to NEK at regulated prices and cannot freely contract with suppliers. In addition, Bulgaria has a system of transaction-based transmission charges, including a number of network surcharges, which act as a barrier to exports and hinder the free flow of electricity across borders. The level of market integration is low: coordinated bilateral capacity allocations at borders are not offered for all timeframes from Bulgaria to Romania and Greece.

3.5. Gas. Bulgaria is totally dependent on imports from Russia, mostly based on long-term contracts with intermediary companies, to satisfy its domestic gas demand. Gas imports amounted to 2.6 bcm in 2011. There is no functioning wholesale market. Bulgargaz EAD is the only importer, conducting wholesale trade at regulated prices. It had a market share of 84.16 % in 2011; the remaining 15.84 % was from domestic extraction. Melrose Resources Sarl and OGEP AD are the companies engaged in domestic extraction. They also supply gas to final customers.

4. Retail markets

4.1. Electricity. The three biggest utilities controlled 76 % of the market in 2010, resulting in a high market concentration. There has been no switching in past years, with no market opening at end-consumer level. Electricity prices for households and SMEs are still regulated.[17] In 2011 energy and supply costs accounted for 58% of the household electricity prices (without taxes), while the share of network costs was 42%. For industrial consumers, the share of energy and supply costs was one of the highest in the EU (78%), while network costs only accounted for only 22% of the net industrial prices. Network costs were among the lowest in the EU.

4.2. Gas. Bulgargaz is the sole importer and main retail gas supplier on the market for large industrial customers. The three largest suppliers control about 72 % of the country’s retail gas market, resulting in a high concentration. Retail prices (both household and industrial) are still regulated. There is no switching. This is in part because consumers who switch away from their licensed regional supplier have to pay an additional transmission price for each 1000 cubic metre of transmitted gas to the gas distribution company whose territory it crosses. Even though gas retail prices in Bulgaria are amongst the lowest in Europe, they have risen substantially over recent years.

4.3. Consumers. The retail electricity and gas markets are assessed the lowest and second lowest in the EU, respectively. In both markets, the scores for trust and overall satisfaction are within the two lowest ratings in the EU. Bulgaria has the highest number of problems with both gas and electricity — in the latter market, more than twice above the EU average.[18] Although there is no price comparison tool, SEWRC requires suppliers to provide information on prices to consumers. Electricity and gas distribution companies provide consumers with online price calculators. Consumers have to file complaints in two steps: first, a complaint has to be addressed to the energy company, and, then, if the reply is not satisfactory, forwarded to SEWRC. SEWRC contributes to the voluntary settlement of disputes by providing a conciliation commission for the out-of-court settlement of consumer disputes. There is no official plan for the roll-out of smart meters and no official cost-benefit analysis has been submitted to the Commission.

Charts 3 and 4

Source: Eurostat Note: in industry VAT is refundable and therefore not included

5. Infrastructure

5.1. Electricity. At transmission system level, Bulgaria does not face significant congestion. However, some investments are planned to develop RES in certain regions of the country, mainly wind power in north-east Bulgaria and solar power in the south of Bulgaria. Bulgaria will also require more cross-border transmission infrastructure to strengthen the country’s interconnection with central/western Europe and possibly to export RES.

5.2. Gas. All gas imports come from Russia through a single route, the Ukrainian-Western Balkan pipeline. This, in addition to the very limited availability of storage capacity, makes Bulgaria particularly vulnerable from a security of supply standpoint. At the same time, Bulgaria is an important transit country for the supply of Russian gas to the Balkan region, Greece, Turkey and the Former Yugoslav Republic of Macedonia. In an attempt to address its poor security of supply situation and to diversify supply, some investments have been made. A project has been launched for better connecting and expanding the capacity and withdrawal rate of the Chiren gas storage facility and steps have been taken to connect Bulgaria’s gas transmission systems with Romania, Serbia and Greece. However, reverse-flow capacity at the borders with Romania and Greece is still quite limited. Further expansion of underground storage capacity would help to reduce the exposure to external events. Supply disruptions could also be tackled by the use of demand-side measures such as interruptible contracts. For improving and developing gas distribution networks, an amount of BGN 68.808 million (EUR 35.07 million) was invested in 2010. Over 400.000 km of distribution pipelines were constructed.

KEY INDICATORS FOR THE ENERGY MARKETS IN BULGARIA IN 2010

Sources: Eurostat, CEER, National Regulatory Authority, EC calculations.

NA: not available or not applicable

(1) Companies are considered ‘main’ if they produce at least 5 % of national net electricity generation.

(2) Retailers are considered ‘main’ if they meet at least 5 % of total national electricity consumption.

(3) The HHI (Herfindahl-Hirschman Index) is a commonly accepted measure of market concentration. It is calculated by squaring the market share of each firm competing in the market and then summing the resulting numbers (the higher the index, the more concentrated the market). Moderate concentration: 750–1800; high concentration: 1800–5000; very high concentration: above 5000.

(4) Entities are considered ‘main’ if they handle at least 5 % of natural gas (indigenous production or imported).

(5) Retailers are considered ‘main’ if they sell at least 5 % of the total natural gas consumed by final customers.

Cyprus

1. General overview

The energy consumption mix was overwhelmingly dominated by oil and petroleum products (96.3 %), whereas renewable energy sources (RES) provided for only a small portion (3.7 %). Solid fuels and gas have not played a significant role in Cyprus during the last two decades and there is no nuclear power generation. This unusual energy mix is mainly due to Cyprus’s isolation from other energy markets in Europe. The country’s 2020 RES target indicator for the whole energy sector is 13 %. Between 2006 and 2010, the share of RES grew slowly (from 2.5 % to 4.9 %). The share of cogeneration[19] was 1% in 2010, which is a slight increase compared to the 0.3% share in 2005.

Charts 1 and 2

Source: Eurostat

2. Regulatory framework

2.1. General. Cyprus has only partially transposed the Third Energy Package Directives despite the two infringement procedures for non-transposition launched by the Commission in September 2011.

2.2. National Energy Regulator. The Regulatory Authority of Energy of Cyprus, CERA, in operation since 2003, employed 12 staff in 2011, with an annual budget of around EUR 2 Mio.

2.3. Unbundling. The incumbent Electricity Authority of Cyprus (EAC) owns both the transmission and distribution system. The TSO is legally and functionally unbundled from EAC. The obligation of unbundling of the TSO according to one of the unbundling models in the Third energy package does not apply, since Cyprus has obtained a derogation from Article 9 of the Directive. The DSO part of EAC has the same duties and responsibilities as the TSO with regard to safeguarding access to the distribution network and equal treatment of all users. EAC has unbundled the accounts of the DSO.

3. Wholesale markets

3.1. Electricity. There is only one generating company, EAC, which is also the supplier. There is no wholesale market in Cyprus. Cyprus has been granted the status of a ‘small isolated system’ under both the Second and Third Energy Packages. It is not integrated and not interconnected at all with neighbouring systems. As a small isolated system, Cyprus can derogate from the application of several Articles of Directive 72/2009/EC. On July 2011, an explosion at the Vasilikos Power station more than halved electricity production. EAC’s response was fast and effective, reactivating old decommissioned equipment and installing mobile generators. However, generation costs, passed on to consumers, rose to a level that triggered widespread protests. The two small wind parks turned out to be useful and more widely used photovoltaic generation would have reduced discomfort. Five wind parks, with a total capacity of 147MW, are currently in operation.

3.2. Gas. Preparations were underway to import gas to a new LNG facility to be built near the site of the now severely damaged Vasilikos power plant; the plant was scheduled to begin operations in 2014. A national gas company, DEFA, has been set up. DEFA is a state-owned monopolist in the sense that it was supposed to be the only party to contract LNG shipments for the new terminal. In addition, as part of the LNG facility, a gas-storage facility was planned. These plans have become obsolete since the discovery of a significant amount of gas in the Aphrodite gas field, within the Cyprus EEZ, close to the larger Israeli Leviathan field. Cyprus will no longer need to import gas and is planning to build export facilities, although no final decision has yet been taken. A new national hydrocarbon company, focused on export, will be established following a decision by the Council of Ministers. The gas will first be used to fuel the three existing power plants (Moni, Vasilikos and Dhekelia) by means of dedicated pipelines. The future gas networks will later be expanded to supply industries, hotels and households — in that order of priority.

4. Retail markets

4.1. Electricity. EAC is the only supplier of electricity in Cyprus. The consequence of having only one supplier is that customer switching cannot take place. In 2009, electricity prices fell significantly only to surge again since 2010. These price trends mirror those of crude oil and oil products. In 2011, the share of energy and supply costs within net consumer prices was the second-highest in the EU behind Malta (82 % for household consumers and 88 % for industrial consumers). Network costs accounted for 18 % and 12 % of the net household and industrial prices, respectively. The high share of energy and supply costs could be explained by the dominance in the electricity mix of the consumption of imported oil, one of the costliest ways of generating power. CERA is currently in the process of developing an Electricity Roadmap aimed at removing obstacles to the opening of the market and will conduct a study to examine the existing market model.

In 2010, the DSO of Cyprus started a pilot project to install 3 000 smart meters. This project will generate information for the cost-benefit analysis report which is planned for 2012. So far, there is no legal requirement for a mandatory rollout.

Chart 3

Source: Eurostat

Notes: In industry, VAT is refundable. Since 2007, Eurostat has applied a new methodology for the calculation of retail prices. The observed Eurostat categories are the following: DC — electricity households (2 500 kWh — 5 000 kWh), ID — electricity industry (2 000 MWh — 20 000 MWh), D2 — gas households (20 GJ — 200 GJ), i4 — gas industry (100 000 GJ — 1 000 000 GJ).

4.2. Consumers. The retail electricity market is assessed second lowest in the EU. The number of complaints is the highest in the EU; trust in the provider, transparancy of billing, comparability of services, and overall satisfaction are amongst the three lowest ratings in the EU.[20]Customer protection, and in particular protection of those who are living in rural areas, elderly or face difficulties, is entrusted to CERA. Vulnerable consumers are covered through social measures.

5. Infrastructure

As there are no oil and gas pipelines or power lines that link Cyprus to other parts of Europe, the country can be described as an energy island, a situation aggravated so far by an almost 100 % dependence on external primary energy supplies. On the island there are three power plants, all oil-fired. There are over one hundred dams in Cyprus, but none is used for electricity generation or pump storage.

KEY INDICATORS ON THE ENERGY MARKETS IN CYPRUS IN 2010

Sources: Eurostat, CEER, National Regulatory Authority, EC calculations.

NA: not available or not applicable

(1) Companies are considered as ‘main’ if they produce at least 5 % of the national net electricity generation.

(2) Retailers are considered as ‘main’ if they meet at least 5 % of the total national electricity consumption.

(3) The HHI (Herfindahl-Hirschman Index) is a commonly accepted measure of market concentration. It is calculated by squaring the market share of each firm competing in the market and then summing the resulting numbers (the higher the index, the more concentrated the market). Moderate concentration: 750–1800, high concentration: 1800–5000; very high concentration: above 5000.

(4) Entities are considered as ‘main’ if they handle at least 5 % of the natural gas (indigenous production or imported).

(5) Retailers are considered as ‘main’ if they sell at least 5 % of the total natural gas consumed by final customers.

Czech Republic

Key Issues ₊ With regard to electricity, the possibilities of market coupling with more neighbouring states should be further explored. The Czech Republic should increase the capacity at certain local points of its distribution system to balance RES at local level (solar) and put in place regionally coordinated procedures for the calculation and allocation of cross-border capacity in cooperation with other NRAs from the CEE region. The Czech Republic has the highest overall level of interconnection capacity within the CEE region but its transmission capacity is reduced because of loop flows originating mostly from Germany and flowing via Poland to the Czech Republic. Therefore the Czech Republic needs to continue engaging with its neighbours in order to identify appropriate short and long term solutions to this problem. ₊ With regard to gas, the progress made in 2010 and 2011 is noted, inter alia by the introduction of a virtual trading point with a view to improve liquidity and enhance competition on the Czech wholesale market. The Czech Republic should continue diversifying its portfolio of gas sources. Bi-directional reverse-flow capacities were introduced in 2011 on some main pipelines and should also be introduced on other existing and newly planned pipelines. For gas infrastructure, permitting procedures need to be streamlined.

1. General overview

Solid fuels made up most of the energy and electricity mix in 2010. Together with nuclear power plants, they accounted for almost 90 % of gross electricity consumption. Hydro power contributed more than 50 % of renewable electricity, followed by biomass. As far as the 2020 target for RES is concerned, the Czech target is 13 %.[21] This indicator improved from 6.4 % in 2006 to 9.2 % in 2010. The share of cogeneration[22] was 14.2% in 2010, showing a decrease compared to the share in 2005 (16.8%).

Charts 1 and 2

Source: Eurostat

2. Regulatory framework

2.1. General. As the Czech Republic had notified full transposition of the Third Package Directives by the end of September 2011, no infringement proceedings for non-transposition have been opened.

2.2. National Energy Regulator. The Czech National Authority, Energetický regulační úřad (ERO), in operation since 2001, employed 102 staff in 2010 with an annual budget of almost CZK 112 023 million (about EUR 4.43 million). Over the years, the regulator has acquired considerable independence from government and industry and is generally seen as a credible independent actor in the energy market. Its budget is not linked to any ministry and is decided by Parliament.

2.3. Unbundling. CEPS is the country’s electricity transmission operator, majority-owned by the state. The model chosen is ownership unbundling. The NRA notified its draft decision to the Commission in August and the Commission’s issued its opinion in October. With regard to gas, the transmission system operator NET4GAS (formerly RWE Transgas Net) will be operating as an ITO, due to be certified in autumn 2012. As far as distribution is concerned, there are six regional gas distribution companies serving more than 90 000 customers. Four are members of the RWE group and functionally unbundled. There are also 71 ‘local distribution companies’ each serving fewer than 90 000 customers. For electricity, distribution is split between CEZ, E.ON and Prazska energetika, with a further 200-300 small local DSOs. CEZ, E.ON and Prazska energetika are also active in distribution and supply.

3. Wholesale markets

3.1. Electricity. At generation level the market is highly concentrated. The incumbent and state-owned CEZ continues to be the dominant electricity producer, with a market share of 75 % in 2010. No other company had a market share exceeding 5 %. Electricity is traded at Power Exchange Central Europe a.s. (PXE) under bilateral contracts and on spot markets organised by the market operator OTE. Market integration through market coupling with Slovakia started in 2009 and volumes of traded electricity have been increasing. The market coupling of the Czech, Slovak and Hungarian day-ahead markets started on 11 September 2012. There are plans to extend the market coupling project to other CEE countries. Uniform auction rules are in place with the other countries of the CEE region for the allocation of cross-border transmission capacities (coordinated explicit auctions based on the NTC method), while the possibility of introducing flow-based allocation (FBA) in the CEE is being explored along with market coupling. The average Czech day-ahead wholesale price in 2011 was EUR 50.6/MWh for baseload power (an increase of 15.8 % compared to 2010).[23] With regard to liquidity, 8.4 TWh were traded on the spot day-ahead market (13 % of national power consumption).

3.2. Gas. In 2010, the Czech Republic imported 99 % of its domestic consumption. Total imports amounted to 8.5 bcm, with 64.1% from Russia, 23.5% from other EU-countries and 11.4 % from Norway.

RWE Transgas remains the largest player on the wholesale market, as it holds all the large import contracts with Russia and RWE Gas Storage ltd. owns six of the eight gas storage facilities in the Czech Republic. However, new suppliers are gaining access to the market with import contracts from Germany and Norway. There is a Virtual Trade Point as a hub only since 2011, so that no reference wholesale price can be given. The estimates of long-term prices for Russian gas indicate an annual average of EUR 29.3/MWh for 2011 (an increase of 24.3 % compared to 2010).

4. Retail markets

4.1. Electricity. Market concentration is very high, as the market share of the three largest suppliers (CEZ, E.ON and PRE) is 95 %. Supplier switching increased in absolute terms, i.e. almost four times more households switched their supplier in 2010. The switching rate, by number of meter points, was 3.3 %. Power prices for households and industry have been increasing, mainly due to the net energy price. Of the taxes paid, VAT accounts for the largest share. In 2011, the share of network costs accounted for 62% of the electricity price for households (without taxes), while energy and supply costs took up the remaining 38 %. For industrial consumers, the shares were 34 % and 66 %, respectively. End-user prices are not regulated, but the correlation analysis does not show any significant correlation between wholesale and retail prices.

4.2. Gas. Market concentration is high with the two largest companies (RWE and PP) holding a combined market share of almost 62.3 % in 2011. Switching rates were the highest in the EU in 2012, more than quadrupling between 2010 and 2012.[24] The structure and the movement of retail gas prices were quite similar to those of electricity prices. Nevertheless, prices declined for industrial customers in 2009, showing some adaptability of the sector to general market trends. The share of taxes was low, with VAT dominating the tax structure. End-user prices are not regulated.

Charts 3 and 4

Source: Eurostat

Notes: VAT is refundable for industry. Since 2007, Eurostat has applied a new methodology for the calculation of retail prices. The Eurostat categories are as follows: DC — electricity households (2 500 kWh — 5 000 kWh), ID — electricity industry (2 000 MWh — 20 000 MWh), D2 — gas households (20 GJ — 200 GJ), i4 — gas industry (100 000 GJ — 1 000 000 GJ).

4.3. Consumers. Retail gas market is assessed below EU average (17th position out of 23). However, switching rates are the highest in the EU and have more than quadrupled between 2010 and 2012 while the ease of switching receives the fourth highest score in the EU. Consumer assessment of the electricity retail market is slightly below the EU average (15th place out of 27).[25]

ERO provides a price comparison tool for electricity on its website. As far as gas consumers are concerned, a legal definition of ‘vulnerable customers’ is in place since 1 November 2012. Customers can complain to relevant institutions on the basis of the general prohibition of unfair commercial practices. As to the roll-out of smart metering, a cost-benefit analysis in 2012 turned out negative and no legal obligation is in place. However, pilot projects are under way to gather further information for a possible roll-out.

5. Infrastructure

5.1. Electricity. The Czech Republic is a net exporter of electricity. As a result of investment in the development of photovoltaic plants, the total installed capacity of photovoltaic plants has strongly increased. This is the result of a generous feed-in tariff. Installed capacity is able to satisfy peak demand. The Czech Republic has the highest overall level of interconnection capacity within the EEC region. However, transmission capacity is reduced because of loop flows originating mostly from Germany and flowing via Poland to the Czech Republic. The expansion of wind generation in northern Europe will place further constraints on the internal transmission grid.

5.2. Gas. The Czech Republic is an important transit country for Russian gas to Western Europe. Most of this gas enters from Slovakia at the Lanzhot interconnection point and leaves the country on the German border at Waidhaus and Hora Svate Kateriny. The Czech Republic has recently built the first interconnector to Poland with a capacity of 0.5 bcm/year. The new 30 bcm GAZELLE Pipeline will, as of the end of 2012, connect the Czech grid with the new northern route for Russian gas flowing into Europe via Nordstream and OPAL. Other investment projects focus on increasing flexibility, through underground gas storage and reverse flow capabilities. The EEPR programme is co-financing gas storage extension in UGS Tranovice and UGS Tvrdonice. The high number of permits needed for construction is delaying implementation of the project.

KEY INDICATORS FOR THE ENERGY MARKETS IN THE CZECH REPUBLIC IN 2010

Sources: Eurostat, CEER, ERU (Energy Regulatory Office), EC calculations.

(1) Companies are considered ‘main’ if they produce at least 5 % of national net electricity generation.

(2) Retailers are considered ‘main’ if they meet at least 5 % of total national electricity consumption.

(3) The HHI (Herfindahl-Hirschman Index) is a commonly accepted measure of market concentration. It is calculated by squaring the market share of each firm competing in the market and then summing the resulting numbers (the higher the index, the more concentrated the market). Moderate concentration: 750–1800; high concentration: 1800–5000; very high concentration: above 5000.

(4) Entities are considered ‘main’ if they handle at least 5 % of natural gas (indigenous production or imported).

(5) Retailers are considered ‘main’ if they sell at least 5 % of the total natural gas consumed by final customers.

Denmark

1. General overview

Denmark has a high share of crude oil and petroleum products in its energy mix. This can partly be explained by the fact that Denmark is an important oil producer. In 2010, renewables made up the second largest share of its energy mix, with wind energy as the most important source, representing two thirds of all renewable electricity. Denmark’s target for 2020 is 30 % of renewables,[26] which is higher than the EU-27 average (20 %). Between 2006 and 2010 the country’s RES indicator increased from 16.5 % to 22.2 %. The share of cogeneration[27] in electricity production was 49.2% in 2010, being the highest in the EU which reflects Denmark's long-standing commitment to energy efficiency.

Charts 1 and 2

Source: Eurostat

2. Regulatory framework

2.1. General. Following the opening of infringement proceedings in September and November 2011 for non-transposition, Denmark has notified full transposition of the Third Energy Package Directives.

2.2. National Energy Regulator. The Danish regulator is the Danish Energy Regulatory Authority, DERA; it has been operating since 2000, employs some 50 staff and has an annual budget of around EUR 5 million.

2.3. Unbundling. Denmark has a state-owned TSO, Energinet.dk, which owns and operates the transmission networks for both electricity and gas. The model chosen is ownership unbundling and the certification procedure for Energinet.dk has been completed. For electricity, there are another twelve (or 10) regional network operators, which are fully or partly vertically integrated with other companies engaged in competitive activities, such as trading, production and generation. With effect from 1 January 2012, the 10 regional transmission companies were bought by the Danish TSO, Energinet.dk. Hence, complete ownership unbundling of regional transmission companies and DSOs has been achieved.

There are 77 electricity DSOs and three gas DSOs, most of which are fully or partly vertically integrated.

3. Wholesale markets

3.1. Electricity. In 2010, at the generation level, the market was dominated by two big players, Dong Energy and Vattenfall, who together accounted for almost two thirds of the total capacity. The remaining third was provided by a large number of smaller companies, including cooperatives and municipal companies. Market integration with neighbouring markets is adequate. In the Nordic countries, roughly 75 % of energy is traded on the power exchange, Nord Pool Spot (NPS). Volume coupling is used by the EMCC on the borders with Germany. In November 2010 this coupling was extended to the central western Europe region, and about 60 % of Europe’s electricity is connected via this new coupling. Danish electricity is traded on the Nord Pool power exchange. The country is divided into two market areas, east and west. The average wholesale price in 2011 for baseload power was EUR 49.4/MWh for the east (a decrease of 13.5 % compared to 2010) and EUR 48.0/MWh for the west (an increase of 3.3 %).[28] The price is often lower in the west than in the east due to its high level of wind generation with low marginal costs. In terms of liquidity, volumes traded on Nord Pool are the highest of all European power exchanges. Danish volumes reached 28 TWh (11 TWh for the east and 17 TWh for the west), representing 81 % of the national electricity consumption.

3.2. Gas. Denmark is a net exporter of natural gas. In 2010 it exported approximately 3.2 bcm of gas: 46 % to Sweden, 32 % to Germany and the rest to the Netherlands. Physical imports of gas into Denmark were not possible until October 2010. However, physical imports from Germany were made possible by a pressure service agreement with the owners of the DEUDAN pipeline, and approximately 0.15 bcm of gas was imported in 2010 (3 % of consumption). In Denmark there are two natural gas hubs, the Gas Transfer Facility (GTF) and the Nord Pool Gas Facility (NPTF).[29] The average day-ahead wholesale price on the Nord Pool Gas exchange (NPG) was EUR 23.3/MWh in 2011 (an increase of 26.6 % compared to 2010), and around 7 % of the gross inland consumption was traded on the day-ahead market. In 2010, DERA conducted a survey that showed that around 90 % of the total volume traded on the wholesale market in 2009 and 2010 was done under long-term take-or-pay contracts, while only 9 % and 1 % of the volume was done under OTC contracts and exchange contracts respectively. However, more recent figures show an increase in hub-based pricing. Furthermore, the market share of the Nord Pool Gas exchange has been growing rapidly, and the volumes traded on the gas exchange in 2012 account for about 15 % of the total consumption on the Danish gas market.

4. Retail markets

Danish consumers of electricity and gas have access to the free market without price regulation. However, consumers must choose a supplier to enter the market, and by default they are supplied by the energy supplier that has a licence for ‘obligation to supply’ in a specific geographical region. The four new suppliers that entered the market in 2010 compete mainly for household customers. This is a very important development, especially considering that about 90 % of Danish household consumers are still in the regulated segment.

4.1. Electricity. There are a total of 55 suppliers of electricity to households in Denmark. Each of the 33 supply obligation companies has been granted a concession for a specific geographic region where they supply households and small businesses that have not concluded an individual contract. Between 90 and 95 % of the Danish households and small businesses are supply obligation customers. The remainder of the trading companies supply small customers (who have used the liberalised market and changed supplier), larger businesses and enterprises. Price regulation exists for household and industrial consumers. The switching rate for households and small business was 3.5 % in 2011, lower than in previous years (4.2 % in 2010 and 6.1 % in 2009). DERA considers that a possible reason for this is a decrease in information campaigns encouraging the change of supplier. Power prices are characterised by high taxes, representing approximately 51 % of the final price.[30] Network costs accounted for 49 % of the power price for Danish households (without taxes) in 2011, with energy and supply costs making up the other 50 %. In the case of industrial electricity prices, the percentages were 43 % and 57 % respectively. The correlation analysis shows a considerable correlation between the wholesale and the retail price. There are no legal provisions for smart meters for customers consuming less than 100 000 kWh per year, since the cost-benefit study addressing a mandatory roll-out was negative in 2009. Nevertheless, approximately half of all households are equipped with advanced electronic meters enabling remote reading.

4.2. Gas. In 2010, there were 17 gas suppliers. There were six incumbent suppliers: three were supply obligation companies with regulated prices (DONG Energy Gasforsyning, NGF Gazelle Gasforsyning and HMN Salg) and three were affiliated commercial supply companies (DONG Naturgas, HMN Handel and NGF Gazelle). Even though the Danish retail market for gas was liberalised in 2004, regulated prices (for households and industry) still coexist with market prices. As in the case of power prices, gas prices are heavily taxed in Denmark. Apart from VAT, consumers pay an energy tax and a CO2 tax, which together can sometimes exceed the price of gas itself (depending on price developments on gas exchanges).

Charts 3 and 4

Source: Eurostat.

Notes: In industry VAT is refundable. Since 2007, Eurostat has applied a new methodology for the calculation of retail prices. The observed Eurostat categories are the following: DC — electricity households (2 500 kWh — 5 000 kWh), ID — electricity industry (2 000 MWh — 20 000 MWh), D2 — gas households (20 GJ — 200 GJ), i4 — gas industry (100 000 GJ — 1 000 000 GJ).

4.3. Consumers. Danish consumers rate the performance of their retail electricity and gas market above the EU average (12th place out of 27 and 9th place out of 23, respectively). The incidence of problems is, respectively, the lowest and third lowest in the EU while trust in providers and overall consumer satisfaction are above EU average (both score 3rd highest for gas market). On the other hand, comparability is amongst the three lowest ratings in the EU for both markets and the scores for choice, ease of switching, and actual switching are also below the EU average, probably due to the system of regulated prices that is still applied in Denmark. [31]

The Danish Energy Association publishes the electricity prices online. The Danish gas TSO does the same for gas. Complaints arising from the contractual relationship between household energy consumers and suppliers are dealt with by the Energy Supplies Complaint Board. The Board’s decisions are not binding or enforceable and the matter can be taken to court. There are no specific provisions regarding vulnerable consumers in energy law; instead this issue is dealt with in social legislation.

5. Infrastructure

5.1. Electricity. The supply system is historically robust, with only few system failures. Nevertheless, the European objectives on renewable energy could pose a challenge to the supply system. ENTSO-E has predicted power balance problems for Denmark in winters starting from 2016.[32] The Great Belt interconnection between Eastern and Western Denmark has operated from August 2010. Despite intensive usage, existing price differences between Danish regions may make further expansion of capacity necessary.

5.2. Gas. ENTSO-G has identified potential shortcomings with respect to demand versus entry capacity in the Denmark/Sweden region from 2014 onwards. The main cause is insufficient capacity at the German-Danish border, which cannot offset the depletion of Danish off-shore fields. Following an investment decision, a new 94 km gas pipeline in southern Jutland and a new compressor station in Egtved will probably be ready to transmit natural gas to Danish and Swedish consumers in October 2013. The pipeline, which will run from Ellund near the German border to Egtved, together with the compressor station in Egtved, will increase the capacity of the gas transmission network, allowing Denmark to import natural gas when gas production in the Danish part of the North Sea starts to decline. The expansion is expected to improve security of supply and increase competition in the gas market to the benefit of consumers.

KEY INDICATORS FOR THE ENERGY MARKETS IN DENMARK IN 2010

Sources: Eurostat, Energitilsynet (Danish Energy Regulatory Authority), EC calculations.

NA: Not available or not applicable.

(1) Companies are considered as ‘main’ if they produce at least 5 % of the national net electricity generation.

(2) Retailers are considered as ‘main’ if they meet at least 5 % of the total national electricity consumption.

(3) The HHI (Herfindahl-Hirschman Index) is a commonly accepted measure of market concentration. It is calculated by squaring the market share of each firm competing in the market and then summing the resulting numbers (the higher the index, the more concentrated the market). Moderate concentration: 750–1800, high concentration: 1800–5000; very high concentration: above 5000.

(4) Entities are considered as ‘main’ if they handle at least 5 % of the natural gas (indigenous production or imported).

(5) Retailers are considered as ‘main’ if they sell at least 5 % of the total natural gas consumed by final customers.

Estonia

1. General overview

Solid fuels, predominantly oil shale, were the most important energy source in 2010. Estonia is one of the largest producers of oil shale in the world and its energy sector relies heavily on this source, from which the bulk of its electricity also originates. Nevertheless, the share of renewables in the energy mix has been increasing; it tripled compared to 1990, reaching 13 % in 2010. Estonia set a target of 25 % of renewables in Gross Final Energy Consumption by 2020. In 2006 this share was 16.1 % and in 2010 it was 24.3 %. The share of cogeneration[33] was 10.3% in 2010, remaining practically unchanged compared to 2005 (10.2%).

Charts 1 and 2

Source: Eurostat

2. Regulatory framework

2.1. General. Following the opening of infringement proceedings in September 2011 for non- transposition, Estonia has declared that the Third Energy Package Directives have been now fully transposed. The Commission is conducting a prima-facie examination of the completeness of the transposition based on the measures notified and other information provided in the proceedings.

2.2. National Energy Regulator. The Estonian Competition Authority (ECA) also acts as regulator for several sectors. It has been in operation since 1998, and employs 62 staff (14 of whom work on energy issues) with an annual budget of almost EUR 1.83 million in 2011, both of which are low figures.

2.3. Unbundling. The electricity TSO, Elering AS, is state-owned and plans to apply for certification under the ownership unbundling model. There is one single operator in gas, namely AS EG Võrguteenus, which provides transmission and distribution services and belongs to the dominant gas trader AS Eesti Gaas, the main shareholders of which are Gazprom, E.On and Fortum. At the time of writing, this TSO is only legally unbundled, but the Estonian Parliament has recently adopted the Gas Law, which requires ownership unbundling to be implemented by 2015 (despite a derogation from the unbundling rules that Estonia enjoys on the basis of .

3. Wholesale markets

3.1. Electricity. The Estonian electricity market is very small. Effective competition is limited by the dominant position of Eesti Energia, which accounted for 89 % of total electricity production in 2010. The Nord Pool Tallinn power exchange, which started in April 2010,[34] is expected to generate more competition on the market. In 2011 there were 17 traders (including undertakings from Latvia and Lithuania) that operated in the NPS Estonia price area. From January 2011, the three Baltic TSOs decided to use implicit auctions to allocate capacity. From a technical perspective, the Estonian electricity system operates in synchronous mode with the systems in Russia, Belarus, Latvia and Lithuania. This interdependency requires an agreement with Russia and Belarus on how to operate the networks. Such an agreement will to allow Estonia also to explore fully the potential of integration with Nord Pool Spot. The Commission is negotiating this agreement on behalf of the EU. The average day-ahead wholesale price in 2011 for baseload power was EUR 43.4 /MWh (looking at the period from April to December 2010, the price was 7 % lower in 2011 within the same period).[35] In terms of liquidity, 5.8 TWh of this power was traded in the same year (72 % of electricity consumed).

3.2. Gas. Estonia imports natural gas exclusively from OAO Gazprom from Russia. In winter time, the Inčukalns underground gas storage facility is used. In 2011, 0.63 bcm were imported (100 % of gross inland consumption). Estonia has cross-border connections with Russia and Latvia only, and Russia is the sole supplier of gas in all three Baltic countries. Hence there is no competition between sellers. There is no organised hub, and therefore it is impossible to give a reference wholesale price. The estimates of long-term prices for Russian gas result in an annual average of EUR 27.8 /MWh for 2011 (an increase of 6.8 % compared to 2010).

4. Retail markets

4.1. Electricity. Estonia, in accordance with exemptions under the second energy package, is now in a transitional period towards market opening, and only eligible customers − who accounted for 33.2 % of the total consumption in 2011 − can switch suppliers. In 2010, Eesti Energia AS had a market share of almost 88 %. The second and third largest undertakings (VKG Elektrivõrgud OÜ and Imatra Elekter AS) have more or less the same share, namely 5.4 %. The market will be fully opened in 2013, which is likely to have beneficial effects on competition. Electricity retail prices increased (see chart 3), mostly because of the net energy price, but also due to taxes. In 2011 the share of network costs within the household price (without taxes) accounted for 58 %, while energy and supply costs accounted for 42 %. The proportions for industrial electricity prices were 51% and 49 % respectively. Prices are regulated for households and industry. The roll-out of smart meters is due to be dealt with in the next Energy Sector Development Plan 2030, which should be ready by the end of next year. The Estonian grid code determines that all consumers must be provided with a ‘remote reading device’ by 2017. No cost-benefit analysis has yet been carried out.

4.2. Gas. Because there is no proper wholesale gas market, the retail market for gas is not developed either. Eesti Gaas is in a dominant position in the retail market too. Its retail market share has consistently been above 90 %. Gas retail prices were more volatile than electricity prices. Any changes were chiefly due to the variations in the net energy price. The import price of gas is calculated according to the changes in the average price of heavy and light fuel oil, which explains the volatility of the gas price. End users pay the full import price, transportation cost and a regulated profit margin.

Charts 3 and 4

Source: Eurostat

Notes: In industry VAT is refundable. Since 2007, Eurostat has applied a new methodology for the calculation of retail prices. The observed Eurostat categories are the following: DC — electricity households (2 500 kWh — 5 000 kWh), ID — electricity industry (2 000 MWh — 20 000 MWh), D2 — gas households (20 GJ — 200 GJ), i4 — gas industry (100 000 GJ — 1 000 000 GJ).

4.3. Consumers. Retail gas market is assessed third highest in the EU, with the second highest score on comparability. However, consumer assessment of choice, switching and ease of switching is amongst the three lowest in the EU and has been falling since 2010. Also the performance of retail electricity market is assessed above EU average (8th position out of 27), with the highest score in the EU on comparability of services. [36] There is no price comparison site available for the electricity and gas retail market. The NRA acts as an alternative dispute resolution body. Consumers can also contact the Consumer Protection Board of Estonia.

5. Infrastructure

5.1. Electricity. Estonia is interconnected to the EU electricity market through Estlink1, and recently joined Nordpool spot by creating the Estlink price area for day-ahead market and trading in the power exchange. The limited capacity of the connection between Estonia and Latvia creates cross-border bottlenecks, which have an adverse impact on the electricity markets of Estonia and the other Baltic States.

5.2. Gas. Estonia’s gas grid is connected to the gas system of the Russian Federation as well as to that of Latvia. There is no link with the rest of the EU gas market. There is one gas supply contract with Gazprom, which ends in 2015. Eesti Gaas AS expects to extend this contract for a further period. As part of the BEMIP initiative, there are plans to end Estonia’s isolation from the EU market. Significant infrastructure investment is needed in order to diversify sources and increase security of supply. An interconnection between Lithuania and Poland, as well as a regional LNG terminal in the Baltic States or Finland, are among the topics under discussion. In order for the investments to reach the potentially necessary scale, the connection to Finland may also be needed. This could be done via the planned Balticconnector.

KEY INDICATORS ON THE ENERGY MARKETS IN ESTONIA IN 2010

Sources: Eurostat, CEER, Konkurentsiamet, EC calculations.

NA: not available or not applicable

(1) Companies are considered as ‘main’ if they produce at least 5 % of the national net electricity generation.

(2) Retailers are considered as ‘main’ if they meet at least 5 % of the total national electricity consumption.

(3) The HHI (Herfindahl-Hirschman Index) is a commonly accepted measure of market concentration. It is calculated by squaring the market share of each firm competing in the market and then summing the resulting numbers (the higher the index, the more concentrated the market). Moderate concentration: 750–1800, high concentration: 1800–5000; very high concentration: above 5000.

(4) Entities are considered as main if they handle at least 5 % of the natural gas (indigenous production or imported).

(5) Retailers are considered as ‘main’ if they sell at least 5 % of the total natural gas consumed by final customers.

Finland

1. General overview

In 2010, crude oil and petroleum products had the largest share (27.8 %) of the country’s energy mix, followed by renewable energy sources (RES). Finland’s power generation mix was dominated by nuclear energy (28.3 %) and RES (30 %), while solid fuels and natural gas also contributed significantly to electricity production. The share of RES in the country’s gross final energy consumption in 2010 was 32.2 %, which is almost three times as high as the EU average of 12.5 %. Finland’s overall RES share in 2020 is predicted to be 38 %. The share of cogeneration[37] was 36.2% in 2010, one of the highest in the EU, however, slightly less than in 2005 (38.9%).

Charts 1 and 2

Source: Eurostat

2. Regulatory framework

2.1. General. Following the opening of infringement proceedings in September 2011 for non- transposition, Finland has notified only partial transposition of the Third Package Directives.

2.2. National Energy Regulator. In 2010, the Finnish national regulator, the Energy Market Authority (EMA), employed 45 staff and had an annual budget of almost EUR 5 million. It has been in operation since 1995.

2.3. Unbundling. The electricity TSO is Fingrid, in which the state has a majority stake (about 53 %) with institutional investors owning the rest. The certification of this TSO has not yet taken place. There are 87 electricity distribution companies (of which 52 are legally unbundled) and 12 regional network operators. The gas TSO, Gasum, is vertically integrated and the shareholders are Fortum, E.On, Gazprom and the Finnish state. No changes in the ownership structure are envisaged, as Finland has a derogation from the Gas Directive exempting it from legal and operational unbundling (Article 49). There are 23 gas DSOs.

3. Wholesale markets

3.1. Electricity. At the generation level, the market is dominated by two big players, Fortum (which is mostly state owned) and Pohjolan Voima (PVO). The three biggest companies control approximately 58 % of the total installed capacity. The Finnish power market is integrated into Nord Pool’s wholesale market.[38] Electricity is traded via Nord Pool (76 % of total volumes in 2011) and bilaterally (24 %). In 2010, the Nordic market took steps to become better integrated with the markets of continental Europe and the Baltic states through the opening of the new Estonia bidding area in the Nord Pool Spot market and through the coupling between the Nordic and central west European regions. In terms of liquidity, in 2011 51.1 % of the country’s gross inland electricity consumption was traded on the Nord Pool Spot.

3.2. Gas. Finland does not produce gas. The country’s imports of gas amounted to 4.7 bcm in 2010, which came exclusively from Russia on the basis of long-term contracts. There is only one importer, Gasum Oy, which is consequently the only party active on the wholesale market. Gasum is a vertically integrated company that also operates the transmission system. Even further downstream, Gasum is also a distribution operator and the supplier (in addition to other DSOs and suppliers). The majority of Gasum Oy’s natural gas customer contracts are based on a public tariff, and are renewable at 4-yearly intervals. In addition to these long term products, Gasum Oy offers short term products that are sold on the Kaasupörssi Oy gas exchange, which has existed since 2002.

4. Retail markets

4.1. Electricity. Market concentration at retail level was moderate in 2010 as there were four retail power utilities whose market share was above 5 %, with the three largest actors controlling around 35-40 % of the market. Supplier switching is common for industry and big companies but still low for very small commercial and households customers. Low retail prices do not induce them to change supplier. In 2010 the switching rate was roughly 7.6 %, which is slightly down on the previous year (8 %). Power prices for both households and industrial consumers have gradually increased between 2005 and 2011, although it is worth noting that industrial prices remained below the level of household prices and VAT-free industrial prices were more stable than those of households. At the beginning of 2011, non-refundable taxes increased for both industrial and household consumers. In 2011, network costs accounted for 43 % of Finnish household electricity bills (without taxes), while the share of energy and supply costs was 57 %. For industrial electricity prices, these ratios were 27 % and 73 %, respectively. Price regulation does not exist in Finland. A correlation analysis shows a strong correlation between the wholesale and retail electricity prices. Finnish electricity market legislation provides for a roll-out of smart meters by 2014. More than half of the country’s 3.1 million metering points are already equipped with smart meters.

4.2. Gas. Market concentration at the retail level was moderate at the end of 2010, as the share of the top three retail suppliers was about 50 % in terms of total gas volume. However, gas retailers in Finland have a monopoly within their own distribution network. There were 23 natural gas suppliers, most of whom had only a dozen customers. The retail supply of natural gas in the distribution network covers only about 5 per cent of the total amount of gas consumption. In Finland there were only about 36 000 customers in the natural gas market, of which the largest segment (29 000 consumers) comprised households that used only 0.02 % of the country’s annual gas consumption in 2010.

Charts 3 and 4

Source: Eurostat.

Note: in industry VAT is refundable and therefore not included.

4.3. Consumers. Finnish consumers rate the performance of their retail electricity market above the EU average (10th place out of 27). The market is assessed slightly above EU average on all indicators with the exception of comparability, problems and complaints.[39]Electricity prices can be compared through a price comparison tool, managed by the National Regulatory Authority. Finland has a single point of contact for information requests on gas and electricity legislation, prices and consumer rights, which is provided by the NRA. However, responsibility for handling complaints is divided between the NRA and consumer bodies. The Consumer Disputes Board is an impartial body of experts that acts as an alternative dispute resolution mechanism. As regards electricity, the legislation provides specific protection to vulnerable customers, typically through time and climate-based restrictions for disconnection. Social assistance is provided as a last resort to individuals with inadequate income to cover energy bills.

5. Infrastructure

5.1. Electricity. Finland is connected to Sweden, Estonia, Norway and the Russian Federation. The Estlink1 cable between Finland and Estonia has provided Estonia with the opportunity to integrate with the Nordic market. However, interconnection capacity with the Baltic states is insufficient — in 2011 Estonian and Finnish prices differed about half the time. The second interconnection with Estonia, Estlink2 (with the capacity of 650 MW), is planned for early 2014. It should substantially reduce congestion and strengthen Finland’s integration with the continental EU markets, as well as open up the possibility of exporting electricity to Russia (in 2010 electricity imports from Russia were 11.7 TWh, with no possibility of exporting).

5.2. Gas. The Finnish natural gas market is isolated. Finland is connected to the Russian transmission system, but there is no transmission connection to other EU countries.

KEY INDICATORS FOR THE ENERGY MARKETS IN FINLAND IN 2010

Sources: Eurostat, CEER, National Regulatory Authority, EU calculations.

NA: not available or not applicable.

(1) Companies are considered as ‘main’ if they produce at least 5 % of the national net electricity generation.

(2) Retailers are considered as ‘main’ if they meet at least 5 % of the total national electricity consumption.

(3) The HHI (Herfindahl-Hirschman Index) is a commonly accepted measure of market concentration. It is calculated by squaring the market share of each firm competing in the market and then summing the resulting numbers (the higher the index, the more concentrated the market). Moderate concentration: 750–1800, high concentration: 1800–5000; very high concentration: above 5000.

(4) Entities are considered as ‘main’ if they handle at least 5 % of the natural gas (indigenous production or imported).

(5) Retailers are considered as ‘main’ if they sell at least 5 % of the total natural gas consumed by final customers.

France

1. General overview

The largest share of total gross inland consumption (energy mix) comes from nuclear energy, with 41 %. Oil (31 %) is the second largest energy fuel, followed by gas (16 %).The power generation mix is dominated by nuclear generation, with the highest share in the EU (76 % in 2010). Renewables contribute to 14.7 % of electricity production. France’s 2020 renewable target indicator[40] increased from 9.8 % (2006) to 12.9 % (2010), and it aims to reach 23 % by 2020. The share of electricity from cogeneration[41] in the overall electricity production was 2.8% in 2010; slightly less than in 2005 (4%).

Charts 1 and 2

Source: Eurostat

2. Regulatory framework

2.1. General. Following the opening of infringement proceedings in September 2011 for non- transposition, France has notified full transposition of the Third Package Directives. One infringement procedure is still open under the Second Package concerning regulated gas prices.

2.2. Regulator. The French National regulatory Authority (Commission de Régulation de l’énergie -CRE), in operation since 2000, employed 131 staff with an annual budget of almost EUR 21 million. New competences were attributed to CRE with the adoption of the new electricity law called NOME (new organisation of the electricity market[42]) approved in December 2010, but the regulator is concerned that, despite the new competences assigned to CRE by law, the budget allocated and the staff limit set by the ministry have not been increased accordingly.

2.3. Unbundling. France has chosen to implement the ITO model as the unbundling regime for electricity and gas TSOs. The TSO in electricity is Réseau de Transport d’Electricité (RTE) entirely owned by Electricité de France (EDF). In gas there are two TSOs: TIGF, which is owned by Total (100 %), GRTgaz, which, since July 2011, is owned by GDF SUEZ (75 %) and a public consortium composed of the Caisse des Dépôts et des Consignations and CNP Assurances (25 %). All three TSOs have been certified by CRE. As far as the distribution network in electricity and gas is concerned, the French regulator considers progress has still to be made as regards DSO independence vis-à-vis their parent companies. In electricity, one DSO (ERDF) represents 95 % of total distribution and the remainder is made up of almost 160 other local companies. In gas, there is one big DSO (GrDF) and 24 local distributors.

3. Wholesale markets

3.1. Electricity. The French market remains one of the most concentrated electricity markets in the EU. Generation is dominated by EDF, although some competitors are entering this segment with the construction, for instance, of new combined cycle gas turbines. The only EDF competitors, GDF-Suez (5.5 % of installed capacity) and E.On-France (3 % of installed capacity), have a negligible share of the market. EDF has 91 % of the installed capacity and the three largest generators have 99 % of total installed capacity. The NOME law aims to foster competition in the French electricity market. Under this law, EDF, which owns and operates all nuclear plants in France, is obliged to sell up to 100 TWh annually to its competitors. With this new law, incumbent competitors’ market share increased from 25.5 % to 29.6 % between May and September 2011.

A substantial proportion of wholesale trade in the electricity market takes place over-the-counter (OTC). In 2011 it was 84 % of all exchanges. Market integration with neighbouring markets was successfully carried out through Trilateral Market Coupling in 2006, involving France, Belgium, and the Netherlands. Since November 2010, market coupling is extended to Luxembourg and Germany. In 2011, the common allocation platform of the Central West region was extended to the Central South and Swiss borders, followed by the consolidation of a single set of harmonised allocation rules. After integrating the French and German markets in 2010, a cross-border intraday mechanism was introduced with Italy. Finally, after implementing a cr