# EUR-Lex - 52012SC0368 - EN

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# 52012SC0368

**COMMISSION STAFF WORKING DOCUMENT Energy Markets in the European Union in 2011 Accompanying the document COMMUNICATION FROM THE COMMISSION TO THE EUROPEAN PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL COMMITTEE AND THE COMMITTEE OF THE REGIONS Making the internal energy market work /* SWD/2012/0368 final */**

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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 cross-border balancing mechanism
(BALIT) with UK TSO National Grid, NRAs and TSOs are now working to extend
BALIT to the South-West region in the beginning of 2013.

The
2011 annual average wholesale price in France was EUR 48.9
/MWh[43]
(corresponding to a 2.8 % increase
compared to 2010). Despite being Europe’s second largest market, France has
much lower liquidity than Germany (the ratio of day-ahead traded volume of
power compared to the annual gross inland electricity consumption was 12.5 %
in France compared to 47.1 % in Germany), owing mostly to its regulated
tariffs and high market concentration.

3.2. 
 Gas. France
imports almost its entire gas demand. In 2010, natural gas was imported through
long-term contracts, mostly from Norway (32.5%), the Netherlands (15%), Russia (14%), Algeria (14%) and LNG-suppliers. As the spread between long term contracts and the
spot price increased, suppliers renegotiated the price conditions of long-term
contracts. The renegotiations introduced indexation for certain contracts to
wholesale gas market prices, which brought the portion of the volume of these
contracts indexed to market prices up to 25.9 % for some suppliers in
2012.[44]

4. Retail
markets

4.1. 
Electricity. Market
concentration at retail level was high in 2011. The three largest companies
had a market share of 96 % in 2011 for households and small industry. The
only company with a market share exceeding 5 % was EDF. Over the last
decade, power prices in France have remained almost stable. Since 1 July
2007, all consumers have had the choice between opting for regulated prices or
not. At the end of 2011, nearly 94 % of households remained under
regulated tariffs. As regards non-residential sites, nearly 85 %
(representing 56 % in volume) remained under regulated tariffs. In 2011, regulated
prices rose less than in 2010. Switching of electricity suppliers in
the retail markets increased in France in 2011, from 2.0 % in 2010 to 3.7 %
in 2011.

4.2. 
Gas. Similarly to the
electricity market, concentration at retail level in gas was high in 2011. The
three largest companies had a market share of 95 % in 2011 for households
and small industry (86 % of market share in volume). Consumers have had
the choice between opting for regulated prices or not, since 1 July 2004 for
non-household customers and 1 July 2007 for household customers. In 2011, 86 %
of residential sites and 58 % of non-residential sites connected to the
distribution network remained under regulated tariffs. In order to take into
account the new indexing of certain long-term contracts to wholesale gas market
prices, the regulated tariff formula was revised by law on 22 December 2011.
Switching of gas suppliers in the retail markets increased slightly in 2011,
from 3.5 % in 2010 to 4.5 % 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.
French consumers rate the performance of their retail electricity market above
the EU average (9th place out of 27), with the second lowest
incidence of problems and  the lowest percentage of complaints. However,
switching is about one third of the EU average (second lowest in the EU). The
assessment of the retail gas market is just below the EU average (13th
place out of 23).[45]
In 2009, the NRA together with the National Energy Ombudsman introduced an
on-line price comparability tool for electricity and gas prices. In France, complaints handling is shared among various institutions, depending
on the nature of the complaint. France has not yet defined a category of ‘vulnerable
consumers’ but it does guarantee access to gas and electricity to people in
precarious situations, who can benefit from specific regulated tariffs for the
first 100kWh of electricity every month and for gas through the Housing
Solidarity Fund (FSL).

5. 
Infrastructure

5.1. 
Electricity. France is interconnected with all its neighbouring countries, the United Kingdom, Belgium, Germany, Switzerland, Italy and Spain, but capacity is currently insufficient. In order to
better integrate the markets, foster competition and reduce congestion, the
French TSO (RTE) is reinforcing its interconnections with Spain by building the Baixas-Santa Llogaia high voltage line to reach a total capacity of
2600MW by 2014. For this project, the authorisation process was, after many
years, completed in 2011 and construction work has already started. The
European Investment Bank will provide a EUR 350 million loan to
the French and Spanish TSOs. The project also receives a EUR 225 million
EU grant under the European Energy Programme for Recovery. In addition, the
French (RTE) and the Italian (TERNA) TSOs are optimising the existing
interconnection and have agreed to develop a new one of 1000MW between Savoie
and Piedmont by 2017. During the summer of 2012, the British and French TSOs
launched submarine studies for a new interconnection between France and the United Kingdom and an investment decision is expected for the beginning of 2013.
Additional interconnector projects are also under consideration, in particular
a DC link in the Western part of the France-Spain border, expected to reach a
total capacity of 4000 MW. The French regulator is contemplating implementing
specific incentive measures to foster interconnection investments.

5.2. 
Gas. France
depends on gas imports (98.5 %). France has six interconnections with
neighbouring countries, one interconnection with a subsea pipeline (Dunkirk) and three LNG terminals. A fourth LNG terminal (Dunkirk) is being developed for
completion by 2015. The French network is being reinforced to improve
interconnection capacity, notably with Germany, Belgium and Spain, and to increase the liquidity of the gas market.

The
European Energy Programme for Recovery (EEPR) has granted to the French TSOs
(GRT-Gas and TIGF) € 283.7 million to reinforce the French Network and
increase the interconnection capacities with Spain and Belgium.

KEY INDICATORS ON THE ENERGY
MARKETS IN FRANCE IN 2010

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

Germany

1. General
overview

In
2010, the energy mix was dominated by fossil fuels, with crude oil and
petroleum products accounting for more than one third. Solid fuels were almost
equally divided between lignite and hard coal. In the electricity mix, fossil
fuels had again the highest share, but solid fuels were the main source. The
main source of renewable electricity was wind, contributing 38 TWh in 2010. As
far as the renewable target for 2020 is concerned, the goal for Germany is an 18 % share of renewable energy.[46]
This improved from 7.1 % in 2006 to 11 % in 2010. The production of
renewable energy has substantially increased in Germany, meeting 20 % of
consumption in 2011. Germany intends to increase this figure further to 35 %
by 2020. The share of electricity from cogeneration[47] was 13.2% in
2010, which is a slight increase compared to the 2005 level of 12.6%.

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General. As Germany had notified full transposition of the Third Package Directives by the end of
September 2011, no infringement proceedings for non-transposition have been
opened. One infringement procedure is still open on the Second Package,
concerning the lack of congestion management and transparency provisions for
access to the network for the cross-border exchange of electricity.

2.2. 
National Energy Regulator.
In 2010, the German national regulatory authority, the Bundesnetzagentur,
employed 2600 employees, with 185 working on energy issues, and had an annual
budget of EUR 155.4 million, including around EUR 18 million for
energy regulation.

2.3. 
Unbundling. Germany’s power transmission system comprises four TSOs: Tennet, Amprion, 50Hertz and
TransnetBW. There are 54 regional utilities responsible for distribution and
over 800 municipal distributors. For gas, there
were 18 transmission system operators in 2010, down from 22 in 2006, the
largest being Open Grid Europe, Wingas, Ontras, and Thyssengas, and 27 regional
network operators. In 2011, there were 743 distribution system operators. The
certification of most TSOs is under way. The
German TSOs have opted for different unbundling models, i.e. partly for
ownership unbundling (OU), partly for the Independent Transmission Operator
(ITO) model. Both choices are as such legitimate under German law.

3. Wholesale
markets

3.1. 
Electricity.
Generation is still dominated by four large private companies, E.ON, RWE, EnBW
and Vattenfall. Although their share was reduced after antitrust investigations
by the Commission and the commitment by E.ON to divest 5000 MW of its
generation capacity,[48]
the four largest producers together still controlled 82 % of the German
electricity wholesale market in 2010.[49]
The special regime for renewable power generation in terms of pricing and
marketing in Germany poses specific challenges in that it tends to weaken the
strength of market signals.

The
German and Austrian wholesale markets are largely integrated.[50] Market
integration with other neighbouring markets is progressing thanks to the
introduction of market coupling in the CWE and Northern regions. Through the
coupling of electricity markets in north-western Europe, the national
electricity spot markets of 9 countries are now integrated at wholesale level.
The power exchange EEX, located in Leipzig, operates the German power
derivatives market (futures and options), whereas the German spot market
(day-ahead and intra-day) is operated by EPEX Spot in Paris. Liquidity on both
EEX and EPEX Spot is high. Regarding the trade in day-ahead volumes, this
reached 238 TWh on EPEX Spot in 2011[51]
(47.1 % of German power consumption). The average day-ahead wholesale
price in 2011 for baseload power was EUR 51.1/MWh (an increase of 14.8 %
compared to 2010). Compared to neighbouring countries[52], the German
energy price at wholesale level is fairly competitive, which can be explained
partly by favourable weather conditions for the production of renewable electricity
(mostly wind) and also its maturing technology, which decreases the marginal
costs of wind power.

3.2. 
Gas. Germany produced approximately 13 % of its consumption in 2010, with net imports accounting
for 82%. In volume, natural gas imports amounted to 88.7 bcm with the following
breakdown : 37 % Russia, 33 % Norway, 25 % Netherlands and 5 % other countries. The German gas market has seen significant
developments towards more competition over recent years. The German regulator
has implemented an entry-exit system, reformed the balancing rules and reduced
the number of market areas drastically, from more than 20 in 2006 to six in
2009 and only two market areas today. Today, Germany has a dual-quality market
area (the L-gas and H-gas networks requiring separate operation for technical
reasons) with all customers included in one large balancing area. Two antitrust
decisions by the Commission addressed the problem of insufficient access to
transport capacity in Germany. The Commission’s
intervention led RWE to divest its gas transport network and E.ON to release
significant volumes at the entry points to its gas networks. Congestion of main
import/export points due to long-term bookings remains an obstacle to
cross-border trade and competition.
Recent German legislation on capacity allocation and congestion management is
intended to improve the situation, particularly by increasing the use of
capacity auctions on a centralised booking platform. Both German virtual points
(hubs), NCG and Gaspool, have grown significantly since 2007. The volume of
trading on the exchange has grown steadily, recording an increase of 216 %
in 2010 compared to 2009. One main reason for this was additional procurement
on the exchange for system balancing energy by the two balancing zone
operators, NetCologne Germany and Gaspool.[53].
The average day-ahead wholesale price in 2011 was EUR 22.9/MWh on both
hubs (an increase of 30.9 % compared to 2010, which reversed the
significant drop in 2009). This was due to the improvement in the economic
climate and the rise in gas demand. Regarding liquidity, 9 TWh in
day-ahead volumes were traded in 2011, compared to the national consumption of
870 TWh. With a churn rate of 2.1 for H-gas zones, as compared to that for TTF
(3.4), there is a potential to increase liquidity. Gas delivered through Nord
Stream is expected to contribute to a higher churn rate.

4. Retail
markets

4.1. 
Electricity. In
2010, the share of the four largest electricity suppliers for household
customers at national level was 43.8 % (a drop of 6.3 % within two
years). However, this trend at national level has not affected the continuing
dominant position of local basic suppliers at regional level, such as
Stadtwerke. Household customers are still reluctant to switch away from local
basic suppliers despite price discrepancies and the presence of competitors.
Supplier switching increased from 4.9 % in 2009 to 6.3 % in
2010. Power prices for households and industrial consumers have
increased in recent years. The structure of retail prices reveals that net
power prices have changed only marginally, decreasing slightly for industrial
consumers. The increase in retail prices is mostly due to taxes and levies. Network costs accounted for 42% of the electricity bill for
German households (without taxes) in 2011, while energy and supply costs took
up 58%. In the case of industrial electricity prices these proportions were 27%
and 73% respectively. End-user prices are not regulated. A correlation
analysis of half-yearly averages for industry shows a moderate influence of
the wholesale price on the retail price with a time lag of six months. For
households, this influence was less apparent. German law requires smart
meters to be installed in new buildings, in buildings undergoing major
refurbishment and for customers consuming over 6000 kWh per year. No nationwide
roll-out schedule is in place yet.

4.2. 
Gas. In
2010, some 720 000 household customers switched gas suppliers. The volume
of gas supplied to customers who had already switched doubled from 47.18 TWh in
2009 to 110.38 TWh in 2010. This corresponds to a switching rate of 10.88 %.
In 2010, most household customers had a choice of between 11 and 20 gas
suppliers. In 36 network areas, a household customer could already choose from
over 50 suppliers. Another important trend is the fact that the wholesale
prices for gas, which had decreased significantly since the second half of
2008, has had a positive influence on household customer prices.

Gas
prices for final consumers were more volatile than
power prices. For both households and industry, they decreased after 2008 and
increased again in 2011. This can be explained by the general drop in energy
prices due to the economic slowdown in 2009 and the subsequent recovery. Unlike
for power prices, taxes had less impact on price movements. The correlation
analysis of half-yearly prices points to a significant influence of the
wholesale price on retail prices for households and industry. For industry, the
correlation is stronger within the same half-year, but for households it
increases with a lag of six months. End-user prices
are not regulated.

Charts
3 and 4

Source:
Eurostat

Note:
since 2007, Eurostat has applied a new methodology for the calculation of
retail prices.

4.3. 
Consumers.
German consumers rate the performance of their retail electricity market third
highest of all EU countries and scores on choice, comparability and ease of
switching are amongst the three highest in the EU. A similar picture is
observed for the retail gas market (ranked 6th highest in the EU),
where the scores for ‘choice’ and ease of switching are the highest in the EU
and the number of complaints is the second lowest.[54]While there is no officially
recognised online price comparability tool, there are a number of
privately run online price comparison services for electricity and gas. Bundesnetzagentur
provides advice for energy consumers via a hotline. Complaints are
handled by the NRA, although it does not settle disputes between customers and
suppliers. For out of court settlements, this task was attributed to a special
arbitration body for energy. Germany does not specifically define ‘vulnerable
consumers’ in energy law, but assistance is provided under general social
laws and related support schemes. This includes bill rebates, discounted
tariffs, benefit entitlement checks, and debt advice to low-income families
with several family members and specific needs.

5. 
Infrastructure

5.1. 
Electricity. In
the light of the Fukushima accident and following review of its policy on
nuclear energy, Germany decided to shut 8 nuclear power plants in 2011 (8300
MW). This has led to a significant drop in capacity in the south of Germany and increased the need for power transportation from north to south. North-south
and east-west power flows in Germany increased in the first half of 2011. With
new wind parks being developed in the North and Baltic Seas and a further
increase in the share of renewable generation (35 % planned for 2020), the
existing bottleneck on the north-south axis will be further exacerbated. The
German electricity grid is expected to see increasing electricity imports, and
network constraints will significantly aggravate the current problem of loop
flows on neighbouring systems. In 2011, Germany passed a law requiring a
network development plan to be prepared jointly by all TSOs, with the aim of
streamlining planning procedures at federal level. Technical, financial and
environmental expertise has been brought together within Bundesnetzagentur.
Until recently, priority projects were progressing only slowly due to public
acceptance issues and the separation of spatial and regional plan approval
regimes. This situation might improve now that Germany has a streamlined
approval regime at federal level.

Under
the European Energy Programme for Recovery (EEPR), one important north-south
link, the Halle-Schweinfurt electricity line, has received funding of
EUR 100 000 000 and should be completed in the coming years.

5.2. 
Gas. After the UK, Germany is the EU’s second largest gas market, accounting for 17 % of EU gas consumption.
86 % of its imports arrive via pipelines. It has the largest gas storage
capacity in the EU (20 bcm). In November 2011, the first arm of Nord Stream
came online, the second arm followed in October 2012 Nord Stream has the
capacity to bring a total of 55 bcm/y of Russian gas to Germany by the end of
2012. Germany will have to enhance the interconnectivity of its gas
infrastructure to neighbouring countries, including reverse flows, and develop
new north-south and east-west transport capacity. Good progress is being made
on reverse flows with Austria. Significant bottlenecks remain at the borders
with Denmark (Ellund) and Poland (Lasow), within southern Germany and on the north-south route.

KEY INDICATORS FOR THE ENERGY
MARKETS IN GERMANY IN 2010

Sources: Eurostat, CEER.

(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.

(6) Value for 2009.

Greece

1. General
overview

Oil
and petroleum products represented 53.2 % of Greece’s energy consumption
mix in 2010, followed by solid fuels (27.8 %), natural gas (11.4 %)
and renewables (7.6 %) (Chart 1). Power is mainly produced from solid
fuels (Chart 2). Greece’s 2020 renewable target indicator[55] increased
from 7.2 % (2006) to 9.2 % (2010), and it aims to reach 18 % by
2020. The share of cogeneration[56] was 4.3% in 2010, which is a significant increase compared
to the share of 1.7% in 2005.

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General. As Greece had notified full transposition of the Third Energy Package Directives by the end of
September 2011, no infringement proceedings for non-transposition have been
opened. Two infringement procedures are still open on the Second Energy Package
concerning: i) lack of transparency of conditions for access to the natural gas
transmission network and ii) regulated prices for non-household customers for
electricity.

2.2. 
National Energy Regulator.
The Regulatory Authority for Energy (RAE), established in 1999, operates with
88 staff and a budget of EUR 8.3 million (2010). The Third Energy Package
transposition law provides for stronger independence of the RAE. However, in
practice, RAE’s autonomy in implementing the allocated budget, as planned under
the transposition law, is severely compromised by the austerity measures that
affect all public administrations in Greece. RAE has not been allowed to fill
vacant posts, despite the fact that in the last two years, more than a third of
RAE’s scientific personnel has sought employment elsewhere. Half of this group
has left, after their salaries were cut by over 50 % in many cases. This
situation is starting to impact on RAE's ability to fulfil its tasks.

2.3. 
Unbundling. ADMIE,
the newly established TSO in electricity, is a wholly owned subsidiary of the
incumbent electricity company PPC S.A., which in turn is majority owned by the Greek State.[57] The incumbent
TSO in the gas sector is DESFA, which operates both the national grid and the
Revithoussa LNG terminal. DESFA belongs to DEPA, which is majority state-owned.
The Greek energy law provides for an ITO solution for the electricity TSO and
either ownership unbundling or ITO for the gas TSO.[58] The
certification process is ongoing. Regarding distribution, an electricity DSO,
DEDDIE, has been recently established, which is wholly owned by PPC. Legal and
functional unbundling have been implemented; the network assets, however, still
belong to PPC. In gas, Greece is still developing its market and therefore
applies derogations, including from market opening and unbundling, for the
establishment of gas distribution companies.

3. 
Wholesale markets

3.1. 
Electricity.
Regarding generation, PPC S.A. accounts for 75 % of total
electricity production, which is a pronounced decrease from almost 100 %
in 2009. Independent producers achieved a share of 20 %, mostly from the
use of gas-fired power generation (Elpedison 8.9 %, Mytilinaios 5.6 %
and Heron Thermoelectric 5.3 %). The wholesale market is also still highly
concentrated, but some competition is emerging. 2010 was a significant year for
the Greek wholesale electricity market as a market design reform was completed,
which introduced a distinction between day-ahead markets and balancing
mechanisms, as is the case in other countries with mandatory pools.[59] Market
integration with neighbouring markets remains very low and consequently
price differentials with neighbouring countries are high: the 2011 annual
average wholesale price in Greece was EUR 59.36/MWh
(corresponding to a 30 % increase compared to 2010), which is above most
wholesale prices in the EU.[60]

3.2. 
Gas. Greece
imports its entire gas demand. In 2010, 3.9 bcm of natural gas were imported
with 52% coming from Russia, 31% from Algeria and 17% from Turkey. Until 2010, the Greek wholesale market for gas was foreclosed due to incumbent DEPA’s exclusive rights
for imports, transmission and supply. However, at the beginning of 2010, Greece introduced third-party access to the transmission grid and to the Revithoussa LNG
Terminal. This allowed the first non-DEPA gas imports via the Revithoussa
Terminal in May 2010, de facto opening up the Greek market. Despite this
positive development, there is still no functioning wholesale market and there
is no spot market. Consumers who want to have access to gas without contracting
with DEPA need to make a bilateral contract with a supplier of LNG and book
capacity in the LNG terminal separately. RAE has taken the first steps towards
more transparency on the gas market by publishing data on a monthly basis on
the weighted-average import price of natural gas into the National Natural Gas
System (NNGS).

4. Retail
markets

4.1. 
Electricity. The
retail market remained highly concentrated in 2010. Only about 7 % of
industrial and commercial customers connected to the medium voltage network
switched supplier (a volume of 8.42 %).[61]
Switching by customers connected to the low-voltage market (including all
household and smaller commercial customers) remained insignificant due to
limited competition and price regulation below cost-reflective levels. By the
end of 2011, nearly 6.18 % of industrial and commercial customers
connected to the medium voltage network had switched supplier. The percentage
in the low-voltage market segment, by number of eligible meter points, was
around 2 % for household customers and 2.4 % for small industry
customers.

Power
prices for households increased in 2010 and in 2011, mainly due to a sharp rise
in VAT and other taxes, but also as a consequence of adjustments in regulated
tariffs to bring them more in line with costs. From 2009 onwards, increases in
prices for industrial customers were also due to the increasing tax and levy
component of end-user prices and an adjustment in regulated tariffs, triggering
a 14 % rise in power prices between 2008 and 2011. In 2011, the share of
network costs within the household prices without taxes was 28 %, which
was among the lowest in the EU-27. The share of network costs in industrial
retail prices without taxes was even lower at 17 %.

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).

At
the end of 2011, price regulation for medium-voltage customers was removed.
Price regulation for domestic and small business customers is expected to
continue until mid 2013.

Greece
is starting to roll out smart meters and has adopted a legal framework on the
implementation of smart metering (Article 15 of Law 3855/2010). However, no
official schedule for the roll-out has been published.

4.2. 
Gas.
Natural gas has only been available in Greece since 1997 and its use has been
actively promoted through tax rebates, in order to reduce the use of oil. From
2010, however, due to the economic crisis, gas consumption-related taxes have
been substantially increased. There are currently three regional gas distribution/supply
companies (called EPAs, the majority owned by DEPA) that operate under a
concession regime for a period of thirty years. EPAs hold the exclusive
(monopoly) right to (a) plan, design, construct, operate and exploit the
distribution network in their respective area and (b) supply gas to small
consumers (annual consumption <100 GWh/pa) in their respective area. As a
result, small consumers connected to the distribution grid of each EPA are not
eligible and cannot switch to alternative gas suppliers. No Eurostat data are
available for retail prices in Greece. EPAs publish their monthly prices on
their websites.

4.3. 
Consumers. The
retail electricity market is assessed forth lowest in the EU. Trust in the provider, comparability of services and
overall satisfaction are amongst the four lowest ratings in the
EU. Retail gas market is assessed
slightly above EU average (10th place out of 23) but the switching
rates are the third lowest in the EU[62]. The Citizen Service Centres (KEP) Network throughout the
country acts as a single point of contact
providing all necessary information on consumer rights. A price
comparison tool service would currently be of limited use as prices
for households are still regulated. The RAE handles complaints.
Responsibility for consumer dispute settlement
lies with the Hellenic Consumer's Ombudsman and other institutions.[63] It is nevertheless noticed that the activities handled by KEP and
REA should be better advertised. Vulnerable customers are
classified into five household categories, including elderly people, those in
energy poverty, life support-dependent, the physically or mentally disabled and
customers in remote areas (such as non-interconnected islands), who are
entitled to special services.[64]
A Social Tariff for Domestic Customers is in force
since January 2011.

5. 
Infrastructure

5.1. 
Electricity. As a
result of the economic and debt crisis, Greek demand for electricity has
substantially decreased since 2009. In the years preceding 2009, Greece had experienced a steep growth in demand. Expansion projects for the power
transmission grid are planned for the coming years with a view to improving the
power supply to the Aegean islands, increasing penetration of RES projects on
the islands and reducing PSO costs (the higher cost of generation on the
islands is recovered through a PSO levy in retail tariffs). Today,
non-interconnected islands operate as autonomous electrical systems and, except
for Crete, they are isolated micro-systems. In the long run it is considered
that the best option to improve the security of supply of these islands is to
connect them to the mainland grid. To this end, in 2010, RAE conducted two
studies and further feasibility studies for submarine cables to be carried out
by the TSO are expected in the near future.

5.2. 
Gas. To
diversify supply sources, Greece uses LNG imports, originally purchased under a
long-term contract between the incumbent DEPA and the Algerian Sonatrach. LNG
imports increased by about 40 % in 2010 after Greece introduced
third-party access to the Revithoussa terminal. An additional 7 % increase
in LNG volumes was recorded in 2011. Third-party access at the Revithoussa
terminal also led to further diversification of supply with Algerian LNG,
amounting to less than 65 % of all imports in 2011. There are plans to
extend the LNG terminal by 2014 in terms of both storage and regasification
capacity. Additional expansion works will enable LNG carriers to accommodate
capacity of up to 260 000 m3 LNG. Currently Greece has no gas storage
facilities (i.e. underground storage). Northern Greece has some potential for
natural gas storage, specifically in the area of South Kavala. The Greek gas transmission system has two northern
entry points (with Bulgaria and Turkey) and one southern entry point at the
Revithoussa LNG terminal. A planned new interconnector with Bulgaria (supported by EEPR) should be built without any further delay and the existing transit
pipeline transporting Russian gas from Bulgaria should allow for improved
third-party access. There is currently no gas interconnector to Italy. However, there are plans to build a sub-sea pipeline through the Ionian Sea with an
initial capacity of 10 bcm/year (TAP project). Developing the Southern Corridor
has the potential to make Greece the entry point of substantial gas volumes
flowing from the Caspian region and possibly beyond to the rest of the EU
market.

KEY INDICATORS FOR THE ENERGY MARKETS IN GREECE

Remark:
latest figures from the National Regulatory Authority show some changes for the
gas sector. In 2011, there were 5 entities bringing gas into the countries and
5 gas retailers (all considered as main entities).

Sources: Eurostat, CEER, RAE (Regulatory
Authority for Energy), EC 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.

Hungary

Key Issues ₊         Hungary should gradually abolish regulated energy prices, as recommended by the Council1, in all consumer segments, including households, while taking into account universal service obligation and effective protection of vulnerable customers. Hungary should also gradually abolish extra taxes on the energy sector. Such taxes hamper operators’ ability and willingness to invest and innovate in Hungary. ₊         The national energy regulator, HEO, should be given powers to set network tariffs autonomously and to organise its structures independently. ₊         With regard to electricity, Hungary should continue increasing cross-border network capacities1 to facilitate trade with neighbouring countries and the integration of renewable energy sources. Regional electricity market integration through market coupling should continue to be a priority. ₊         With regard to gas, Hungary should restore non-discriminative network tariffs and third-party access rules to cross-border interconnectors. Measures that have been introduced recently hinder equal access to markets and have the potential to severely distort competition. Hungary should continue its efforts to diversify gas transmission routes through cross-border interconnections (e.g. SK-HU) and implement reverse-flow arrangements on unidirectional pipelines (e.g. HU-RO). These are vital to provide the central European region with access to sources of gas in the south-east. Plans to set up a Hungarian gas exchange should be pursued.

1. 
General overview

Natural gas plays the most important role in Hungary's energy consumption, accounts for 37.8 %. Crude oil and petroleum products
come second. The power generation mix is dominated by nuclear energy (42 %),
gas-fired generation (31 %) and solid fuels (16.7 %). Renewable
energy sources (RES) play an increasingly important role in the consumption
mix. The share of RES in energy consumption[65]
rose from 5.2 % in 2005 to 8.7 % in 2010. Hungary's 2020 RES target
is 13 %. However, in the Renewable Action Plan, the government has set a
target of 14.65 %. The share of cogeneration[66] was 19.6% in 2010, showing only a slow progress since 2005
(19.1%).

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General. As Hungary 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 Hungarian National Regulatory Authority, Magyar Energia Hivatal
(HEO), in operation since 1994, employs 119 staff with an annual budget of around
EUR 12 million. HEO is relatively sizeable compared to counterparts
elsewhere in the EU, with a fairly wide portfolio of tasks. However, the
Hungarian government has recently limited HEO’s powers to set network tariffs
autonomously. Since 1 January 2012, HEO is obliged to calculate tariffs using
the methodology imposed by the Ministry. Furthermore, the government has
imposed an internal operational and functional structure on the regulator,
thereby reducing its independence and scope for autonomous decision-making
still further.

2.3. 
Unbundling. The
Hungarian electricity transmission grid is operated by MAVIR Zrt., a subsidiary
of MVM. The gas transport network is operated by the gas TSO, Földgázszállitó
Zrt, which is fully owned by MOL. Both of the TSOs have been certified as
ITOs. There are nine DSOs in gas and six in electricity.

3. 
 Wholesale markets

3.1. 
Electricity. At
generation level, the three biggest firms had a market share of 69.2 % in
2011. The power generation market is relatively concentrated, with MVM, a
state-owned generation and supply company, classified by HEO as a market
participant with significant power. As such, MVM has to auction part of its
generation portfolio to third parties. Hungary is a net importer of electricity
and an important transit country, connecting markets in the Balkans to Central Europe. Improving integration among the countries involved to develop more liquid
hubs is therefore particularly important. The trilateral Czech-Slovak-Hungarian
market coupling, being operational since 11 September 2012, is an important
step in the right direction and fits well into wider regional coupling
initiatives. It will hopefully help to reduce overall transaction costs and
allow Hungary to tap into much-needed sources of flexibility. Hungary’s power exchange, HUPX, a provider of organised access to markets, should continue
to facilitate this process. In its first year of operation, it managed to build
up an encouraging level of liquidity, with a total volume of 3.8 TWh of
spot traded power. This amounts to 9.4 % of the country’s gross inland
electricity consumption in 2011.

3.2. 
Gas. In
2011, 24 % of natural gas consumption was supplied from domestic sources,
with the rest imported, mainly from Russia (76% of all imports in 2011). E.On
Földgáz Trade is a major player on the wholesale market and is classified by
HEO as having significant market power. Since mid-2009, other licensed parties
are also active on the wholesale market.

In
2011, the import capacity of the HAG pipeline at the Hungarian-Austrian border
was expanded from 12.1 Mm3/day to 14.4 Mm3/day, enabling
imports from central-western European gas hubs to be increased. There are also
encouraging plans to set up an organised gas exchange (CEEGEX). Together with
new and planned interconnectors to neighbouring countries, the gas exchange is
expected to facilitate access to competitively-priced sources of gas, providing
an alternative to oil-indexed long-term contracts with Russia.

4. 
 Retail markets

4.1. 
Electricity. Market
concentration at retail level was high and the three biggest companies covered
77.6 % of the retail market at the end of 2011. Prices are still regulated
for certain groups of consumers, including all households and small businesses.
Consumers eligible to purchase power at regulated rates now include a large
group of public institutions, including all local administrations. The effect
of this recent measure diminishes the size of the market segment open to
effective competition. As to the roll-out of smart metering, a
preliminary cost-benefit analysis of various options for their deployment has
been carried out. However until pilot projects are finalised, there is unlikely
to be a legal framework for the roll-out in place.

4.2. 
Gas. Market
concentration at retail level is high, as the three largest companies cover
67.4 % of the retail market (as at the end of 2011). Prices for consumers
with an off-take capacity of up to 20 m3/h, including all domestic
consumers, are regulated. In addition, there are measures in place that provide
certain groups of consumers with beneficial access to interconnectors and
domestic gas production. Such arrangements may distort markets and reduce the
room for effective competition.

4.3. 
Consumers. The
retail gas market is assessed forth lowest in the EU. The percentage of
consumers reporting problems is about 80 per cent higher than the EU average
(highest incidence in the EU) and overall consumer satisfaction is third lowest
in the EU. Consumer assessment of the electricity retail market is slightly
below the EU average (16th place out of 27), with the second highest
number of complaints.[67]
A price comparison tool service is not available. Hungarian consumers can
access information concerning their rights, current legislation and means of
settling disputes by contacting HEO and the Hungarian Authority for Consumer
Protection (Nemzeti Fogyasztóvédelmi Hatóság, HACP). HACP acts as a
single contact point and has an office available in each county. Consumers can
also contact the Alternative Dispute Resolution (ADR) procedure, managed by the
local Chamber of Commerce and Industry office. Hungary recognises vulnerable
consumers on the basis of their social  situation or because of health-related
issues (two categories). Vulnerable consumers benefit from various measures,
including payment by instalments, or deferred payment, prepayment options, debt
advice, or individual assistance to help consumers understand their bills, etc.

Charts
3 and 4

Source:
Eurostat.

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

5. Infrastructure

5.1. 
Electricity. The
Hungarian system has the capacity to handle approximately 3000 MW of transit
flows with cross-border profiles to Slovakia, Ukraine, Serbia, Austria, Romania and Croatia. Hungary has relatively strong interconnections with its
neighbours, amounting to some 30 % of the domestic generation capacity
installed. The interconnectors between Szombathely (HU) — Wien Südost (AT) and
Pécs (HU) — Ernestinovo (HR) were implemented in 2010. Four new interconnection
projects between Hungary and Slovakia are under discussion. These projects are
important to provide capacity for increasing power flows from the north of Europe to the south and to further facilitate trade.

5.2. 
Gas. The
interconnectors with Croatia and Romania were finalised in 2010 and 2011 and
are now operational. The installation of reverse flow capabilities in the
Hungarian transmission system is ongoing. The Slovak-Hungarian interconnector
is in the planning phase. The Hungarian gas exchange (CEEGEX) has
already obtained a licence and is scheduled to start operation on 1 January
2013.

KEY
INDICATORS ON THE ENERGY MARKETS IN HUNGARY IN 2010

Remark:
2011 figures provided by the National Regulatory Authority show some
significant changes in both markets. In electricity there were 45 companies
representing at least 95 % of net power generation and the market share of
the largest one was 44 %. The number of main electricity retailers
increased to 6. In gas, the number of entities bringing gas into the country
declined to 14, with 7 main entities; the market share of the largest one was
60.5 %. The number of main gas retailers shrank to 6, increasing the
concentration level in the retail market (HHI of 2270).

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) 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 import).

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

(6) small businesses with an interconnection of
less than 3*63 A in total for all off-take points and for public institutions.

(7) small customers with an off-take capacity of
less than 20 m3/hour.

Ireland

Key Issues ₊   With regard to electricity, Ireland should build on the development of the Single Electricity Market (SEM) with Northern Ireland by fully participating in the wider internal market. The completion of the new interconnector with Wales will help it to do so. It should continue developing networks and systems to accommodate a large proportion of wind generation, which is particularly difficult on a small system like that of Ireland. ₊   With regard to gas, Ireland should address concerns about gas security, given that the country relies heavily on it.  Blanket retail price regulation imposed on the incumbent operator should be phased out, while ensuring effective protection of vulnerable customers.

1. General
overview

Crude
oil and petroleum products represented more than half of the energy mix in
2010, but natural gas was the leading fuel in the electricity mix. Only in the Netherlands did natural gas account for an even greater share in gross electricity generation than
in Ireland. Wind was the greatest source of renewable energy, accounting for
more than two thirds of green electricity, while the rest was almost entirely
hydro power. Ireland’s goal is to have 16 % of renewable energy by 2020.[68] This share
grew from 3 % in 2006 to 5.5 % in 2010. The share of cogeneration[69] was 6.7% in
2010; reflecting a significant increase from 2.4% 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, Ireland 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. In addition, two
infringement procedures are still open in relation to the Second Package. They
relate to the following issues: the lack of congestion management and
transparency concerning access to the network for cross-border exchanges in
electricity, and the lack of transparency of conditions for access to the
natural gas transmission network.[70]

2.2. 
National Energy Regulator.
The Irish National Regulatory Authority, the Commission for Energy Regulation
(CER), in operation since 1999, employed a staff of 66 in 2010, with a budget
of EUR 10 million.

2.3. 
Unbundling. The
Irish electricity incumbent, the state-owned ESB, owns the electricity
transmission system.  The system is operated by EirGrid, the system operator.
ESB has applied for these arrangements to  be certified as guaranteeing
effective unbundling in line with Article 9(9) of the Electricity Directive,
however, neither the Irish regulator CER nor the Commission have made a
decision on this application.  EirGrid plc also owns the Northern-Ireland
system operator SONI, and the Northern Ireland transmission system is owned by
ESB subsidiary NIE.  ESB also owns the distribution system, operated by ESB
Networks Ltd. The Irish gas transmission and distribution networks are owned by
the Irish government through Bord Gáis Energy (BGE). They are operated
by Gaslink. Ireland plans to adopt the ITO unbundling model in gas, but the
Government has also decided to sell supply interests, thereby moving to full
ownership unbundling, which is expected to be implemented early in 2014.

3. Wholesale
markets

3.1. 
Electricity. The
wholesale electricity market for Ireland is the SEM. It is jointly regulated by
the CER and its counterpart in Belfast, the Northern Ireland Authority for
Utility Regulation (NIAUR). The major supplier in the Irish market is the ESB.
It owns roughly 41 % of dispatchable capacity on the island.[71] Endesa is the
second largest supplier (15.5 %). It is currently building a new CCGT.
This will increase the percentage of its capacity and reduce that of the ESB’s.
The regulators require the ESB to offer a certain number of directed contracts
to reduce the level of market concentration.

With
regard to market integration, day-ahead market coupling between the SEM
and the wholesale electricity market in Great Britain is being considered. The
SEM pool is the common and mandatory wholesale electricity spot market. The
average wholesale day-ahead price in Ireland in 2011 for baseload power
was EUR 62.0/MWh[72]
(14.8 % higher than in 2010) and 34 TWh were traded (compared to 35 TWh for
the SEM area).

3.2. 
Gas. Irish gas imports (exclusively coming from the UK) amounted to 5.1 bcm in 2010, accounting for 93% of national consumption. Most of this
is used to generate electricity. Indigenous production accounts for around 7 %
of electricity generation, while the rest is imported from the UK through two interconnectors. As a result, wholesale prices are closely linked to the United Kingdom’s NBP hub. BGE dominates the Irish wholesale market. The CER traditionally
regulated BGE’s tariffs, but this changed in October 2010 for large customers,
who now have access to an unregulated tariff. There are some new entrants in
the different segments of the wholesale market focusing on large customers.
They tend to use BGE’s regulated tariff as a benchmark.

4. Retail
markets

4.1. 
Electricity. There
are eight suppliers in the retail electricity market. The state-owned ESB
(Electric Ireland as of 2012) supplies most domestic customers. By the end of
2011, it accounted for 57 % of domestic electricity consumption, BGE for
23 % and Airtricity for 20 %. In 2010, the annual switching rate
in the whole retail market was very high. At over 28 %, it was one of the
highest switching rates ever seen in Europe, with 40 % of domestic
customers having switched between 2009 and April 2011.
The annual switching rate was 15 % in 2011. End‑user prices
are not regulated. Power prices for industrial customers
were more volatile than household prices. The industrial price decreased after
2008. This appears to be linked to the economic slowdown. Network costs accounted for 29 % of the power price
for Irish industrial customers (before taxes) in the second half of 2010, while
energy and supply costs accounted for 71 %. Based on a positive
cost-benefit analysis, the CER has developed national roll-out scenarios for
electricity and gas smart meters. In June 2012, it published its decision on
proceeding to the next phase of the smart metering project.

4.2. 
Gas. Historically, BGE has dominated the Irish retail market.
Traditionally, it supplied energy to 97 % of residential customers.
However, in May 2010 a new supplier, Airtricity, entered the market. There was
a large increase in the number of customers who switched supplier as a result.
In April 2011, Electric Ireland also entered the gas market. By the end of
2011, BGE had 73 % (~78 % GWhs) of gas domestic customers, Airtricity
had 19 % (17.4 % GWhs), Flogas had 4 % and Electric Ireland had
4 %. Tariffs for BGE customers are still regulated. End‑user prices
are not regulated for those who consume between 5.5 GWh and 264 GWh. Gas
prices for final consumers dropped after 2008 for both households and
industry, but the price for households took some time to respond. In general,
as Ireland sources gas from the UK, the Irish gas commodity price is determined
by changes in the UK price. Domestic taxation also affected the price.

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. Irish
consumers score the performance of their retail electricity and gas markets
above the EU average (6th place out of 27 and 7th place
out of 23, respectively). In both markets, switching rates and ease of
switching are the second highest of all EU countries.[73] The CER has implemented an
accreditation framework for independently run private online price
comparison services. It acts as a single contact point for consumers
by giving them information on electricity and gas. It also acts as a dispute
resolution body. Irish legislation introduced the concept of vulnerable
consumers in 2004 for electricity and in 2005 for gas. Recently transposed
legislation ensures that energy is supplied to these two categories of
household: households that are critically dependent on electrically powered
equipment, which includes life-protecting devices and medical equipment, and
households that are particularly vulnerable if disconnected during the winter
on account of advanced age or poor health.

5. 
Infrastructure

5.1. 
Electricity. The
East-West Interconnector between Ireland and the UK, was inaugurated on 20
September 2012 and doubles the interconnection capacity between the two
systems. The project for establishing a second high-capacity connection between
 Northern Ireland and Ireland is at an advanced planning stage. Alongside these
projects, work on the transmission grid in Ireland aims to improve the grid
configuration in order to integrate generation from renewable sources, mainly
from wind parks. All of this greatly helps to improve the security of supply to
  Ireland, while making the grid flexible and reliable.

5.2. 
Gas. There
are no plans to develop gas connections with the UK or the continent in the
near future. However, the Corrib gas field is expected to commence
production early in 2015. Work on the first LNG terminal in Shannon is
progressing slowly and the terminal could be operational in 2017. These two
projects can play an important role in improving the security of supply and
fostering competition.

KEY
INDICATORS ON THE ENERGY MARKETS IN IRELAND IN 2010

Sources: Eurostat, CEER, Commission for Energy
Regulation, EC calculations.

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 the national net electricity generation.

(2) Retailers are considered ‘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 company 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 the natural gas production (indigenous production
or imported gas).

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

Italy

Key Issues ₊   With regard to electricity, there is still a high concentration in some areas of the country (mainly the two main islands Sicily and Sardinia), and internal congestion leads to suboptimal use of generation capacity. The transmission grid capacity should be upgraded to fully exploit newly installed efficient thermal and RES generation capacity. The development of the electricity network is expected not only to reduce congestion on the domestic grid, but enhance interconnection capacity with neighbouring markets, as recommended by the Council1, improving wholesale price alignment with adjacent countries. ₊   With regard to gas, competition remains limited, and there is a high share of imported gas. Import capacity needs to be further expanded to enhance long-term security of supply. New capacity is also needed to develop a liquid spot gas market, which today remains small. The high share of imported gas in electricity generation implies that the security of electricity supply relies on secure gas supply. Italy should therefore continue to actively pursue further diversification of supply sources and routes, including by implementing the Southern Gas Corridor. ₊   For both gas and electricity infrastructure, permitting procedures need to be streamlined.

1. General
overview

Crude
oil and petroleum products dominate the energy mix, followed by natural gas. In
the electricity mix however, natural gas is the most important fuel, providing
more than half of the electricity produced. Renewables are second, two thirds
of which originate from hydro power. Italy’s 2020 indicator[74] improved from
5.6 % in 2006 to 10.1 % in 2010, and it aims to reach 17 %.
Cogeneration[75]
assured 11.5% of total electricity generation in 2010, showing an increase
from  9% in 2005.

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General. As Italy had notified full transposition of the Third Package Directives by the end of
September 2011, no infringement proceedings for non-transposition have been
opened. One infringement procedure is still open on the Second Energy Package
in relation to the lack of congestion management (cross-border intraday) and
transparency concerning access to the network for cross-border exchanges in
electricity.

2.2. 
National Energy Regulator.
The Italian National Energy Regulatory Authority, Autorità per l’Energia
Elettrica e il Gas (AEEG), in operation since 1997, employed 168 staff in
2011 with an annual budget of EUR 39 million. To cover its budget, AEEG
collects levies from energy market stakeholders. The regulator is independent
but its budgetary autonomy has been reduced by the parliament in the last
couple of years. Law No 214 of December 2011 also gave AEEG responsibility for
regulating, controlling and monitoring water services.

2.3. 
Unbundling. The
electricity TSO is TERNA, which had its ownership unbundled in 2004. TERNA owns
almost the entire national electricity transmission grid but there are also
other smaller operators which own some network elements (a few lines and
substations). Snam Rete Gas TSO is a subsidiary of SNAM S.p.A. which in 2011
was owned 52.5 % by ENI, 5 % by the government and the rest was
privately owned. The second operator was the Edison Group. Italy had initially chosen the ITO unbundling model for gas, but in May 2012 the new
government issued a decree introducing full ownership unbundling for the gas
sector too. In 2011, there were 239 DSOs in gas (430 in 2005) among which ENI
was the main one (23.1 % in terms of distributed volume). In electricity,
the number of DSOs is much lower (145). 10 serve more than 100 000
customers and are therefore legally unbundled. ENEL Distribuzione was the
leading distributor with 86 % of the volume distributed.

3. Wholesale
markets

3.1. 
Electricity. In
terms of generation, the four largest producers together controlled less
than 50 % of the Italian market. This development is due to a further
reduction of ENEL’s market share in electricity production, which dropped from
29.8 % in 2009 to 26 % in 2011. ENEL’s competitors were ENI (9.4 %),
 Edison (8.5 %), E.On (5.1 %) and Edipower (4.8 %). ENEL, E.On’s
and Edipower’s market shares decreased to the advantage of other medium and
smaller producers. Market integration with neighbouring markets is
progressing, but Italy’s interconnectors remain highly utilised. With more than
12 000 MW of interconnection capacity (8 000 MW of Net Transfer
Capacity), Italy is one of the best interconnected systems in Europe, but the
interconnectors are not always used as efficiently as they could be (e.g. there
is no intraday capacity allocation) and internal congestion restricts their
potential use. Since 1 January 2011, integration of the Slovenian and Italian
markets is based on market coupling for daily capacity allocation. Otherwise
yearly, monthly and daily capacity is allocated through explicit auctions (from
June 2012 intraday explicit auctions are in place). In April 2011, TERNA joined
— together with other regional TSOs from the central-south region — the
Capacity Allocation Service Company (CASC), the company organised by the TSOs
of the central-west region to operate as a single auction platform for the
region.

Wholesale
prices in 2011 were on average EUR 72.2 /MWh
for Italian day-ahead baseload power (an increase of 13.2 % compared to
2010).[76]
The Italian wholesale price is considerably higher than in other EU countries.
Internally, congestion is managed through market splitting into several zones.
Externally, a better management, and possibly expansion, of interconnections
with other countries could also help align wholesale prices. An important
pricing factor for electricity is the wholesale price for gas, which is also
above the European average.

With
regard to liquidity, 180 TWh of day-ahead baseload power were traded in
2011 on the Italian power exchange IPEX (55 % of gross inland
consumption).

3.2. 
Gas. In
2011, Italy imported 70.3 bcm of natural gas, corresponding to 90 % of its
gross inland consumption of natural gas in 2010. The three main importer countries
were Algeria (37 %), Russia (20 %) and Libya (12.5 %), and 12.8 %
of imported gas was LNG. Domestic production of natural gas rose slightly in
the last year from 8 to 8.4 bcm. In 2011 ENI, Edison and Enel covered 74.3 %
of the total gas supplied (in 2009 their share was 79.3 %). Wholesale
prices remain higher in Italy than in any other European country with a gas
trading hub. Gas prices remain mainly linked to take-or-pay contracts. The
volume of spot imports has slightly decreased (from 10.6 % in 2010 to 9.5 %
in 2011).

The
day-ahead wholesale price of natural gas on the Italian hub PSV reached
an average of EUR 28.2 /MWh in 2011 (20.5 % higher than in
2010), higher than the price on the other hubs. It appears that the distance
from the larger hubs where most European wholesale trading takes place and
limited access to gas traded on spot markets contribute to this situation. In
terms of traded volume and liquidity, PSV is the smallest gas hub in the
EU. In terms of volume, 65.5 % of the gas consumed in Italy in 2011 was traded on the hub.[77]
The virtual trading point PSV moved towards a real gas exchange in May 2010
when a new trading platform, P-Gas, was set up and importers and producers
became obliged to place their gas there. A new balancing mechanism was launched
in December 2011. The results have so far showed a promising trend towards
alignment with the spot prices of the other hubs.

4. Retail
markets

4.1. 
Electricity. Enel
remained the strongest player (36.8 %), followed by Edison (8.2 %)
and Acea/Electrabel (4.6 %). Their joint market share dropped to 49.6 %
(2011) from 54 % (2010). Consumers have been able to choose their own
supplier since January 2007. Consumers that do not choose a supplier remain
with a default supplier, the local DSO, which provides electricity according to
a ‘standard offer’. In this case, the local DSOs buy electricity from the
Single Buyer at wholesale market price. Today the majority (77 %) of
households and SMEs are still served on the base of this ‘standard offer’.
Other consumers (i.e. other than households and SMEs) are obliged to find a
supplier, but if they cannot find a suitable offer, electricity is supplied by
a Last Resort Supplier, selected through an open auction.

The
switching rate of suppliers was 7 % in 2011 (11.7
for non-households and 5.8 % for households) up from 5.9 % in 2010. In 2011, the share of network costs within the household
prices (without taxes) was 31 %, while energy and supply costs made up 69 %.
For industrial electricity prices, the proportions were 19 % network costs
and 81% energy and supply.

At
the end of 2006, AEEG issued a regulatory provision defining minimum technical
requirements and timing for the mandatory roll-out of smart meters: 95 %
of the entire low voltage customer-base
was to be equipped with smart meters by the end of 2011. The roll-out is highly
focused on reducing non-technical losses, rather than on making energy savings.

4.2. 
Gas. The
level of concentration of the total market has fallen: the share of three
largest companies was 53.1 % in 2011 (down from 57.4 % in 2009) of
which ENI 29.6 %, Edison 13.5 % and ENEL 10 %. Consumers have
been able to choose their own supplier since January 2003. Around 10.4 %
of the residential sector is now in the free market. In 2011, 5.3 % of all
final customers switched suppliers, mainly large consumers. The share of the
tax component was low for industrial consumers, but high for household
customers. The correlation analysis shows that there is a rather strong
correlation between the wholesale and retail gas prices. Provisions for rolling
out smart gas meters were introduced by Regulatory Order ARG/gas 155/08 and
recently updated by Regulatory Order 28/2012/R/gas, which prescribes a 60 %
roll-out to residential consumers by 2018.

4.3. 
Consumers. Italian
consumer assessment of both retail electricity and gas markets is below the EU
average (17th place out of 27 and 16th place out of 23, respectively. In both
markets, trust in providers is the fourth lowest in the EU. In 2009, AEEG
introduced the on-line price comparability tool (Il Trova-Offerte)
for electricity and in 2010 for gas prices. Since 2009, consumers have also
been able to send requests for information and complaints on electricity and
gas to a single contact point (Sportello per il consumatore di
Energia). The NRA has a role in guaranteeing an efficient handling of the Alternative
Dispute Resolution procedure between customers and energy suppliers or the
DSO. Since 2007, social laws classify vulnerable customers into three
household categories including (i) income thresholds, (ii) offspring and (iii)
life support dependence. These categories of consumers can have a rebate on
their bills.

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. For Italy the breakdown of electricity prices is not available for 2008 and 2009. 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).

5. 
Infrastructure

Although
the permitting and authorisation processes for new energy infrastructure have
been streamlined in recent years, there is still the need to enhance
coordination and address public concerns.

5.1. 
Electricity. In
response to the power deficits of 2003 and 2004, a strong increase in installed
capacity (including in thermal and RES generation capacity) led to a generation
surplus of as much as 12.6 GW. The increased generation capacity led to
constraints in the transmission network, which still suffers from congestion.
In particular, the south is poorly interconnected to central-northern Italy. At the end of 2009, the new 1 000 MW SA.PE.I Cable, connecting Sardinia to the mainland, was inaugurated. The cable is expected to reduce congestion
between Sardinia and the Italian peninsula and improve competition on the Sardinia market. A new 2 GW sub-sea transmission cable to better connect Sicily to the Italian
peninsula is also under construction.

5.2. 
Gas. Natural gas is
imported via five pipelines and two LNG facilities, with the total import
capacity around 120 Bcm. In the past, most of the import pipelines were owned
and operated by ENI, but following a competition case analysing the potential
abuse of its dominant position, ENI committed to divest its shares in the TAG
pipeline, which imports gas from Russia. These were sold to Italian state
lender Cassa Depositi e Prestiti, and shares in Transitgas and TENP, which
import gas from north-west Europe were sold to Belgian gas infrastructure
company Fluxys Europe. More LNG terminals are planned and are at different
stages of the authorisation process. A further diversification of supply
sources could be achieved through new pipeline projects such as Galsi and TAP.
Major steps have been taken regarding gas storage, with the Bordolano storage
starting to inject cushion gas in 2010 and a number or other projects getting
closer to completing the authorisation process. Moreover, ENI is obliged by law
to build an additional 4 Bcm of storage and offer it to the market.

KEY
INDICATORS ON THE ENERGY MARKETS IN ITALY IN 2010-2011

Remark:
latest figures from the National Regulatory Authority show an increase in
switching rates. In 2011, switching rates were 7 % for electricity and 5.3 %
for gas.

Sources: Eurostat, CEER, National Regulatory
Authority, EC 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. The measure relates to the entire country.

(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.

Latvia

1. General
overview

The
country’s energy-consumption mix has the highest renewable energy (RES) share
(34.6 %) in the whole EU-27. The country’s RES target for 2020 is 40 %.[78] Natural gas
accounted for 32.2 % of gross inland energy consumption while the share of
crude oil and petroleum products (28.5 %) was also significant.
Nuclear-based electricity generation does not exist at all. RES had a dominant
share in the country’s electricity generation mix (54.9 %); followed by
natural gas (45.1 %). Cogeneration[79]
provided for 45% of total electricity generation in 2010, which was a high
share compared to other EU countries and was up from 30.7% measured in 2005.

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General. As Latvia 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 Latvian national regulator, Sabiedrisko pakalpojumu regulēšanas komisija,
the Public Utilities Commission — PUC, is a multi-sector regulator. In
operation since 2001, it employed 110 staff (of whom 20 were responsible for
energy) in 2010 and had a budget of around EUR 3 million.

2.3. 
Unbundling. For
electricity, the TSO is JSC Augstsprieguma tikls. Legally unbundled
since 2005, it became a separate company in 2012 and operates as ISO. The main
DSO is JSC Sadales tikli; there are 10 smaller local
electricity-distribution companies. For gas, the TSO is Latvijas Gaze;
E.ON and Gazprom own the majority of its shares. Latvia has an explicit
derogation from the Gas Directive exempting it from unbundling rules (Article
49). The certification of these gas TSOs has not taken place yet but the process
for the electricity TSO has started.

3. 
Wholesale markets

3.1. 
Electricity. The
dominant utility, Latvenergo, produced around 90 % of all power in
2010 and this was the only company whose market share exceeded 5 %. At the
wholesale-market level, the concentration was also very high as there were only
three companies active in that market (though 32 companies possessed licences
to trade). Market integration through market coupling has been implemented
since January 2011 on the EE-LV interconnection, which is regularly congested.
Moreover, the method implemented did not work properly, due to loop flows with Russia. Latvia is assessing the technical feasibility of implementing flow-based market
coupling. Latvia plans to join Nord Pool Spot soon.

As
there is no power exchange yet in Latvia, wholesale spot prices are not
provided. About three quarters of the total power consumption was covered by
domestic generation and the remainder was imported. In 2010, 67.2 % of
electricity was sold at the regulated tariff while the remaining 32.8 %
was sold at freely negotiated prices (through bilateral contracts).

3.2. 
Gas. Annual
gas consumption was 1.6 bcm in 2011. Currently, 100 % of all natural gas
consumed in the country is imported from the Russian Federation. In 2011 the
average Latvian import price was EUR 25.8 /MWh.

4. 
Retail markets

4.1. 
Electricity. In
2010, there were only two nation-wide power-supply utilities, one with a market
share of over 95 %. Switching of suppliers is almost non-existent,
in 2011 0.01% changed the supplier. In 2011 the share of energy and supply costs in household prices
(without taxes) amounted to 49%
(51% being network costs) which was one of the lowest commodity component
levels in the EU. In the case of industrial consumers the share of energy and
supply costs was higher (61%). There are no legal provisions in place
regarding smart metering. A cost-benefit analysis on the roll-out of
smart meters has not been conducted.

4.2. 
Gas. In
2011, all customers received gas from the vertically integrated joint stock
company Latvijas Gāze, so there was no switching of suppliers. Latvia’s isolation not only necessitated a derogation pursuant to the Gas Directive but
also means that there is still not a properly functioning competitive
environment in the gas sector. During 2011, prices were stable for all
consumers, apart from a slight increase during second half of 2011, but in 2012
they picked up again. Oil indexation can be tracked in the price trends of both
industrial and household gas tariffs. An additional aggravating factor was the
introduction of excise tax on gas in the middle of 2011. In the case of
household prices, changes in VAT rates also contributed to the increase in
final gas prices.

4.3. 
Consumers. Latvian
consumers' assessment of the performance of their retail electricity market is
below the EU average (20th place out of 27), with particularly poor assessment
of the ease of switching (second lowest in the EU) and choice (third lowest).
Retail gas market is ranked above the EU average (8th place out of 23) but the
switching rate and ease of switching are the second lowest in the EU. According
to the Law on Regulators of Public Utilities, the National Regulatory Authority
deals with customer complaints. Consumers can also approach the Consumer
Rights Protection Centre for out-of-court dispute settlement. There is no
definition of vulnerable consumers in Latvia.

Charts
3 and 4

Source:
Eurostat.

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

5. 
Infrastructure

5.1. 
Electricity. There
are currently no bottlenecks between Latvia and Lithuania. The interconnector
between Latvia and Estonia, however, is regularly congested. For historical
reasons, the Latvian electricity system is heavily interconnected with the
networks of Belarus, Russia, Estonia and Lithuania. In order to coordinate the
operation of the system and to ensure its stability, the five states are
subject to the so-called BRELL ring agreement. The Commission is currently
negotiating an intergovernmental agreement, on behalf of the EU, with Russia and Belarus on electricity-network operation in the Baltic States. In the medium-term, Latvia and the other Baltic Member States aim at synchronisation with the EU electricity
system and this will require significant investment in electricity interconnections.

5.2. 
Gas. The Baltic States’ gas network is isolated from the rest of the EU. To end this isolation, work
is taking place in the context of the BEMIP initiative; the planned LNG
terminal is one of the key projects. Latvia also has the only functioning gas-storage facility in the Baltic States, the Inčukalns
Underground Gas Storage Facility, and is involved in the LV/LT reverse-flow
project. A risk-assessment exercise concluded by the three Baltic TSOs has
identified some urgent infrastructure developments that should not be delayed.

KEY INDICATORS ON THE ENERGY
MARKETS IN LATVIA 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 import).

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

Lithuania

Key Issues ₊    As recommended by the Council, Lithuania should promote competition and improve connectivity with EU energy networks. ₊   With regard to electricity, there is only limited competition in Lithuania and the market is concentrated. Lithuania has joined Nord Pool Spot, which might help to spur competition at the wholesale level, but Lithuania should still continue work in BEMIP towards the creation of a Baltic regional electricity market. While taking into account universal service obligation and effective protection of vulnerable customers, Lithuania should continue phasing out price regulation, as planned. It is essential to continue cooperation with the European Commission in negotiations with Russia and Belarus on electricity network operation in the Baltic States. Lithuania should complete the electricity interconnection with Sweden and develop cross-border interconnection with Poland, which could help reduce market concentration at wholesale and retail level. ₊   With regard to gas, Lithuania relies on only one supply source. As a result, Lithuania should take the necessary measures to end isolation of its gas network from the EU, in particular by working in the context of the BEMIP initiative and diversification of supply with a regional LNG terminal in the Baltic States (which is planned for 2014) and interconnection with Poland. ₊   Since the adoption of national legislation at the beginning of 2012, Lithuania has made some effort to strengthen its regulator. Further efforts are required to ensure independent, economic-based regulation.

1. General
overview

In 2010, oil and natural gas had almost the same share in
the energy mix. Nuclear energy was still very important in 2009, but at the end
of the year the second reactor of Ignalina nuclear power plant (NPP) was shut
down as foreseen in Protocol n°4 on the Ignalina nuclear power plant in Lithuania attached to the Accession Treaty. With the decommissioning of the Ignalina NPP,
which accounted for 80 % of national electricity production, Lithuania has become the most dependent EU Member State on electricity supply from abroad. Currently up to 80 % of Lithuanian primary energy mix is provided by import. This
phasing out is planned to be offset mainly through an increased share of
natural gas, but also through renewables (RES). In the electricity mix, the
share of RES amounted to 29 % in 2010 (from 9% in 2009). Lithuania has set a target of 23 % of RES in gross final energy consumption by 2020.
In 2010 this share was 19.7 %. About 35% of the total electricity
generation in 2010 was provided by cogeneration[80], while in
2005 this share was 15.5%, putting the country in a good position compared to
other EU countries. In the mid-term Lithuania plans to build a new nuclear
power plant at Visaginas, although a recent referendum shows growing popular
resistance to nuclear power.

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General. Following
the opening of infringement proceedings in September 2011 for non-
transposition, Lithuania has notified full transposition of the Electricity Directive
and partial transposition of the Gas Directive of the Third Package. As
regards the Electricity Directive, 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. Lithuania, like Latvia, Estonia and Finland, has no interconnections with the EU gas network. It
only has an interconnection to Latvia. Unlike the other three Member States, Lithuania did not request an explicit derogation pursuant to Article 49 of the Gas Directive during
the Third Package negotiations.

2.2. 
National Energy Regulator. The
Lithuanian regulator, the National Control Commission for Prices and Energy
(NCC), in operation since 1997, employed 46 staff (of which only 15 working on
the regulation of electricity and gas) with an annual budget of almost EUR 0.92
million in 2011. These are low figures compared to those of other Member
States, even in relative terms.

2.3. 
Unbundling. In
electricity the OU model was chosen for unbundling the state-owned TSO (Litgrid AB). There is one major DSO (AB LESTO) and five smaller DSOs in electricity. Both
the TSO and the DSO were given additional time to complete their unbundling
(until 31 October 2012, and 30 June 2012 respectively). The gas TSO is Lietuvos
Dujos of which E.On, Gazprom and the Lithuanian Government are the main
shareholders. Lietuvos Dujos submitted its unbundling plan to the NCC on
31 May 2012. In parallel, negotiations between Lithuania, Gazprom and E.ON are
underway concerning ownership unbundling. In the gas distribution sector Lietuvos
Dujos AB has a market share of 99 %. Five other companies were
entitled to engage in distribution activities, but they provided distribution
services only to a few regions and their total distribution market share was 1 %.

3. Wholesale
markets

3.1. 
Electricity. The
closure of Ignalina NPP in 2009 removed a monopoly power supplier and created
room for new suppliers on the market. However, the Lithuanian electricity
market is still concentrated. In 2010, INTER RAO Lietuva UAB and Lietuvos
Energija AB each had a 40 % share of the wholesale electricity market
and 18 other market players had a combined market share of 20 %. In 2011,
INTER RAO Lietuva UAB had a share in energy exchange of 19.3 % (sales
share) and 44 % (purchase share). Lietuvos energija had a share of
45.1 % and 17.4 % respectively. Nord Pool Spot started in Lithuania in June 2012. Since then, electricity trading is based on the Nord Pool Spot
model, taking place on the Lithuanian electricity market and through bilateral
exchanges between producers, importers and suppliers. In 2011 the average
day-ahead wholesale price for baseload power was EUR 45.2 /MWh
(a decrease of 2.6 % compared to 2010).[81]
In terms of liquidity concerned, 8 TWh were traded on the exchange
in 2011 (75 % of gross electricity consumption).

3.2. 
Gas. Lithuania
does not have its own natural gas resources. All gas is imported from a single
source -  Russia (via a single pipeline from Belarus). In 2011 3.4 bcm of gas
were imported. Correspondingly, competition has not developed in the wholesale
sector of the natural gas market. All the natural gas is purchased from one
company. Incumbent companies AB ‘Lietuvos dujos’ (the largest player)
and UAB ‘Haupas’ purchase from Gazprom directly (as well as AB ‘Achema’
and UAB ‘Kauno termofikacijos elektrinė‘). UAB ‘Dujotekana’
purchases from Gazprom via Gas Stream AG LT. Nevertheless, a gas exchange was
launched on 1 March 2012. Wholesale trading of natural gas
administered by exchange operator Baltpool takes place on the commodities
exchange by trading natural gas or transferring the right to acquisition of
natural gas. As trade on the natural gas exchange is local for the time being
and just getting off the ground, no reference wholesale price can be
given. Estimates of long-term prices for Russian gas result in an annual
average of EUR 33.7 /MWh for 2011 (an increase of 26.4 % in
relation to 2010).

4. Retail
markets

4.1. 
Electricity. In
2010, Rytu Skirstomieji Tinklai AB and VST AB together supplied 65 % of
the market, with 59 independent suppliers having a combined market share of 35 %
(the number of independent suppliers had doubled in relation to 2009). At the
end of 2010, Rytų Skirstomieji Tinklai AB and VST AB merged into
one single operator, AB LESTO; and in 2011 LESTO supplied 53.1 % of the
market. Supplier switching among non-household consumers has been rising
gradually since 2010. End-user price regulation still exists for household
consumers, but will be fully removed for industrial consumers in 2013. By a
decree of 2009 the Lithuanian Government instituted a plan for the gradual
phasing out by January 2015 of regulated end-user tariffs for electricity.
Regulated end-user tariffs will continue to apply to vulnerable customers only.
Power prices for households and industrial consumers have been
increasing in recent years, mostly due to the net commodity price in 2010, but
also to public interest services’ supply in 2011-2012. The former is related to
the closure of the Ignalina power plant and the switch to other sources of electricity.
  Lithuania also increased the rate of VAT from 19 % to 21 % in
September 2009. In 2011 and in the first semester of
2012 the share of network costs in the power price for households (without
taxes) was 55 % while the share of energy and supply costs was 45 %.
In the case of industrial electricity prices, these proportions were 40 %
and 60 % respectively. A cost-benefit analysis addressing smart
meters is currently being carried out.

4.2. 
 Gas. The functioning of the natural gas
retail market is determined by the situation on the wholesale market.
Theoretically, the market is 100 % liberalised. In practice, as there is
only one external gas supplier, no switching occurred in 2011. As in previous
years, in 2011 customers were supplied with natural gas by the two main
suppliers, Lietuvos Dujos AB and Dujotekana UAB. Gas quotas are
allocated to those undertakings by a single external supplier (Gazprom RAB).
There is therefore no competition between the main suppliers, which means that
there is no real switching option. There are another five gas supply companies,
whose combined market share is as low as 1.2 % of the retail market. Prices
for final consumers followed a similar trajectory to electricity prices. The
increase in the price of the natural gas and in VAT contributed to higher
retail prices. A comparison of the development of estimated long-term gas
import prices and retail prices highlights some correlation for
industrial consumers. In 2009 there was a sharp drop in industrial retail
prices, followed by a gradual increase in subsequent years. This corresponded
closely to the movement of the import price of natural gas.

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. The
NCC, the State Energy Inspectorate and the State Consumer Rights Protection
Authority investigate individual consumer complaints depending on the nature of
the complaint. Lithuanian consumers rate the performance of their retail gas
market 5th highest in the EU, with the highest score on comparability of all EU
countries. The assessment of the retail electricity market is below the EU
average (18th place out of 27), with the third highest percentage of consumers
reporting a problem.  Disputes are settled out of court by both authorities.
The regulator established a single point of contact in March, 2012. As regards
the definition of vulnerable consumers and measures to protect them, Lithuanian
law provides that the non-interruptible supply of natural gas is guaranteed as
a matter of priority to those groups of vulnerable consumers — household
customers and non-household customers — which consume up to 20 thousand cubic
metres of gas per year.

5. 
Infrastructure

5.1. 
Electricity. Lithuania is not directly connected to the European grid and therefore should continue
working in BEMIP towards the creation of a Baltic regional electricity market.
Plans are in place to build the 700 MW Nordbalt interconnector to Sweden by 2015 as well as an interconnection to Poland by 2016. In 2011, NCC and TSO agreed on
financing terms for NordBalt. The Baltic States operate within the BRELL
synchronous system. Electricity flows changed after the shut-down of Ignalina
NPP, resulting in congestion in Latvia-Estonia interconnections, especially
during the summer.

5.2. 
Gas. The
grid is connected with the Belarusian, Latvian and Russian Federation (Kaliningrad enclave) gas systems. Work should continue in BEMIP to end the isolation of Lithuania’s gas network from the EU. Investments in a Lithuanian-Polish
interconnector and enhancement of the Latvian-Lithuanian interconnection have
been submitted as potential projects of common interest in gas infrastructure.
In June 2012 the Lithuanian Parliament adopted the law on the LNG Terminal,
thus ensuring the required legal framework for the construction of an LNG
Terminal.

KEY
INDICATORS ON THE ENERGY MARKETS IN LITHUANIA IN 2010

Remark:
the latest figures from the National Regulatory Authority show significant
changes for the electricity sector. In 2011 there were 53 companies
representing at least 95 % of net power generation and 15 electricity
retailers (including 4 main electricity retailers). The market share of the
largest power generation company was 25 %, and the switching rate
increased to 14.8 %.

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 adding up 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.

Luxembourg

Key Issues ₊   With regard to electricity, the share of renewable energy sources is low due to limited national capabilities. Increasing imports of electricity from renewable sources from neighbouring countries would require additional interconnections. ₊   With regard to gas, Luxembourg is suffering from limited availability of firm entry capacity, especially on its German and Belgian connections. A better congestion management mechanism could help to address this situation. Negotiations with neighbours to strengthen the interconnections (for gas and electricity) should be intensified and could lead to positive results.

1. General
overview

In
2010, the energy mix was dominated by crude oil and petroleum products.
Together with natural gas, these sources represented close to 90 % of the
mix. The most important renewable sources were biomass and waste (88 %)
followed by hydro power (7 %). However, hydro power provided one third of
gross electricity production. As far as the 2020 goal is concerned, the
national overall target is an 11 % share of energy from renewables .[82]
In 2006 this share was 1.4 % and in 2010 it was 2.8 %. Cogeneration[83] assured 9.6%
of total electricity generation in 2010; similarly to previous five-year
period, when its share ranged between 9.9% and 11.9%.

Charts
1 and 2

Source: Eurostat

2. 
Regulatory framework

2.1. 
General.
Following the opening of infringement proceedings in September 2011 for non-
transposition, Luxembourg 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.
In 2010, the Luxembourgish national regulatory authority, the Institut
Luxembourgeois de Régulation (ILR),
employed 41 staff and had an annual budget of almost EUR 7 million. It has been
in operation since 1997 and is also in charge of regulating the telecoms and
postal sectors.

2.3. 
Unbundling. Luxembourg has been granted a derogation from the unbundling provisions on the basis of
Article 44(2) of the Electricity Directive and Article 49(6) of the Gas
Directive. Creos Luxembourg SA, which manages transmission and
distribution of electricity and natural gas, is obliged to only legally
separate its activities.

3. Wholesale
markets

3.1. 
Electricity. At
the generation level, the three largest producers (GdF Suez, Enovos,
Soler) together provided 89 % of the power generation volume, implying a
very high concentration. In 2010, Luxembourg was coupled to the other countries
of the central-west region. However, since there is currently no
congestion on the Luxembourgish interconnection lines, the mechanisms for
transmission capacity allocation and congestion management do not apply. Luxembourg does not have a power exchange or a spot market for electricity. Electricity is
sold using OTC contracts. Thanks to interconnections with Germany and the absence of congestion, wholesale operators can participate on the German
power exchange EEX.

3.2. 
Gas. Luxembourg imports all of its national consumption of natural gas through Belgian and
German pipelines (around 1,4 bcm in 2010). Most of the gas originates from Norway (about 50 %) and Russia (about 25 %). At wholesale level,
the country’s gas market has a quasi-monopolistic structure; in 2010 the
dominant company (Enovos) had a market share close to 100 %.

In Luxembourg there is no organised wholesale market for
gas. Wholesale purchasing is done on other hubs, such as NCG, TTF and Zeebrugge, and the prices there
apply for Luxembourg as well. Luxembourg is suffering from limited availability
of firm entry capacity, especially on its German and Belgian connections,
despite the introduction of congestion management mechanisms, such as Open
Subscription Periods and a use-it-or-lose-it procedure in the new grid access
model, introduced on 1 January 2012.

4. 
Retail markets

4.1. 
Electricity. Market concentration at retail level was high, as the
three largest electricity distribution companies controlled 94 % of
market. The electricity market has been open to competition since 1 July 2007.
Enovos is the dominant player on the retail market. Supplier switching
remains low — less than 1 % (by volume and by number of customers).

Retail power prices for
households increased steadily between 2004 and 2009. They peaked in 2009, a
year after the peak in wholesale power and gas prices in the central western
Europe area.

In 2011, energy and supply costs and network costs were equally
split (50 %/50 %) in the final price for households (without taxes).
In the case of industrial consumers, the shares were 74 % and 26 %
respectively. Power prices are not regulated for households or
industrial consumers. A cost-benefit analysis on smart meter roll-out
has been carried out. The recently adopted laws on electricity and gas markets
provide for mandatory roll-out in the electricity and gas sectors.

4.2. 
Gas. Market concentration at the retail level was high, but lower than
on the electricity market, as the three largest distribution companies
controlled 74 % of the market. The HHI index also shows a lower
concentration.

Retail gas prices dropped or were stable after 2008, in
line with decreasing European gas prices. In 2011, following the upturn in
wholesale gas prices, retail prices went up again (see Chart 4). Gas prices
are not regulated for households and industrial consumers.

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' overall assessment of the electricity and gas retail
markets is the highest and second highest in the EU, respectively. Likewise,
the scores for trust are the highest and second highest across all EU
countries. Consumers face fewer problems in the gas and especially the
electricity retail markets compared to EU averages, and complaints also tend to be
lower than average (3rd and 2nd lowest numbers, respectively, in electricity
services) However, actual switching rates in both markets are among the lowest
in the EU (less than half the EU average). [84] An on-line price comparability tool is not yet in place,
but the NRA is planning to set one up in the near future[85]. There
is a single point of contact under the National Consumer Rights Protection
Association. The recently adopted laws authorise
ILR to act as the single point of contact. The regulator handles disputes between customers and suppliers and
between consumers and DSOs, and provides an alternative dispute resolution service.
While the laws on the
organisation of electricity and gas markets refer to vulnerable consumers,
there is no clarity as to the content of the term. The legislation contains
provisions for consumers in remote areas.

5. 
Infrastructure

Luxembourg is dependent on
imports for all its energy needs. More than 50 % of the gas is used for
generating electricity in CCGTs. Luxembourg does not have sufficient generation
capacity to meet its electricity demand. However, in order to secure supply it
can use its interconnections with neighbouring countries. The current n-1
secure interconnection capacity with Germany (980 MVA) is currently sufficient
to cover demand. This situation is, however, subject to review
as a result of the German nuclear phase-out and the anticipated growth in
demand.

KEY INDICATORS FOR THE ENERGY
MARKETS IN LUXEMBOURG IN 2010

Sources: Eurostat, CEER, ILR (Institut
Luxembourgeois de Régulation), 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.
Malta

1. General
overview

Malta's
energy consumption almost exclusively consists of oil and petroleum products.
The country’s dependence on imports of these is close to 100 %, and it has
not used solid fuels, natural gas or any other non-renewable resource for the
past two decades. This unusual situation is due mainly to Malta's isolation from other energy markets in Europe. As it has no oil, gas pipelines or power
lines linking it to other parts of Europe, the country is virtually an energy
island. Power generation (2.11 TWh in 2010) is based almost exclusively on
petroleum products. The country’s 2020 RES target[86] for the whole
energy sector is 10 %. Between 2006 and 2010, its use of renewable energy
sources grew slowly, from next to zero to 0.4 %. There are a number of
on-going projects, including large-scale wind farms, waste-to-energy and solar
photovoltaic installations. In 2010 the share of cogeneration[87] in the
overall electricity production did not reach a statistically significant level.

Charts
1 and 2

Source:
Eurostat

2. Regulatory
framework

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

2.2. 
National Energy Regulator. The
national regulatory authority, Malta Resources Authority (MRA), was set up in
2002, and employed 46 staff as of end-2011, with an annual budget of EUR 2.23
million. The limited budget is a constraint on the effectiveness of the
regulator. The Malta Resources Authority’s remit has been extended to cover
climate change, as well as petroleum, oil and gas exploration in addition to
its regulatory functions. Older tasks cover energy, minerals and water
regulation, energy efficiency and promotion of renewable energy. The Malta
Resources Authority also promotes energy efficiency and the development of
renewable energy.

2.3. 
Unbundling. There
is no transmission system in Malta, only a distribution system. According to
Article 44(2) of Directive 2009/72/EC, Malta has obtained derogations from
several provisions of the Electricity Directive (Article 9 on unbundling of
TSOs, Article 26 on unbundling of DSOs, Article 32 on third party access and
Article 33 on market opening and reciprocity). The island is not supplied with
natural gas. There is no gas infrastructure.

3. 
Wholesale
markets

3.1. 
Electricity. At the
generation and wholesale trade level, there is only one market player
(Enemalta) that generates Malta’s power, supplied predominantly with imported
fuels, mainly heavy fuel oil and gas oil.

3.2. 
Gas. There
is no natural gas in Malta. Households are supplied with liquefied petroleum
gas (LPG) for heating and cooking purposes. The LPG market was
liberalised in 2011, when Liquigas Malta took over importing and sales from
Enemalta, and when MRA authorised a second company, Easygas Malta, to enter the LPG market.

4. 
Retail
markets

4.1. 
Electricity. There
is only one provider, Enemalta, in line with Article 44 of the Electricity
Directive. The general situation of Malta as an energy island, the  lack of an
independent power producer that could compete on wholesale prices, as well as
the small size of the market, means that it is difficult for the country to
achieve a fully-competitive market of the kind that would benefit consumers and
ensure secure supply. Both industrial and domestic power prices are
regulated. Electricity prices are among the highest in the EU.
Taxes account for a very low part of the final electricity
price (5 % VAT). Energy and supply costs accounted for 86% of domestic
prices, with network costs at 14 % in 2011. For industrial consumers, the
percentages were 88% and 12% respectively. Energy prices have increased
substantially in recent years, due to higher heavy fuel oil and gas oil prices.
In 2009, Malta started a mandatory roll-out of smart meters, with a pilot of
5 000 installations. The full replacement of all 245 000 electricity
meters started in 2010 and should be completed within three years.

4.2. 
Consumers.
Maltese consumers rate their retail electricity market 5th highest in the EU,
with the 3rd highest score on trust.  The market is assessed above the EU
average on all indicators except for problems and complaints, which are
slightly more prevalent in Malta than in other EU countries. [88] Consumers can obtain
information and advice from the Malta Consumer’s Association. The National
Regulatory Authority settles unresolved disputes between consumers and
electricity suppliers, thereby providing alternative dispute resolution.
It is nevertheless that the activity of the NRA in this regard is not
sufficiently advertised. Malta recognises ‘vulnerable consumers’ through
specific provisions in its social laws.

Chart 3

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

5. 
Infrastructure

The
project to build an interconnection with Italy (Sicily) by a 220 MW HVAC
submarine cable is progressing well and the line is expected to be in operation
by the end of 2013. In parallel to this project, the national electricity
company, Enemalta, is preparing the distribution system so as to accommodate
the grid to the new connection. Once this connection is up and running, Malta's isolation will cease.

With
regard to gas, Malta promotes the construction of a floating LNG storage and
re-gasification unit (FSRU) with a capacity of 75 Tera BTU (2.1 bcm). The
project includes a connection to the European Natural Gas Network via a 150
kilometre 25’ diameter pipeline to Gela in Sicily; and the installation of an
FSRU to be supplied with LNG shipments, which would be connected to the
Delimara Power Station (via a 12 kilometre pipeline) and to the gas
interconnection. An estimated 20 % of the FSRU's natural gas capacity
would be for local needs and 80 % for export to the European market.

KEY INDICATORS ON THE ENERGY MARKETS IN MALTA 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.

The Netherlands

1. 
General overview

Dutch energy consumption was based mostly on fossil fuels,
notably natural gas (with a share of 45.7 % in the energy consumption
mix), crude oil and petroleum products (40.8 %), and to a lesser extent on
solid fuels (8.8 %). Renewable energy sources (RES) and nuclear energy
were less important in the energy mix (with shares of 3.4 % and 1.2 %,
respectively). Natural gas consumption was approximately 49.4 bcm in 2010,
according to Eurostat data.

In 2010, the power generation (118.4 TWh) mix in the Netherlands was also dominated by gas-fired power generation (with a share of 65.5 %)
and by solid fuels (19.1 %); RES represented 9.5 % and other sources
such as nuclear power (3.4 %) were less important. The country’s 2020 RES
target indicator for the whole energy sector[89]
is 14 %, which is lower than the EU-27 average (20 %). Between 2006
and 2010, the RES share grew slowly (from 2.7 % to 3.8 %).
Cogeneration[90]
provided for 33.2% of the total electricity generation in 2010. In 2005 the
share of cogeneration already stood at a high level (29.4%).

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

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

2.2. 
National Energy Regulator. The
Dutch Office of Energy Regulation, Energiekamer, is part of the
Netherlands Competition Authority, Nederlandse Mededingingsautoriteit
(NMa). The NMa is currently undergoing significant reform, incorporating also
the Dutch telecoms and consumer authorities. Energiekamer, which has
been in operation since 1998, employed 80 staff in 2010 and had an annual
budget of approximately EUR 11.8 million.

2.3. 
Unbundling. TenneT
is the national TSO for the transmission of electricity and Gas Transport
Services (GTS) is the TSO for gas. To date, both are fully owned by the Dutch
state. The certification of these TSOs has not yet taken place, but they are
both expected to apply for certification under the ownership unbundling model. The
interconnectors, Britned and BBL, will also be certified as TSOs. At the end of
2010, all (except two) DSOs were fully unbundled from the integrated company
and are mostly owned by Dutch municipalities and provinces. There are eight
DSOs that supply gas and electricity and two which supply only gas. Due to a
court decision, part of the law on unbundling of DSOs expired, leading the two
integrated companies that were not yet unbundled to postpone their commitment
to unbundling. The Ministry of Economic Affairs, Agriculture and Innovation
appealed to the Supreme Court of the Netherlands and a decision is pending. A
request for a preliminary ruling has been addressed to the European Court of
Justice.

3. 
Wholesale markets

3.1. 
Electricity. At
the generation level, the combined market share of the three largest
firms in terms of volume of power generation was 59 % in 2009 (latest
available data). The Dutch power generation market can be deemed to be
moderately concentrated, both in terms of the combined power generation
capacity of (59 %) of the three largest firms and the HHI index for
capacity (1 433).

Market integration with
neighbouring markets was successfully carried out in 2007 through the
Trilateral Market Coupling system involving the Netherlands, Belgium, and France. In late 2010, market coupling was extended to Luxembourg and Germany. The central west European (CWE) power region was coupled with the Nordic price
area through the Interim Tight Volume Coupling (ITVC) project, which has had a
positive effect on the price convergence. Britned, the interconnector between
the Netherlands and the United Kingdom, became operational in April 2011.
Britned, allowing integration of the Dutch and British electricity markets. In
its first year of operation, Britned accounted for 7.6 TWh of traded volume in
the Netherlands-UK direction and 5.3 TWh of traded volume in the UK-Netherlands
direction. Britned offers medium-term products through explicit auctions and a
short-term day-ahead product through implicit auctions facilitated by
APX-ENDEX. As of May 2012 Britned also offers intraday auctions.

In 2011, the annual average of wholesale day-ahead power
prices on the APX market was EUR 52/MWh, up from EUR 45.4/MWh in
2010. The annual traded volume of wholesale day-ahead power in 2011 was 39 TWh,
up from 33 TWh in 2010. The number of traders involved in day-ahead power
trading on the APX spot market was 56 in 2011. Market liquidity, measured as
the ratio of the annual traded volume of day-ahead power to gross inland
electricity consumption in the Netherlands, was 33.1 % in 2011.

3.2. 
 Gas. The
production and wholesale gas markets in the Netherlands are highly concentrated
due to the exploitation of the large Groningen field by a single producer. The
three largest gas producers covered 93 % of the market in terms of
available gas[91]
in 2010, with the Nederlandse Aardolie Maatschappij (NAM) being by far
the largest producer. The gas that is produced by NAM is sold exclusively on
the wholesale market by the trading company GasTerra to Dutch and foreign
customers, most of which are suppliers.

The Netherlands has a well-functioning virtual trading point
(the TTF hub) based on an entry-exit system. Gas bought at the TTF is
‘entry-paid’ and can be transported to any exit point in the transmission grid.
In 2011, the average day-ahead gas price was EUR 22.6/TWh, up from EUR 17.4/MWh
in 2010. The 2011 average price was broadly in line with average prices on the
other major west European hubs, ranging from EUR 22-24/MWh. The traded volume
of day-ahead gas on the TTF hub increased steeply to 220 TWh in 2011. The
introduction of a market-based balancing system contributed considerably to
this increase. The churn rate (the ratio of traded volumes to physical gas
deliveries) was 4.6 in 2011, up from 3.6 in 2010.

The Netherlands is the biggest natural gas producer in the
EU. According to Eurostat data, the country accounted for 40 % of EU-27
gas production in 2010. In 2010 the country’s annual production was
approximately 63.5 mtoe, however, gas production is forecast to decline
significantly by 2020.,On the demand side, annual domestic consumption amounted
to 39.3 mtoe and exports totalled 42.7 mtoe.

Cross-border interconnection points with Germany and Belgium are fully booked well into the future, but are underutilised, which is
inefficient from an economic perspective. Swift implementation of new rules on
congestion management and capacity allocation could alleviate the situation
without the need to invest.

4. 
Retail markets

4.1. 
Electricity. Market
concentration at retail level was high, as the three largest companies
covered 80.3 % of the retail market at the end of 2010. Between 2007 and
2011, household prices remained more or less stable. Industrial prices
decreased slightly during 2010 and 2011.

Energy and supply costs made up 58 % of household
prices (whereas the share of network costs was 42 %) in 2011. For
industrial consumers, the share of energy and supply costs of the total price
(76 %) is high compared to other EU countries, thanks to relatively low
network costs (accounting for 24 %). There is a correlation between both
industrial and household retail prices and wholesale market prices, although it
is not strong. It took a couple of months for changes in wholesale prices to be
reflected in the retail prices.

The number of customers that switched supplier has
decreased compared to 2009 (11 %); at the end of 2010 the figure stood at
8.8 %.

A legal framework for a voluntary roll-out programme for smart
meters was adopted in 2011, which gives households a choice with regard to
the installation and use of smart meters. It consists of a two-year trial
period (2012-2013) followed by an ‘acceleration’ phase starting in 2014.

4.2. 
Gas. Even
though the market is fully liberalised in the Netherlands, market concentration
at the retail level remained high, as the three largest companies covered 78.6 %
of the retail market at the end of 2010.

Gas prices for
both households and industrial consumers rose between 2005 and 2008/2009,
mainly due to an increase in net prices combined with the general upward trend
of wholesale gas prices (see Chart 4). In 2009 the non-VAT tax content of both
household and industrial prices was increased. The tax component of the final
price was particularly high for households in the Netherlands (39 %) in
2011; it was 24 % in the case of industrial prices. In 2010 retail gas
prices in the Netherlands decreased slightly, while they remained stable in
2011.

There is a strong correlation between wholesale gas prices
on the TTF hub and retail prices in the Netherlands (for both industrial and
household prices). It took a couple of months for changes in wholesale market
prices to be reflected in retail prices.

The
number of customers that switched supplier (8.9 %) has decreased
slightly compared to 2009.

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. Dutch
consumers rate their electricity and gas retail markets above EU average (7th place
out of 27 and 11th place out of 23, respectively. Both markets rank well above
average on choice (2nd and 3rd highest score in the EU, respectively),
switching rates (1st and 5th highest) and satisfaction (highest score in the EU
for electricity market). Especially in the gas market, consumers face fewer
problems than the EU27 average (2nd lowest incidence in the EU); yet complaints
are second highest. [92]
Online price comparability tools for electricity and gas are available and
operated by private companies. NMa monitors these tools and publishes the
results on the website of the national point of contact, Consuwijzer.
Consumers can direct requests for information and complaints to Consuwijzer,
which is run by NMa (together with the Dutch telecom and consumer authorities).
The NRA also handles complaints. The legislation does not define ‘vulnerable
customer’, but low-income households benefit from social support schemes and a
‘no-disconnection period’ running from 1 October to 1 April applies to all households.

5. 
Infrastructure

5.1. 
 Electricity. Generation capacity has
been rising sharply since 2008 and this trend is expected to continue, making
the Netherlands a potential net exporter of electricity. The downside of this
generation surplus is the reduced ability of the transportation grid to
accommodate the produced quantities. In an attempt to solve the most urgent
problems, Dutch authorities have introduced a congestion management system
allowing the TSO to reduce production in one region and increase production in
another region of the country. A more sustainable solution lies in the
expansion of the transmission grid by TSO TenneT, which is currently in
progress and is expected to result in a strengthening of the 380 kV grid in
both the west and the north of the Netherlands.

5.2. 
 Gas. Dutch domestic production from the
large Groningen field and numerous small fields is expected to decline in the
future, but production currently stands at traditional levels. The Netherlands has retained its position as a net exporter of gas. Nevertheless, the Dutch
government is preparing itself for the time when more imports will be necessary
by pursuing a strategy to become Europe’s ‘Gas roundabout’ To that end, an LNG
terminal near the port of Rotterdam has been constructed which became
operational in 2011. Today, H-gas is physically imported from Norway and Russia through interconnection points on the border with Germany. In order to meet peak
demand, a new gas storage facility has been built in Zuidwending. Furthermore,
several storage facilities (salt caverns) have been built just across the
border in Germany, which serve the Dutch market and will all be operational by
the end of 2012. In addition a seasonal storage system is being developed by
Taqa, which is expected to become operational in 2013.

KEY INDICATORS FOR THE ENERGY MARKETS IN
THE NETHERLANDS 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.

Poland

1. General
overview

Solid
fuel, 83% of which is hard coal, continues to play a major role in Poland’s energy sector. Solid fuel accounts for 54 % of the country’s energy
consumption mix and nearly 87 % in electricity generation. Out of 157.6
TWh of electricity produced in Poland, 7.3 % came from renewable energy. Poland’s indicator for the 2020 RES target[93]
has improved, from 7 % in 2006 to 9.4 % in 2010. The country’s RES
target for 2020 is 15 %. The share of cogeneration[94] in
electricity production was 17.6% in 2010, being slightly higher than in 2006
(16%).

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General. Poland has not yet fully transposed the Third Energy Package Directives. As regards the
Electricity Directive a letter of formal notice was sent in November 2011 and
reasoned opinion followed in May 2012. On 24 October 2012, the Commission
decided to refer Poland to the Court of Justice for only partially transposing
the Directive.[95]
Moreover, three infringement procedures are still open on the Second Energy
Package concerning i) regulated wholesale and end user prices in gas; ii)
lack of transparency of the conditions for third-party access to natural gas
transmission networks and failure to put in place appropriate procedures for
dealing with consumer complaints; iii) lack of congestion management and
transparency provisions concerning access to the network for cross-border
exchanges in electricity and the failure to put in place appropriate procedures
for dealing with consumer complaints.

2.2. 
National Energy Regulator. The
Polish National Regulatory Authority, Urząd Regulacji Energetyki
(URE), in operation since 1998, employed 300 staff in 2010 with an annual
budget of 35 million zloty [about EUR 8.7 million]. The tasks of the
regulator were enhanced in 2010, for instance, in the field of consumer
protection.

2.3. 
Unbundling. The
TSO in electricity is PSE Operator SA and for gas, Gaz-System SA. Both in electricity
and in gas, the TSOs and the vertically-integrated energy companies remain
(majority) state-owned. Certification of these TSOs has
not yet taken place. By November 2010, Gaz-System S.A. was also appointed
operator of the Polish section of the Yamal gas pipeline. The owner of the
pipeline remains EuRoPolGaz, owned by PGNiG, Gazprom Export and Gas-Trading. A
new intergovernmental agreement was reached between Poland and the Russian Federation, enabling the Polish section of the Yamal pipeline to be operated in
line with EU law,  and enabling subsequent agreements at company level to
reflect the provisions of the intergovernmental agreement.

In
2010, at distribution level, seven out of 22 DSOs in electricity were legally
unbundled, while the other 15 were exempted from unbundling. In gas, there were
six DSOs legally unbundled from the PGNiG group and one local DSO, exempted
from the unbundling requirement.

3. 
Wholesale markets

3.1. 
Electricity.
Regarding generation, the three biggest producers together controlled
more than 60 % of the Polish market. Polska
Grupa Energetyczna SA (PGE) had a 36.5 % market share,
TAURON Polska Energia SA (TAURON) 15.1 % and Electricité de
France (EDF) 10.2 %. Consequently,
market concentration remained high. At wholesale trade level, more
than two-thirds of electricity was traded through bilateral contracts between
producers and distributors in vertically-integrated groups. 17.6 % was
traded OTC outside the group and only a very small fraction was sold on
the POLPX power exchange. One of the positive developments spurring competition
was the introduction in 2010 of a legal obligation in the amended Energy Law on
generators to sell 15 % or 100 % (for generators involved in
long-term power purchase agreements) of generated electricity through a power
exchange, which increased liquidity. Market integration with
neighbouring markets, although in general still poor, has also been improved
thanks to this measure. Increased liquidity enabled Polish and Swedish traders
to use capacity on the SwePol interconnector (600 MW) for trading electricity
between these markets on Nord Pool Spot and the POLPX exchange. Day-ahead
trading has been coupled between the Nordic and Polish energy markets since
December 2010. The wholesale price in 2011 was on average
EUR 52.2 /MWh for day-ahead baseload power contracts, up from
EUR 48.0 /MWh measured in 2010.

3.2. 
Gas. Annual
imports of natural gas were 10.1 bcm in 2010, corresponding to 70% of gross
inland consumption. 90% of imports come from Russia under a long-term
agreement with Gazprom and 10% from Germany. Domestic production covers around
30 % of demand. Poland has considerable potential for developing shale gas
extraction and the government has been issuing extraction licences. The
country's shale gas reserves could make it self-sufficient in energy.

Market
concentration at the level of imports and production remain very high. Wholesale
trade in natural gas in Poland in 2010 took place only within the PGNiG SA
group. The market share of PGNiG was 98 % in 2010, easing to 97 % in
2011, but even companies active in the remaining 2 % of the market
purchased gas from PGNiG. Wholesale trading remains based exclusively on
bilateral contracts. There is no gas trading on exchanges or through hubs.
PGNiG SA also booked almost 100 % of capacity at all entry points to the
Polish gas transmission system with utilisation rates ranging between 50 %
and 100 % of the interconnectors concerned. In November 2011, five
companies applied for the virtual reverse flow capacity available on the Yamal
pipeline.

Also
in 2011, URE initiated a ‘Gas Price Release Programme’ intended to liberalise
the Polish market and to foster competition, but the efforts made in this
context could be stepped up. There are plans to deregulate tariffs for
industrial and commercial customers, and to start trading gas on the gas
exchange. In 2011, for the first time, entry-exit rates were introduced into
transmission tariffs.

4. Retail
markets

4.1. 
Electricity. In
2010, market concentration was high because most of the sales on the
retail market were made by incumbent suppliers which used to be part of the
distribution companies before market opening. The three largest companies were
TAURON Polska Energia S.A., PGE Dystrybucja S.A. and ENERGA
Operator S.A., with a market share of 71 %. Switching of suppliers
remains insignificant, most likely as a result of regulated prices. In 2011, energy and supply costs accounted for 55 % of
domestic prices (without taxes), while network costs accounted for 45 %.
For industrial consumers, the shares were 67 % and 33 % respectively.
The correlation between wholesale and retail prices is distorted due to
retail price regulation. As for the roll-out of smart meters, an
assessment of long-term costs and benefits was implemented in 2012, following a
report by the URE in 2008. No legal framework is currently in place.

4.2. 
Gas. In
2010, market concentration at retail level was very similar to that at
wholesale level. The market was dominated by the incumbent PGNiG SA, with its
share of approximately 98 %, easing to 97 % in 2011. The 2 % was
highly fragmented, with several dozen companies buying gas from PGNiG and
reselling it to final customers. No switching took place. Both domestic and industrial prices were subject to regulation.
In 2011, gas prices were reduced by 3.23 % on average, due to a rebate
expected under import agreements which PGNiG S.A. concluded with Gazprom.
According to the agreement, 15 % of imported gas was covered by a rebate.

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' overall assessment is just below the EU average for retail gas
market (12th place out of 23 countries) and well below for retail
electricity market (21st place out of 27). Both markets are ranked
below EU average for all indicators, except problems and - in the gas retail
market- choice. The number of problems faced fell considerably between 2010 and
2012 while the choice has increased compared to 2011.[96]  In June 2011, URE introduced
an on-line price comparability tool for electricity and gas prices, but it does
not yet include gas options. Since September 2011, consumers have also been
able to obtain information and make complaints on electricity and gas to a single
contact point at ERO. There appears to be no alternative dispute resolution
mechanism of the type required under the Third Energy Package Directives yet.
To date, Poland has not defined vulnerable consumers.

5. 
Infrastructure

5.1. 
Electricity.
Despite the 600 MW SwePol interconnector, the lack of cross-border transmission
capacity is a major impediment for integration. This situation is exacerbated
by the increasing level of power generated from RES in Northern Germany, which
creates loop-flows. Congestion is also caused by the uneven geographic
distribution of generation. A feasibility study for a new 500MW link between Poland and Lithuania (LitPolLink) is being carried out. LitPolLink is part of the Baltic Energy
Market Interconnection Plan (BEMIP).

5.2. 
Gas. There
are four projects that recently received support from the European Energy
Programme for Recovery (EEPR), two interconnections, PL-DE and PL-CZ, an LNG
terminal in Swinoujscie and an upgrade of the transmission system in
north-western Poland. The Commission also welcomes an ambitious programme of
investment in gas storage, with support from various European funds. Last year,
the virtual reverse flow on the Yamal transit pipeline was made available.
Feasibility studies are being carried out for interconnections with Slovakia (part of N-S Interconnections) and Lithuania (part of BEMIP).

KEY INDICATORS ON THE ENERGY
MARKETS IN POLAND

Sources: Eurostat and ACER, 2010 data.

(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 (indigeneous production or import).

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

Portugal

Key Issues ₊   With regard to electricity, Portugal should address the economic sustainability of the national electricity system in line with the Memorandum of Understanding with the Commission, the ECB and the IMF, in particular in terms of support for renewables and co-generation, and stranded cost compensation (Cost of Maintenance of Contractual Equilibrium (CMECs)). To this end, it should accelerate convergence to market-based pricing for co-generation operators in parallel with changes in the electricity market. It should aim to increase the number of interconnections with France and Spain. These are essential for the creation of a regional market in the south-western region. ₊   With regard to both electricity and gas, while taking into account universal service obligation and effective protection of customers, Portugal should phase out regulated gas prices for end-customers, as envisaged in the legislation that is in force or is being prepared. ₊   With regard to the gas wholesale market, Mibgas should be further developed, in particular in terms of harmonising cross-border tariffs with Spain. Portugal should maintain its plans to increase the cross-border capacity of the gas network with Spain by 2015. ₊   With regard to regulatory matters, the energy regulator’s independence from the Ministry of Energy should be ensured. Its powers with regard to arbitration and enforcing penalties should also be guaranteed.

1. General
overview

Crude
oil and petroleum products make up slightly more than half of the energy mix.
Renewable energy sources (RES) were the second most important fuel type in the
mix. No nuclear power is generated in Portugal. At 53.2 %, the greatest
source of power was RES. Portugal’s 2020 RES indicator[97] increased
from 20.8 % in 2006 to 24.6 % in 2010. It aims to reach 31 %.
The share of cogeneration[98]
in electricity production was 11.8% in 2010, showing a great deal of stability
since 2005 when it was 11.6%.

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General. As Portugal had notified full transposition of the Third Energy Package Directives by the end
of September 2011, no infringement proceedings for non-transposition have been
opened Some implementing acts regarding the role of the national regulator are
in preparation. Portugal made also several commitments regarding reforms of the
energy markets, including abolishment of regulated prices for gas and
electricity and further measures protecting vulnerable customers.

2.2. 
National Energy Regulator. The
Portuguese National Energy Regulatory Authority, Entidade Reguladora dos
Serviços Energéticos (ERSE), in operation since 1998, employed a staff of 80
in 2010, with a budget of almost EUR 11 million. ERSE’s independence from
the Ministry of Energy should be ensured including equipment with sufficient
financial means allowing fulfilling its functions foreseen in the Third
Package. Its powers with regard to arbitration and enforcing penalties should
also be guaranteed.

2.3. 
Unbundling. There
is one publicly owned TSO for electricity, REN (Redes Energéticas Nacionais).
In 2012, a 40 % stake in REN was sold to China State Grid Corporation and
Oman Oil. EDP Distribução is the main electricity distributor through an
exclusive concession granted by the State. It is legally unbundled. There
are ten other smaller electricity distributors. The gas TSO is REN
Gasodutos. It has a 40-year concession to operate the national gas grid.
These TSOs have not yet been certified.

3. Wholesale
markets

3.1. 
Electricity. With
regard to electricity generation, the market concentration is high. In
2010, the three biggest electricity producers (EDP, REN Trading and Iberdrola)
held a combined market share of approximately 70 %. EDP was the clear
market leader with a share of around 55 %. The Portuguese market has been
integrated into the Iberian market since July 2007. The spot market operator
(OMEL) is located in Spain, while the forward market operator (OMIP) is located
in Portugal. The situation has been improving since 2008. The market was split
for 68 % of the time in 2008 and for only 21 % of the time in 2010.
The wholesale baseload day-ahead power price was EUR 45.5/MWh in
2011. This was higher than the average price in 2010 (EUR 37.3/MWh).
Investment and operating costs of power generation in Portugal are significantly influenced by economically unsustainable support measures for generation
(power guarantee mechanism, Costs with the Maintenance of Contractual
Equilibrium (CMECs) and Power Purchase Agreements (PPAs)), renewables and CHPs.
  Portugal made commitments to revise those measures.

3.2. 
Gas. In
2010, 5.2 bcm entered the National Natural Gas Transmission Network. No gas is
produced in Portugal. The main sources of imported gas were Nigeria, through the Sines LNG facility (52 %), and Algeria (38 %), through the pipeline
from Spain. Galp remains the biggest supplier on the Portuguese gas market. In
an effort to liberalise the market, ERSE obliged Galp to auction 300 mcm per
year for three years. However, in 2010 this process ended because suppliers had
excess stocks of gas. There is no hub or marketplace to trade gas with a
transparent price setting mechanism. The Mibgas project however aims to merge
the Spanish and Portuguese gas markets. To do this, it is necessary to
harmonise cross-border tariffs with Spain. Following the public consultation at
the beginning of 2012, ERSE and the Spanish regulator CNE are preparing a
proposal on this subject.

4. Retail
markets

4.1. 
Electricity. Market
concentration at retail level is very high. The market share of the three
biggest companies was 95.6 % in 2010. Many big customers and industrial
customers switch suppliers (27.4 %). Very few households switch however
(2.3 %). The retail market consists of a regulated market and a
liberalised market. In 2010, the regulated tariff, which had been a barrier for
new entrants, was abolished for customers with a contract for more than 41.4 kW
of power. Industrial electricity prices gradually increased between 2005 and
2011. There were fewer taxes on industrial prices than on household prices and
the difference between household and industrial prices can mostly be explained
by taxes other than VAT. In 2011, the share of energy and supply costs in
household electricity prices without taxes was 59 %, while network costs
accounted for 41 %. The share of energy and supply costs in industrial
prices without taxes was higher at 65 %, while network costs were moderate
at 35 %.

4.2. 
Gas. Thanks
to the complete liberalisation of the Portuguese natural gas market, all
customers could choose their supplier in 2010. In mainland Portugal, the end-user sales market consists of a regulated system of integral tariffs
offered by last-resort suppliers and a market-driven system in which energy is
supplied through contracts with non-regulated prices. During 2010, around 1100
industrial users, roughly one third, switched gas supplier. Gas prices
for industrial consumers were much lower than for households during the last
couple of years.

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.

4.3. 
Consumers.
Consumers' overall assessment of retail gas markets is just below the EU
average (14th place out of 23), with the second lowest score on
choice. Retail electricity market is ranked 5th lowest in the EU,
with particularly poor scores on choice (second lowest in the EU) and ease of
switching (third lowest).[99]
A price comparison tool for electricity is available on the NRA’s
website. It is planned to develop such a tool for gas in 2012. In 2011, Portugal passed new legislation on electricity and gas.[100]
It describes the single point of contact as a centralised platform that
will give consumers all the information they need to exercise their rights, as
well as information about legislation and dispute resolution mechanisms. Complaints
should be made to the energy supplier, who must answer within 15 working
days. If the supplier does not meet this deadline, the consumer will
automatically be compensated. Several bodies are in charge of alternative
dispute resolution, such as consumer associations, arbitration centres and
public bodies. There is a definition of vulnerable consumers based on
social criteria. In 2007, the National Energy Services Entity presented a
cost-benefit analysis and a non-legally binding meter substitution plan
for the period 2010–15.

5. 
Infrastructure

5.1. 
Electricity. Portugal currently has relatively few interconnections with France and Spain. To reduce splitting in
the Iberian Electricity Market, an investment programme has been put in place
to increase the capacity of interconnections with the Spanish transmission
network. It includes the construction of a new 400 kV line and the construction
of two new 400 kV interconnections. They will almost double capacity. Under the
European Energy Programme for Recovery (EEPR), REN received EUR 45 million
to reinforce the two interconnections with Spain (Douro Region and the  Algarve).

5.2. 
Gas. Gas is
expected to play an increasingly important role as a back-up fuel given the
increasing production of electricity from renewable sources. This requires an
increase in cross-border capacity. REN Gasodutos received EUR 10.7
million from the EEPR to enable reverse flow capacity into the gas network.
This will prepare the network for the development of a third interconnection
with Spain.

KEY INDICATORS ON THE ENERGY
MARKETS IN PORTUGAL IN 2010

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

NA: not available or not applicable.

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

(2) Retailers are considered ‘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 company 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 the natural gas production (indigenous production
or imported gas).

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

Romania

Key Issues ₊   With regard to electricity, Romania needs to phase out regulated end-user prices for non-household customers by the end of 2013 and for household customers(while taking into account universal service obligation and effective protection of customers) by the end of 2017 in line with the roadmap adopted by the Romanian government in March 2012. Furthermore, Romania should set up a functioning intra-day market and provide for procedures for the allocation of capacities on interconnectors, including implementation of market-based and coordinated congestion management on all its borders. Romania should abolish all transaction-related transmission charges and review discriminatory rules of participation on its power exchange organised by Opcom. Interconnectors also need to be expanded. Romania has an action plan to upgrade and extend its infrastructure, which needs to be updated in accordance with EU and national legislative requirements. ₊   With regard to gas, Romania needs to phase out regulated end-user prices for non-household customers by the end of 2014 and for household customers (while also ensuring effective protection of vulnerable customers) by the end of 2018 in line with the roadmap adopted by the Romanian government in June 2012. High market concentration at production level combined with bilateral long-term supply contracts are structural obstacles to more competition in this market. Full third-party access to gas pipelines should be implemented, including virtual backhaul capacity on all pipelines. Romania needs to set up an organised wholesale gas market. The ‘transit’ pipelines need to be linked physically to the Romanian national gas system. Romania should make the new HU-RO interconnection bi-directional and remain committed to timely implementation of the Romania-Bulgaria reverse flow and a new Romania-Bulgaria Interconnection (both EEPR co-financed). ₊   Romania needs to restore the independence and financial autonomy of its national regulatory authority ANRE.

1. General
overview

Gas
represented 30 % of the Romanian energy consumption mix in 2010, followed
by petroleum products (26 %) and solid fuels (20 %). The significant
share of RES (16 %) and nuclear power (8 %) contributes to a balanced
energy mix. The power generation mix is mainly shared between solid fuels (34 %),
renewables (33.5 %) and nuclear (19 %). The country’s 2020 renewable
target indicator[101]
increased from 17.2 % in 2006 to 23.4 % in 2010, the aim being 24 %
by 2020. The share of cogeneration[102]
in electricity production was 10.8 in 2010.

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General.
Following the opening of infringement proceedings in September 2011 for
non-transposition, Romania 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. One infringement
procedure is still open on the Second Energy Package concerning the lack of
transparency of the 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.[103]

2.2. 
National Energy Regulator.
The Romanian National Regulatory Authority, Autoritatea Nationala de
Reglementare in domeniul Energiei (ANRE), has been in operation since 1998.
In 2010 it employed 232 staff with an annual budget of EUR 6.6 million and had
10 regional offices. ANRE’s independence and its financial autonomy were
seriously curtailed in 2009 and 2010 due to two national laws that changed the
regulator’s status.

2.3. 
Unbundling. The
state owns the majority of the shares in the electricity TSO (CN Transelectrica
SA) and gas TSO (Transgaz SA). Romania plans to choose the ISO model for both
TSOs, a model largely implemented already in 2000. The TSOs currently have no
ownership of the transmission systems they operate, which are owned directly by
the state. At distribution level, 8 of the 37 electricity DSOs are legally
unbundled while the others are exempt from unbundling. In the gas sector, 2 of
the 39 DSOs are ownership-unbundled while the others are exempt from
unbundling.

3. 
Wholesale markets

3.1. 
Electricity. In
2010, at generation level, the three largest producers controlled 65 % of
the market. The government owns most of the large generation companies.
Further, hydro power from these generators is often sold below market prices.[104] This
situation makes it difficult for independent power producers to compete with
the state-owned companies: they do not have access to the low-cost hydro and
nuclear generation capabilities. At wholesale level most electricity is
sold through bilateral contracts, but increasing volumes are sold on the
Romanian electricity exchange, OPCOM. Trading on the OPCOM Power Exchange
accounts for about one quarter of Romania’s electricity supply, and this share
is expected to double when regulated prices for non-residential consumers are
removed by the end of 2013 and state-owned generators move those volumes from
the regulated market to OPCOM, as required by law. The growing importance of
the power exchange makes it all the more important to review its admission
criteria and to implement changes to ensure equal participation for all traders
irrespective of their country of establishment.

Romania
maintains a system of transmission tariffs which hinders the free flow of
electricity across its borders. This not only hinders trade between Member
States but also reduces the efficiency of the planned market coupling between Romania and the wider CEE region. The tariff system should therefore be reviewed so as to
abolish all transaction-related charges. No functioning intra-day market is yet
in place in Romania, but there is a day-ahead market with hourly products for
the next day. Market integration with neighbouring markets is still in its
infancy. Interconnectors to Bulgaria and Hungary are regularly congested, and
trading is still solely through bilaterally coordinated auctions. Romania is a net exporter of electricity. Wholesale prices in 2011 were on average
EUR 52.13/MWh for baseload power[105]
(a 43 % increase compared to 2010). Market liquidity was lower than
in major central-western European hubs (16-17 % in 2010 and 2011), but
there is a clear upward trend (in 2008 the ratio was 9.6 %).

3.2. 
Gas. Romania has the third largest gas reserves in the EU. The country imported only 2.3 bcm of
natural gas, corresponding to 17 % of its gas consumption in 2010 (98% of
imports come from Russia). Natural gas is extracted by two companies, Romgaz
(state-owned) and Petrom (51 % owned by OMV and 20 % state-owned). The opening of the new 4.4 bcm Arad-Szeged interconnector
with Hungary in October enables gas to be imported from other sources (the
reverse flow to Hungary still needs to be implemented). At wholesale level,
gas is sold exclusively through long-term bilateral contracts between producers
and suppliers. This hampers market entry. There is neither an organised
wholesale market nor a spot market. OPCOM has been designated to set up
a gas exchange. Transgaz applies the
first-come-first-served capacity allocation method, which is not the most
suitable for the allocation of scarce capacity. Since 2010, it has been
possible to book interruptible capacity products, which gives third parties
more opportunities to gain access to the grid.

4. 
Retail markets

4.1. 
Electricity. Market
concentration at retail level remains moderate. Price regulation continues to
exist for both household and industrial customers. A roadmap was adopted by the
Romanian government in March 2012 to phase out regulated electricity prices for
non-household customers by the end of 2013 and for household customers by the
end of 2017. However, as long as regulated prices remain and are below market
prices, switching rates will continue to be negligible (0.06 %). Power
prices for industrial consumers decreased by 10 % between the first
half of 2008 and the first half of 2011. In comparison, power prices for
households (taxes included) increased by 2 % in the same period due to a
strong increase in the tax element of the final price (+33 %). The share
of network costs in Romanian household prices (without taxes) was the highest
in the EU-27 in 2010 (60.2 %) and in 2011 (61 %), while energy and
supply costs accounted for only 39.8 % in 2010 and 39 % in 2011. For
industrial electricity prices, the opposite is true: in 2010, network costs
accounted for 39 % (35 % in 2011) of the net industry retail price
while the share of commodity and supply costs was 61 % (65 % in
2011).

4.2. 
Gas. The
Romanian retail gas market consists of a competitive segment and a regulated
segment. Almost all of the approximately three million gas consumers in Romania fall under the regulated segment, where prices are set by the regulator rather than
being determined by supply and demand. A roadmap was adopted by the Romanian
government in June 2012 to phase out regulated gas prices for non-household
customers by the end of 2014 and for household customers by the end of 2018. In
the regulated segment, two large companies, E.On and GdF Suez, cover around 91 %
of the market; the rest of the market is covered by 37 very small suppliers.
Since prices for the household consumers in this segment are regulated, no
switching takes place. Around 1500 consumers are in the competitive segment. As
set out in chart 4 below, gas prices for industrial consumers decreased by 13 %
between the first half of 2008 and the first half of 2011, despite a
significant increase in taxes. For households, the trend was similar with taxes
accounting for 48 % of the final price in 2011. The share of network costs
in Romanian household prices (without taxes) was the highest in the EU-27 in
2010 (60.2 %), while energy and supply costs accounted for only 39.8 %.
For industrial electricity prices the opposite is true: network costs accounted
for 39 % of the net industry retail price while the share of commodity and
supply costs was 61 %.

Charts
3 and 4

Source:
Eurostat Note: VAT is refundable for industry so is not included.

4.3. 
Consumers.
Consumers' overall assessment of the retail gas market is 5th lowest in the EU,
with choice, problems and overall satisfaction within the 3 worst ratings in
the EU. The electricity market is assessed just above the EU average (14th
place out of 27) even though the percentage of consumers experiencing problems
is 80 % above the EU average (4th highest percentage in the EU). [106] The role and
responsibilities of the NRA with regard to consumer protection issues are weak.
However, a new law regulating ANRE will strengthen its powers in this regard.
Also, the roadmaps for phasing out regulated electricity and gas prices provide
a number of accompanying measures to enhance ANRE’s powers and responsibilities
in the retail market. For example, ANRE will develop a price comparison tool
and set up a protection scheme for vulnerable customers. The Energy Act defines
the concept of vulnerable consumers, which includes residential consumers who,
for reasons such as illness or age and by decision of the government, benefit
from subsidies and are ensured connection to the electricity supply service. In
2010, 1.2 million consumers out of a total of 8.3 million benefited from a
social tariff.

5. 
Infrastructure

5.1 
Electricity. Romania’s
power grid is not well-maintained, resulting in frequent outages, mainly in
distribution networks. Power losses are high and electricity theft is
frequently encountered. It is estimated that around 13 % of generated
power is lost for these reasons. The TSO, Transelectrica,
has planned investments of over EUR 500 million to upgrade infrastructure, and
ANRE has approved a plan to improve the transmission network from 2009 to 2017.
The improvement of interconnections with neighbouring countries is being
examined, in particular the construction of a 600 MW sub-sea cable to Turkey and the improvement of connections to Bulgaria, Hungary and Serbia. The EU Synergy Programme
helps to finance some of these improvements.

5.2 
Gas. Romania’s efforts to diversify its sources of supply are pursuing different options.
The national gas system and the ‘transit’ gas system, i.e. the pipelines
transporting Russian gas further downstream, need to be physically linked in
order to enable more diversification and to support security of supply in Romania. This measure is part of an EERP-financed infrastructure project, which also
provides for the implementation of reverse flows on these ‘transit’ pipelines.
The Szeged-Arad bi-directional interconnector to Hungary was co-financed by the
EERP. Romania is also exploring the possibility to host Nabucco and South
Stream as well as a new interconnector to Bulgaria and the
Azerbaijan-Georgia-Romania Interconnection (AGRI project), which would bring
liquefied Azeri gas to Romania across the Black Sea.

KEY INDICATORS FOR THE ENERGY MARKETS IN ROMANIA IN 2010

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

Slovakia

1. General
overview

In
2010, natural gas was the most important source in the Slovak energy mix,
replacing solid fuels, whose share has been steadily decreasing (in 1990 their
share was 37 %).

In
2010 most electricity was produced from nuclear energy. Even after the closure
of two reactors in Jaslovské Bohunice, nuclear energy
provides half of the power produced in the country. As far as renewable
energy is concerned, Slovakia's national target is to achieve a share of 14 %.[107] This
indicator improved from 6.6 % in 2006 to 9.8 % in 2010. The share of
cogeneration[108]
in electricity production was 15.9% in 2010; similarly to its share in 2005
(15.3%).

Charts 1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General. Following
the opening of infringement proceedings in September 2011 for non-transposition,
Slovakia has declared that the Third 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 Slovakian National Regulatory Authority, Úrad pre reguláciu siet’ových
odevetví (URSO), was established in 2001. In 2010 it employed 93 staff and
had an annual budget of around EUR 3 million. URSO regulates electricity, gas,
water and district heating. The budget, which is voted by the government, is
part of the global government budget. Following recent complaints, the
Commission is investigating the independence of URSO.

2.3. 
Unbundling. Since
2002, the electricity grid has been operated by Slovenská elektrizačná
prenosová sústava (SEPS), which is also the designated TSO (transmission
system operator). SEPS is 100 % state-owned and has been subject to
ownership unbundling from the generation company (Slovenske elektrarne).
The gas transmission system is operated by Eustream, a TSO that has been
functionally and legally unbundled from the incumbent Slovenský plynárenský
priemysel (SPP). Eustream is expected to be designated as an ITO
(independent transmission operator). These TSOs have not yet been certified.
The electricity distribution networks are operated by three major regional
companies: ZSE Distribúcia, Stredoslovenská energetika-Distribúcia
and Východoslovenská distribúcia, which have been legally unbundled. The
gas distribution network is operated by a daughter company of SPP and 48 local
distribution companies.

3. Wholesale
markets

3.1. 
Electricity. At the generation
level, market concentration is very high. Slovenske Elektrarne dominates
the market and accounts for 72.5 % of the electricity produced in 2010.
The other electricity producers active on the market each hold less than 5 %.

The
Slovak TSO is a member of the Common Auction Office (CAO), which groups the
eight TSOs of the Central Eastern European region. It was established to
perform common coordinated congestion management in that region and to allocate
capacities in the cross-border interconnectors. However, the actual
introduction of a new common allocation method in the region, initially planned
for March 2010, has been postponed. Since 2009, market integration has been
ensured by an effective market coupling with the Czech Republic. The
Czech-Slovak market coupling has been extended to Hungary as of 11 September
2012.

Wholesale
trading can be found in two exchanges: OKTE runs a day-ahead spot market
exchange and PXE (a subsidiary of the Prague Power Exchange) offers a future
market for Slovakian energy contracts. In 2011 the average day-ahead wholesale
price was EUR 50.9 /MWh for baseload power (an increase of 16.3 %
compared to 2010).[109]
With regard to liquidity, 3.7 TWh of day-ahead power were supplied
through OKTE, accounting for 13 % of national power consumption.

3.2. 
Gas. Slovakia
imports its entire consumption of natural gas (approx. 6.1 bcm in 2010), almost
exclusively through long-term contracts with Russian Gazprom. The incumbent
supplier SSP is the holder of most of the large import contracts. However,
today five other suppliers (RWE Gas Slovensko s.r.o., SHELL Slovakia s.r.o., VNG Slovakia spol. r.o., Lumius Slovakia s.r.o. and ELGAS s.r.o.) are active on the
wholesale market, supplying industrial users only. The market share of SSP
dropped to 84.9 % in 2010. RWE Gas Slovensko s.r.o. has a market share of
13.1 %. This means that the other four new entrants combined reached a market
share of only 2 %. Only physical entry and exit points to the gas
transmission network (Veľké Kapušany, Lanžhot, Baumgarten) or domestic off‐take
points can be used for trading in natural gas. As it is only at the Austrian
Baumgarten-hub that gas can be traded at an exchange, trading is mostly done
‘over the counter’. No wholesale reference price can be provided. Estimates of
long-term prices for Russian gas amount to an annual average of around
EUR 27.9 /MWh in 2011 (an increase of 14.7 % compared to 2010).

4. Retail
markets

4.1. 
Electricity. There
are three main suppliers in Slovakia (ZSE, SSE and VSE), which are also
vertically integrated with the distribution companies. They supply 52.1 %
of total consumption and are in a dominant position in their regional home
markets. As a result of regulated prices of supply for households and small
industrial customers, switching of suppliers is insignificant with an
overall rate of 0.82 % for households and 1.57 % for industrial
consumers.

Power
prices for households have increased in the last
couple of years, mostly as a result of the net energy price and the widespread
introduction of RES (renewable energy sources) into the national market. In
2011 the share of network costs within the household price (without taxes)
accounted for 53 % of the price, with 47% for energy and supply costs. In
the case of industrial electricity prices, these proportions were 51 % and
49 % respectively. Price regulation exists for household and small
industrial consumers, acting as a barrier to the development of competitive
supply markets for these segments.

There
is no roll-out plan for smart meters, but Slovakia notified a cost-benefit
analysis on smart meters to the Commission in September 2012.

4.2. 
Gas. Gas
prices for final consumers are volatile. It appears that the volatility of
energy commodity prices on the global market has had an influence on Slovak
retail gas prices. Prices are not regulated for industry, although they are
regulated for households with a consumption of under 6500 m3. The
fact that prices for household gas customers are regulated means that there is
no switching of suppliers. New suppliers on the Slovak market
concentrate on industrial customers, so some switching does take place in that
segment of the gas market (10.1 %).

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 in Slovakia rate their retail electricity market second highest in
the EU, with above average scores on all indicators. Trust in providers is the
second highest in the EU while comparability and overall consumer satisfaction
rank the third highest. A similar picture is observed for the retail gas market
(ranked 4th highest in the EU), with scores above the EU average on all
indicators but ease of switching. Also, overall consumer satisfaction is the
second highest in the EU. [110]
The central authorities responsible for consumer protection are URSO, the
Regulation Council and the Ministry of the Economy. URSO provides a price
comparison tool and information on consumer rights, relevant legislation
and dispute settlement options, and could therefore be viewed as acting as a single
point of contact. When consumers need assistance, they can address their complaints
to URSO. URSO settles disputes related to grid access only.

5. 
Infrastructure

5.1. 
Electricity. Slovakia
is interconnected with the Czech Republic, Hungary, Poland and Ukraine. Further interconnections with Hungary are planned. Currently, the main focus of
electricity infrastructure investment is on upgrading some of the existing 220
kV lines to 400 kV. The transmission system is affected by loop flows, most
often originating in Germany, which are passed through Poland into the Czech Republic and Slovakia.

5.2. 
Gas. The Slovak
gas network is connected with Ukraine, Austria and the Czech Republic. Slovakia also has two gas storage sites. Under the EEPR project, the Commission is
co-financing the Hungary-Slovakia interconnector which is in the planning
phase.

KEY
INDICATORS ON THE ENERGY MARKETS IN SLOVAKIA IN 2010

Sources: Eurostat, CEER, URSO (Slovak Regulatory
Office for Network Industries), 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 adding up 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 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.

Slovenia

Key Issues  ₊   An increase in cross-border capacity could help boost competition in the Slovenian power market, and could improve the market coupling mechanism with Italy. Strengthening the national electricity grid would fill infrastructure gaps and help deal with the loop flow issues. ₊   With regard to gas, Slovenia suffers from frequent contractual congestion at its border points. More effective congestion management procedures could help alleviate this problem, whilst allowing for more competition in the market. Cooperation with neighbouring countries should be enhanced. Slovenia should also upgrade its gas transmission system and implement the Recovery fund project, which would enhance cross-border gas transmission in Europe.

1. General
overview

Crude
oil and petroleum products have the largest share in the energy mix,
representing one third in 2010. Nuclear energy is also very important, with 20 %
of the energy mix and the highest percentage in the electricity mix. Hydro
power is by far the most significant source of renewable electricity (95 %
in 2010). Slovenia’s target for 2020 is to have 25 % of renewables .[111]
In 2006, it reached 15.5 %, rising to 19.8 % in 2010. The share of
cogeneration[112]
in electricity production was 6.9% in 2010, which is a slight decrease compared
to 2005 when it stood at 7.3%.

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General. Slovenia has not yet fully transposed the Third Energy Package Directives. Letters of
formal notice were sent in September 2011 and reasoned opinions followed in
June 2012. On 24 October 2012, the Commission decided to refer Slovenia to the Court of Justice for only partially transposing the two Directives.[113]

2.2. 
National Energy Regulator.
The Slovenian national regulator, the Energy Agency of the Republic of Slovenia (AGEN-RS) has been in operation since 2000. In 2011 it
employed 43 staff with an annual budget of almost EUR 3 million.

2.3. 
Unbundling. In the
electricity sector, Slovenia has one state-owned TSO, ELES, and one DSO, SODO,
that cover the entire territory. The gas grid operator is Plinovodi d.o.o.,
100 % owned by but legally independent from Geoplin since 2005. Geoplin
is the biggest gas company in the country. The Commission adopted a
certification opinion on Plinovodi in July 2012. Slovenia has opted for the ITO model. Slovenia has 16 gas DSOs, which are mainly owned by
the local communities. None of them have more than 100 000 customers and
they are not legally unbundled.

3. Wholesale
markets

3.1. 
Electricity.
Regarding generation, the state-owned group HSE has a dominant position
with a market share of 62.4 % in 2011. Together with state-owned GEN
energija (26.4 %) and TE-TOL (3.7 %), the three undertakings have
a market share of 92.5 %, forming a tight oligopoly. The small Slovenian
electricity market is situated between three regional markets with very
different energy prices. In January 2011 Slovenia implemented market coupling
with Italy but price convergence has been limited due to limited
interconnection capacity and differences in generating capacity.

The
organiser of the electricity market in Slovenia is Borzen, and BSP
Regional Energy Exchange is the Slovene power exchange. The average day-ahead wholesale
price in 2011 for baseload power was EUR 57.2 /MWh (an increase of
23.8 % compared to 2010).[114]
In terms of liquidity, 1.5 TWh were traded on the spot market,
representing 11 % of national electricity consumption.

3.2. 
Gas. In 2011 Slovenia imported 0,9 bcm of gas, of which 48% was
supplied from Russia, 23% from Algeria, 22% from Austria and 7% from Italy. These imports are mainly based on long-term contracts with Russia and Algeria. The Slovenian system is connected to the Croatian, Austrian and Italian
transmission grids. The utilisation rates are very high and congestion, both
contractual and physical, occurs frequently. Currently, the only two applicable
congestion management procedures are the offer of interruptible capacity and
the possibility to trade capacity on the secondary market.

The
largest importer, trader and supplier of natural gas is Geoplin, whose
share represents 92.8 % of all imports in 2010. The other two suppliers
are Adriaplin and Petrol Plin.

Slovenia
does not have an organised hub and therefore no reference wholesale price can
be given. Estimates of long-term prices for Russian gas give an annual average
of approximately EUR 32.2 /MWh for 2011 (7.3 % higher than in
2010).

4. Retail
markets

4.1. 
Electricity. Eight
electricity suppliers have a market share of over 5 % and all of them are
primarily state-owned. Market concentration at retail level is high and
the market share of GEN-I is the highest, at 19.9 %. In 2010, the annual
switching rate in the retail market was 1.9 % for households and 4.2 %
for the whole retail market. Power prices for domestic consumers have
increased in recent years. Apart from a higher energy price this was also a
consequence of increased taxes and duties. In 2011,
the share of network costs within the household prices (without levies and taxes)
was 47 %, while energy and supply costs accounted for 53 %. For
industrial electricity prices, the proportions were 75 % and 25 %
respectively. End-user prices are not regulated.

No
legal framework is in place to address the roll-out of smart metering, but a
cost-benefit analysis has been carried out with a positive macroeconomic
outcome.

4.2. 
Gas. Market concentration
at the retail level is high, as Geoplin had a market share of 62.2 %
in 2011. Customers can choose their suppliers. In 2011, 20 suppliers sold
natural gas to around 130 000 end customers. The number of switches
increased, but the proportion of customers who switched supplier is still very
low at less than 0.1 %.

Gas
prices for final consumers were volatile during the
observed period, mainly due to changes in the energy price. End-user prices are not regulated.

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'
overall assessment of retail gas and electricity markets is the highest and
fourth highest in the EU. Both markets are assessed above the EU average on all
indicators but actual switching. The
incidence of problems is much lower than in other countries (the lowest EU wide
in the case of gas market) and complaints are less numerous too (3rd lowest for
both markets). In retail gas market, comparability, trust in providers and
overall consumer satisfaction are within the 3 highest ratings in the EU. [115] The
NRA introduced the on-line price comparability tool  for electricity in
2007 and for gas in 2011. As defined by the Energy Act, the NRA decides on
disputes mainly rising between customers and distributors; while complaints
between consumers and suppliers are handled by a mediator.

5. 
Infrastructure

5.1. 
 Electricity. Slovenia has cross-border
interconnections with Austria, Croatia and Italy. An interconnector with Hungary is under construction and the current interconnector capacity with Italy should be expanded as Slovenia's importance as a transit country increases. Slovenia has hydro power plants, thermal power plants and one joint nuclear power plant with Croatia in Krško. Slovenia’s high generation load factor is the result of the high
performance of Slovenia’s hydrogeneration plants. Slovenia received financial
support from the European Commission for trans-European Energy networks (TEN-E
projects).

5.2. 
Gas. In
2011, investments of EUR 75.9 million were made in the gas
transmission network. The trend in demand over a 10-year range shows a strong
increase. This has led to substantial congestion, which Slovenia needs to resolve by improving its use of existing infrastructure through congestion
management and by building additional capacity. Slovenia receives financial
support in the framework of the Recovery Fund to upgrade its gas transmission
system between the Slovenian-Austrian border and Ljubljana.

KEY
INDICATORS ON THE ENERGY MARKETS IN SLOVENIA IN 2010

Remark: latest figures from the National
Regulatory Authority show an increase in the number of main gas retailers (5 in
2011).

Sources: Eurostat, CEER, Energy Agency of the Republic of Slovenia.

(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.

Spain

1. General
overview

The
highest share in the energy mix came from crude oil and petroleum products. In
the electricity mix, the shares were more equally divided between natural gas,
renewables and nuclear energy. The share of renewable electricity was above 33 %,
mainly hydro and wind. In 2010 Spain was the country with the highest wind
energy output in the EU (16 %). As far as the 2020 goal is concerned, Spain’s national overall target is to achieve a share of 20 % energy from renewable
sources.[116]
This share improved from 9.4 % in 2006 to 13.8 % in 2010. The share
of cogeneration[117]
in the overall electricity production was 7.4% in 2010, being close to the
share measured in 2005 (7.4%).

Charts
1 and 2

Source:
Eurostat.

2. 
Regulatory framework

2.1. 
General. After
the Commission launched an infringement procedure for non-transposition in
September 2011, Spain has notified full transposition of the Directives of the
Third Energy Package.

2.2. 
National Energy Regulator.
The Spanish National Energy Regulatory Authority, Comisión Nacional
de Energia (CNE), which has been in operation since 1998, employed 213
staff in 2010 with a budget of almost EUR 30 million. The CNE is a public body
with its own legal personality and the capacity to act independently. In March
2012 the Spanish Government presented a proposal to merge the Spanish
competition authority and various national sector regulatory bodies, including
the energy regulator, into a single organisation. In the area of energy, Spain must ensure that the designated authority has the powers and duties required by the
Directives of the Third Energy Package and that it fulfils the criteria for
independence.

2.3. 
Unbundling. The TSO
(transmission system operator) in electricity is Red Eléctrica de España
(REE). In 2010 Endesa, Gas Natural Fenosa and EDP-Hidrocantábrico
sold their remaining transmission assets to complete the process of
establishing REE as the sole, ownership unbundled TSO. Following the recent
sale of gas transmission assets to ENAGAS, the main gas TSO that possesses the
majority of transmission network assets, CNE issued the final certification
decisions, in line with the model of ownership unbundling, in July 2012. The
electricity and gas DSOs (distribution system operators) are legally and
functionally unbundled.

3. Wholesale
markets

3.1. 
Electricity. In 2010
there were five major groups competing in the market at the generation
level: Iberdrola (24.3 %), Endesa (19.6 %), Gas natural Fenosa (15 %),
EDP-Hidrocantábrico (5.3 %) and E.On (3.5 %). Furthermore, the
overall share of generation in the so-called ‘special regime’ -  RES (renewable
energy sources) and CHP (combined heat and power) - of other groups amounted to
25.9 %. Spanish and Portuguese day-ahead and intraday electricity markets
have been fully integrated in MIBEL (Iberian electricity market) since July
2007. While interconnection capacity has been increasing significantly across
the Pyrenees (from 3 % to 6 %), interconnection capacity between Spain and France is still scarce, limiting cross-border trade and undermining security of supply. In
2010 Spain was a net exporter of electricity, including to France. The degree of congestion in the Portuguese-Spanish interconnection has been strongly
decreasing each year and in 2011 was at 9 %. The energy traded in the
power futures markets during 2011 amounted to 32.9 TWh in the OMIP market and
284.1 TWh in the OTC market, a total of 317 TWh (+ 12 % compared to 2010).
In 2011 the wholesale price for day-ahead baseload power was
EUR 49.9 /MWh on average (an increase of 35 % compared to 2010).[118] It was lower
compared to many other EU countries because Spain has a very favourable
electricity mix, which allows it to produce at lower costs (also taking
advantage of mature renewable technologies). On the Iberian power exchange OMIE
182.29 TWh of day-ahead baseload power were traded in Spain in 2011 (72 % of power consumption). The rest of energy was traded on the OMIE intraday
market.

Spain
should adopt strict measures to eliminate the tariff deficit. The measures
adopted in March 2012 included reducing regulated costs in the electricity
sector and an increase in tariffs. Further increases in taxes related to
electricity generation and consumption of fossil fuels were proposed in
September 2012. However, these measures should be followed up by further reform
of the energy sector to improve cost effectiveness of electricity generation
and supply activities and provide a stable and certain legal framework for
investors. The reform of the electricity sector should include the gradual
phasing out of the regulated tariff system. Moreover, market rules must
incentivise decentralised generation, while renewables support scheme should be
adapted in a predictable way, with the view to reflect falling production costs
and learning curve gains. The infrastructure investment plan must be revised to
reflect updated supply and demand forecasts in order to avoid underutilising
assets.

3.2. 
Gas. In 2010
  Spain imported 36.7 bcm of natural gas to satisfy its entire consumption. The
three main supplier countries were Algeria (33 %), Nigeria (20 %) and Qatar (16 %). Typical for Spain is a wide diversification of sources
(up to 14 countries) and high import capacities for LNG (76 % of imported
gas in 2010 was LNG and the rest was pipeline gas). No reference wholesale
price can be given because there is no organised hub. However, based on
monthly average import prices, an annual average of EUR 18.5 /MWh for
imported gas is estimated for 2010. Compared to EUR 19.0 / MWh on the
French hub PEG Sud, this appears to be a reasonable estimate, as Spain can take advantage of the variety of its sources and its proximity to the North
African gas fields.

In
the absence of a gas hub, most of the wholesale trade materialises through
bilateral OTC transactions that are reported to the TSO balancing platform with
high liquidity. Traded volumes reached 1004.7 TWh, while consumption was around
400 TWh.

A
postitive development is the publication by CNE in April 2010 of a roadmap to
develop a gas hub (Mibgas) in the for the Spanish and Portuguese markets with a
view to promoting greater transparency and competition in the wholesale market.[119] This roadmap
should be implemented without delay.

4. Retail
markets

4.1. 
Electricity. Spanish
consumers' rating of the performance of their retail electricity market is the
second lowest of all EU countries in terms of trust in providers and
comparability. The retail gas market scores below the EU average on most
indicators, such as trust, comparability, overall satisfaction and choice. [120]
Market concentration at retail level has not changed significantly, but
each supplier's share of the liberalised market has changed as Endesa decreased
its share to the benefit of Iberdrola. The majority of Spanish consumers
(almost 20.8 million out of 27.7 million) are still supplied by last-resort
suppliers at regulated tariffs. Endesa and Iberdrola account for around 80 %
of these customers. Nonetheless, all consumers in Spain can freely choose their
electricity supplier. There has been a significant and steady increase in the
observed switching rate (from 5.2 % in 2009 to 7.4 % in 2010 and 10.6 %
in 2011). More than 70 % of all switches correspond to movements from the
last-resort tariff to the free market. In the period from July 2009 to
December 2011, around 4 million customers switched from last-resort supply to
the liberalised market, as the result of a stimulation policy which introduced
a fee on top of the last‑resort tariff. However, there is still a gap
between tariff incomes and regulated costs, causing a tariff deficit.

Power
prices for households increased considerably between 2008 and 2011. From July
2009 to July 2012, grid charges increased by 25 %, and the energy
component by 28 %. The industrial price increase was more moderate. In
2011, the share of network costs[121]
in the household price (without taxes) accounted for 45 %, while energy
and supply costs accounted for 55 %. In the case of industrial electricity
prices, the proportions were 30 % and 70 % respectively. End-user
price regulation exists for households below 10 kW of contracted capacity (the
aforementioned last-resort tariff).

Spain
has not published a cost-benefit analysis of smart meters. Nevertheless, its
2007 substitution plan for end-users up to 15 kW calls for a full rollout of
smart meters by the end of 2018. Large-scale deployment of smart meters has
started.

4.2. 
Gas. By the
end of 2010, approximately 4.2 million consumers were supplied at a free market
price (58 % of all consumers). In all, 834 115 customers have
switched, more than double the number in 2009. The gas switching rate is
very high, increasing from 11.6 % of customers in 2010 to 19.5 % in
2011.

Gas
prices, as reported by Eurostat for reference customers, decreased after 2008
for households and industry, reflecting a similar pattern in global oil and gas
markets. End-user price regulation exists for households only and not for
industrial consumers. Regulated tariffs apply to households consuming less than
50 000 kWh/year and connected to a network at a pressure below 4 bars.

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. Spanish
consumers rate the performance of their retail electricity market third
lowest of all EU countries. The scores on trust in providers and comparability
are second lowest in the EU while the incidence of problems and consumer
complaints are second and third highest, respectively. The retail gas
market is ranked third lowest in the EU, with the highest incidence of consumer
complaints across EU countries.[122]
This is most likely linked to aggressive (and sometimes fraudulent)
marketing sales practices denounced by consumers associations. Since
2011, CNE provides an on-line price comparability tool for
electricity and gas prices as well as information on the rights of customers,
complaints procedures, suppliers and prices of the offers on the market. There
is no single contact point in place. CNE has recently been asked to ‘report,
attend to and process consumers ́ complaints, in coordination with
competent regional and local Administrations. CNE also settles disputes
related to access to the grid. Electricity and gas suppliers can join the ‘Juntas arbitrales de consumo’, which acts as
the alternative dispute resolution scheme and is managed by the regional
administration. However, only a few companies participate in this scheme. Since
2009, social laws classify vulnerable electricity customers in three
household categories: (i) large families; (ii) pensioners (over 60, with
low-income); and (iii) households where all members are unemployed.

5. 
Infrastructure

5.1. 
Electricity. Power
generation capacity (100 GW) in Spain by far outweighs the country’s current
peak demand (44 GW). Strong government support for renewables generation in
combination with the sudden and deep economic crisis have led to this situation
of overcapacity. In terms of cross-border transmission capacity, Spain is increasingly well connected to Portugal but congestions still occur. Cross-border capacity
was increased in 2011 and projects are planned to further increase available
capacities up to 3000 MW in 2015. The capacity on the French border, which is
still allocated via an explicit auction, is much lower (around 3 % of the
peak demand). Spain and France are developing the Baixas (FR) — Santa Llogaia
(ES) interconnector that should become operational in 2014. The EU is supporting
the project in the context of the EEPR and EUR 225 million have been
granted to the Spanish (REE) and French (RTE) TSOs for its construction.

5.2. 
Gas. Spain
has six LNG terminals and a seventh will be ready for use in 2013. The
transmission system is connected to Algeria and France via pipelines. In April
2011, the 8 bcm Medgaz pipeline between Spain and Algeria entered into
operation. Spain is reinforcing its level of interconnection with France, in particular at the Biriatiu and Larrau points (with support of EUR 45 million
from the EEPR programme), which should be operational by 2013-2014. Further
increases of capacity with France and Portugal should be considered to promote
the export of gas to neighbouring countries and develop a liquid and competitive
regional gas market in South-West Europe. Spain has 3 underground gas storage
sites (Serrablo, Yela and, since 2012, Marismas) that are an important source
of flexibility and security of supply. Two further underground storage sites
(Yela and Castor) are under construction.

KEY INDICATORS ON THE ENERGY MARKETS IN SPAIN IN 2010

Sources: Eurostat, CEER,
CNE (Comisión Nacional de Energía).

(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 adding up 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 import).

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

Sweden

1. General
overview

In
2010, a third of the energy mix originated from renewables (RES). The most
important source was biomass, which accounted for about two-thirds of
renewables. In the electricity mix, renewables accounted for an even higher
share. Hydro power plants produced over 80 % of renewable electricity. Sweden’s target for 2020 is to have 49 % of RES in gross final energy consumption.
This share improved from 42.4 % in 2006 to 47.9 % in 2010. The share
of cogeneration[123]
in electricity production was 12.9% in 2010, showing a significant increase
compared to the level of 6.7% in 2005.

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General.
Following the opening of infringement cases for non-transposition in September
2012, Sweden 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. One infringement
procedure is still open on the Second Package, concerning the lack of
congestion management and a transparency provision concerning access to the
network for cross-border exchanges in electricity.

2.2. 
National Energy Regulator.
The Swedish regulator, Energy Market Inspectorate (EI), has been in operation
since 2008, employing 95 staff with an annual budget of around EUR 11 million.
Despite being an agency administratively attached to the Ministry of
Enterprise, Energy and Communication, it is an independent NRA with
satisfactory powers.

2.3. 
Unbundling. Svenska
Kraftnät is the TSO for electricity and Swedegas for gas. Both TSOs
have been certified under the ownership unbundling model. In electricity, 170
DSOs are functionally unbundled, and in gas, six.

3. Wholesale
markets

3.1. 
Electricity. The
Swedish wholesale power market is part of the integrated Nordic power market.
In 2010, electricity production was dominated by three companies, Vattenfall,
Fortum and E.ON, that together controlled 80 % of generation. However,
thanks to the connection with Nord Pool, the actual number of players active on
the wholesale market is higher. The three incumbents have joint ownership of
nuclear power plants, and the Swedish Competition authority is concerned by the
inherent risk of information being shared between sites, diminishing confidence
in a functioning market. This problem has been addressed by the energy
regulator, which forced the owners of nuclear power stations to agree on common
ethical rules. However,  the risks arising from links among major competing
producers still remain and the authority should go on monitoring the situation,
intervening when necessary. Nord Pool Spot is the common Nordic market place
with which the Swedish wholesale power market is integrated and
where three-quarters of Nordic electricity is traded. New interconnections
using market coupling between the Continent and Nordic countries (Baltic Cable
and SwePol Link) will likely increase continental influence on the Nord Pool
system price. This is seen as the first step towards Europe-wide market
integration. The average wholesale price in 2011 was
EUR 48.4 /MWh (a decrease of 12.6 % compared to 2010).[124] In terms of liquidity,
volumes traded on Nord Pool Spot are the highest on European power exchanges.
Swedish volumes reached 131 TWh, 94 % of national electricity consumption.

3.2. 
Gas. Sweden does not produce natural gas. In 2010 it imported all of its requirements, about 1.5
bcm, through the pipeline from Denmark. The Swedish network works as a distribution
system for gas consumers. Sweden has around 37 000 end-users, of whom
approximately 3 600 are business customers and the remainder domestic. At wholesale
level, two operators are active, E.ON Sverige and Dong Energy. There is no
wholesale market hub as all gas is imported. To gain access to the Swedish
market, a supplier needs to acquire transmission capacity on the Danish
interconnector, given that capacity can only be booked as exit capacity from
the Danish system. There is currently no congestion on the grid, either
nationally or in the import link from Denmark.

4. Retail
markets

4.1. 
Electricity. The
same three incumbents in the wholesale market hold about half the retail
market. This, unlike the wholesale power market, is national in scope. In 2010,
there were 121 electricity suppliers, though smaller players have occasionally
found it difficult to enter the market. Switching of suppliers is high.
Around 11 % of all domestic customers switched their electricity supplier
in 2010. In addition, 24 % of consumers re-negotiated their contract with
their current supplier. Thus, 35 % of all domestic customers took an
active part in the retail market during 2010. After a drop in 2009, power
prices for Swedish households and industry rose in subsequent years. This
was mainly due to higher energy prices. In 2011, network costs in the final
price for households (without taxes) accounted for 52 %, while energy and
supply accounted for the remaining 48 %. For industry, these shares were
33 % and 67 % respectively.[125]
The correlation analysis shows the wholesale price had a significant
influence on the retail price, which is not regulated. By 2009, Swedish DSOs
were obliged to provide monthly meter readings to household customers and
hourly readings to commercial and industrial customers. This resulted in
practically a full roll-out of smart meters, enabling remote readings.
However, most meters are not suitable for hourly readings without additional
investment. Hourly readings are needed for demand response services. As of
October 2012, DSOs are obliged to provide hourly meter readings to households
requesting them.

4.2. 
Gas. In
2010, there were five natural gas suppliers. The three largest companies, E.ON,
Dong Energy and Göteborg Energi, held around 90 % of the market. The
Swedish gas retail market consists of around 34 000 domestic customers. It has
been a free market since 2007. During 2010, 266 of these households switched
suppliers, fewer than in the previous year. The total number of switches
continues to remain low, equivalent to about 1 % of the total number of
domestic customers. This may be due to the small size of the gas market, which
does not incentivise suppliers to competition. End-user prices are not
regulated. Gas prices for final consumers moved in line with global gas
and oil prices. Both households and industry pay high taxes, amounting to
almost half the retail price.

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’ overall assessment of retail electricity market is
below EU average (22nd place out of 27), with particularly poor
score on comparability, trust in providers and consumer satisfaction. The
number of problems reported in the electricity retail
market is lower than the EU average but complaints are more numerous. The
scores for choice and switching are significantly above the EU average (highest
and third highest in the EU).[126]
In 2008, EI launched an on-line electricity price comparison site,
which enables consumers to compare prices, terms, and conditions for all
Swedish suppliers. For gas, there is no single price comparison site. The Alternative Dispute Resolution system
(named Allmänna Reklamations Nämnden) is managed by EI. As of 2011,
there is a definition of vulnerable consumers in the national
legislation. Protection of vulnerable consumers is regulated within the general
social welfare acts and recognised by municipalities, which can also provide tax rebates and benefits.

5. 
Infrastructure

5.1. 
Electricity. High
volumes of hydroelectric power need to be transported from the north to the
south. There is at times significant congestion between the two regions.
Congestion within the national grid is generally associated with high
hydropower generation in the north, which results in pressure to transmit power
southwards, where consumption is concentrated. When low reservoir levels
coincide with unplanned outage of nuclear power plants, which was the case in
January 2010 and 2011, price spikes are likely to occur. This increases the
need for reinforced interconnections that reduce congestion within Sweden and between Sweden and neighbouring countries. Enforcing competition rules also enabled the
creation of four bidding zones in Sweden, contributing to more efficient
management of congestion. This helped to avoid abuse of a dominant position by Svenska
Kraftnät, the national TSO.[127]

5.2. 
Gas. Sweden
has a relatively small gas market, but the fact that it is only interconnected
to Denmark makes it vulnerable to disruption. Sweden is currently exempted from
the N-1 obligation set out by Regulation 994/2010 concerning measures to
safeguard security of gas supply. One possible route for diversification could
be the Skanled pipeline running from Norway, although the fate of this project
is currently uncertain. Sweden has no significant storage facilities, and needs
to rely on foreign storage to balance seasonal swings in demand.

KEY
INDICATORS ON THE ENERGY MARKETS IN SWEDEN 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 import).

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

The United Kingdom

Key Issues ₊   As recommended by the Council, the UK should improve the capacity of its network infrastructure. ₊   With regard to electricity, the United Kingdom (UK) needs substantial investment to decarbonise its electricity generation while minimising the market distortions introduced by the electricity-market reform, ensuring in particular that state intervention is limited to what is necessary and proportionate, and that price signals can continue to be the driving factor in operational decisions for generators. The UK should facilitate the development of additional interconnectors to enhance security of supply and market integration in particular against the background of higher shares of variable wind power in the UK system. ₊   The UK should focus more on the transparency of important data and on non-discriminatory third-party access to essential infrastructure such as IUK. ₊   The UK should complete the integration of Northern Ireland within the internal gas and electricity market by ensuring that internal-market rules are fully applied.

1. General
overview

Fossil
fuels play a dominant role in the energy consumption mix. In 2010, natural gas
had a 39.9 % share of the energy consumption mix, which was the
second-highest share among EU countries after the Netherlands. Renewable energy
sources (RES) played a less important role in the energy mix (with a share of
only 3.2 %). Power generation (in total 381.1 TWh in 2010) in the UK was also dominated by gas-fired power plants (with a share of 46.2 %) and to a
lesser extent by solid fuels (28.3 %). RES represented 7.6 % of total
power production in 2010. The country’s 2020 RES target for the whole energy
sector is 15 %, which is lower than the EU-27 average (20 %). Between
2006 and 2010 the share of RES grew slowly (from 1.5 % to 3.2 %). The
share of cogeneration[128]
was 6.2% in 2010, showing a slight decrease since 2005 when it was 6.8%.

Charts
1 and 2

Source:
Eurostat

2. 
Regulatory framework

2.1. 
General.
Following the opening of infringement proceedings in September 2011 for
non-transposition, the UK has still notified only partial transposition of the
Third Energy Package Directives. In addition, two infringement procedures are
still open under the Second Package. These concern: i) the lack of transparency
concerning conditions for third-party access to natural-gas-transmission
networks;[129]
and ii) the lack of congestion-management and transparency provisions
concerning access to the network for cross-border exchanges in electricity.
These relate to the rules applying in Northern Ireland.

2.2. 
National Energy Regulator.
For Great Britain (GB), the national regulatory authority, the Office of Gas
and Electricity Markets (OFGEM), has been in operation since 2000; it employed
441 staff in 2011 with an annual budget of almost GBP 79 million. Ofgem is a
well-established and effective regulator. The Northern Ireland Authority for
Utility Regulation (UREGNI) has been designated as the regulatory authority for
  Northern Ireland.

2.3. 
Unbundling.
National Grid owns and manages the electricity transmission network in England and Wales. The Scottish electricity network is owned by SP and SSE. Northern Ireland’s electricity grid is owned by Northern Ireland Electricity (NIE) and
operated by SONI. The high-pressure distribution
network in GB is owned and operated by National Grid Gas plc (NGG); the
low-pressure network is owned and operated by local distribution companies. Bord
Gáis Éireann and Mutual Energy own the gas-transmission
assets in Northern Ireland. National Grid
companies have been certified as full unbundled ownership, and the Scottish companies
(SP and SSE) have been certified under Article 9(9) of the Electricity
Directive.

3. Wholesale
markets

3.1. 
Electricity. At
the generation level, the combined market share of the three largest
utilities (EDF Energy, E.ON, Drax) in 2011 was 44 % by metered volume of
power generation, implying a moderate level of concentration. The UK needs substantial investment to upgrade its electricity generation capacity, given the
need to replace much of the existing generating capacity as a result of
closures over the next decade and the need to meet the renewable-energy and
carbon targets. To address this challenge, the UK Government is currently
preparing proposals for Electricity Market Reform (EMR). Following a white
paper published last July, draft legislation was published in May this year
that is likely to be laid before Parliament before the end of 2012. The
EMR aims to facilitate the transition to a low-carbon economy while maintaining
secure and affordable energy supplies. The proposals call for the UK Government
to set the prices that each new renewable technology will receive in the energy
market via feed-in tariffs with so-called ‘contracts for difference’. The
implementation of a national carbon-price support (CPS) mechanism and an
emissions-performance standard (EPS) on new fossil-fuel plants in addition to
the existing EU Emission Trading System (ETS) further aims to support the
decarbonising of electricity generation. The UK Government aims to ensure
security of supply by designing a capacity market to come into effect in the
future if capacity margins are found to have fallen below sufficient levels. It
is essential that the interventions ensure the creation of a stable and
effective regulatory environment and that they are limited to what is necessary
and proportionate. Measures must be compatible with the internal market as well
as EU state aid rules.

There
are three different exchange providers operating in the UK electricity market: the APX UK, the Nasdaq OMX N2EX and the Intercontinental Exchange
(ICE). The latter mainly focuses on trading in future contracts. On the APX
Power Exchange, wholesale power traded in the intraday market reached
18.6 TWh in 2010. The APX Day Ahead auction was
relaunched in April 2011 with the commissioning of the BritNed interconnector
that links the British and Dutch power markets.
In 2011 the traded volume in the APX Day Ahead auction was 2.5 TWh.
Trading on the N2EX exchange started in January 2010. During the first full
year of operation, the amount of day-ahead traded contracts was 2.6 TWh. In
2011, the amount of day-ahead auctions on the N2EX exchange reached 18.7 TWh.
It is also worth noting that only 8.5 % of power trading was carried out
on power exchanges. The bulk of the power was traded over-the-counter (OTC). In
2011, the average day-ahead power price in the UK was EUR 56.5 /MWh,
higher than other European countries in the Central-West region. The market
liquidity churn rate[130]
in the electricity market was 3.1 in 2011, slightly down from 3.4 in 2010.

3.2. 
 Gas. The UK is the largest gas market in Europe with an annual demand of around 84.9 mtoe in 2010. The UK is one of the most important natural gas producers in the EU; however, domestic
production is declining. In 2010, the country’s net annual production was approximately
51.5 mtoe. Imports amounted to 53.8 bcm (45.6 mtoe) with 48.5% coming from Norway and 27% from the United Arab Emirates. There were four companies involved in gas production
in 2011 with a market share greater than 5 %. The three largest gas producers
covered 50 % of the market with available gas[131] in 2010,
implying a moderate market concentration. Trade on the wholesale market
consists of both over-the-counter (OTC) trading (through brokers and
off-market) and exchange trading. It takes place on the virtual trading hub
NBP, which is by far the most liquid hub in Europe. In 2011, the average NBP
hub price reached EUR 22.1 /MWh, which was higher than the average of the
previous year (EUR 16.9 /MWh), mainly due to an increase in global LNG
demand and a rise in energy-commodity prices. The churn rate was 11.6 in 2010
and in 2011 it rose to 14.5.

4. Retail
markets

4.1. 
Electricity. The
British retail electricity market has been open to competition since the late
1990s. At the end of 2011, there were 13 domestic and 24 non-domestic suppliers
active in the market. The domestic retail market is characterised by the
existence of six large, vertically integrated suppliers (the ‘Big 6’), which
account for 99 % of the market. These are British Gas, E.ON UK, EDF Energy, RWE npower, Scottish and Southern Energy (SSE), and Scottish Power. All of
the Big 6 suppliers have a market share of above 10 %. Market
concentration at domestic retail level was moderate, yet the incumbent
regional supplier from 'prior to electricity privatisation' remains dominant.
The three largest companies covered 61 % of the domestic retail market.
The number of customers that switched supplier was among the highest in Europe at 15 % in 2011. In 2011, energy and supply costs accounted for 78 % of retail
power prices (without taxes) in the case of household consumers and the
remaining 22 % were network costs. For industrial consumers, the
distribution of energy supply and network costs was similar at 74 %-26 %.
The high energy and supply costs could be explained by higher UK wholesale prices compared to the northern and western parts of Europe. The British government has
decided to replace all of the nation’s 53 million gas and electricity meters
with smart meters. The large-scale rollout, executed by energy
suppliers, starts in 2014 and is scheduled to be completed by 2019.

4.2. 
Gas. The
British retail gas market is fully liberalised. At the end of 2011, 13 domestic
and 30 non-domestic gas suppliers were active in the market. The so-called ‘Big
6’ suppliers supply 99 % of the 22.3 million domestic consumers. British
Gas is still the largest party active on the domestic market, with a market
share of around 41 %. Market concentration at the domestic retail
level remained highand the incumbent regional supplier from 'prior to
electricity privatisation' remains dominant. The three largest companies
covered 71 % of the domestic retail market at the end of 2011. There
is a strong correlation between wholesale gas prices on the NBP hub and retail
prices in the UK for both industrial and household prices. In 2011, more than
3.2 million domestic gas customers changed their supplier (on average
around 280 000 each month). The switching rate for the year was 15 %,
which is the highest figure in Europe. In 77 % of cases, price was the
main motivation for switching.

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.
Consumer overall assessment of retail electricity market is above the EU
average (13th place out of 27) but fell in the UK between 2010 and 2012. The assessment of the retail gas market is worse than the EU
average (18th place out of 23). Both markets have above average
scores for choice, ease of switching and actual switching. In the gas market,
choice and actual switching rank second and third highest in the EU.[132] Nevertheless, while
switching rates are among the highest in Europe, they have decreased compared
to previous years (22% in 2006 and 17% in 2010)[133]
and between 40-60% of consumers are considered to be disengaged, with only
5-10% being proactively engaged[134].
As a result – according to estimates by national consumers' associations -
consumers are collectively missing out on £4billion a year from not being on
the best deals. To help consumers find the best deal, the consumers'
association set up and run an independent accreditation system for price
comparison tools, which in UK are run by private companies. A single
contact point was recently introduced (April 2012); other sources for
advice on energy efficiency and heating are also available. . As far as complaint
handling is concerned, consumers are advised to contact their energy
companies directly. If the query to the energy company is not resolved within
eight weeks, the consumer can then contact the Energy Ombudsman, who acts as an
alternative dispute resolution point. GB grants ‘vulnerable consumers'
electricity-bill rebates, protection from disconnection in winter,
benefit-entitlement checks, debt advice, and free or low-cost energy-efficiency
measures..

5. 
Infrastructure

5.1. 
 Electricity. The East-West
Interconnector between Ireland and the UK, was inaugurated on 20 September 2012
and doubles the interconnection capacity between the two systems. The 1000 MW
HVDC link between UK and The Netherlands started operating in 2011. The need to
establish additional interconnectors with continental Europe has been
recognised and Ofgem is currently developing a new regulatory framework for
interconnection to support cross-border development. It should be closely
monitored whether the new framework delivers effects.

5.2. 
Gas. No
further plans for development of gas connections with the continent are
foreseen in the near future. However, the UK should continue to cooperate with
its neighbours to ensure effective congestion management and maximize the
commercially available capacity on existing interconnectors.

KEY INDICATORS ON THE ENERGY
MARKETS IN THE UK 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 natural gas (indigenous production).

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

[1]       The data in this section refers to consumption band DC for
households [annual consumption 2.500 KWh - 5.000 KWh] and IC for industry
[annual consumption 500 MWh - 2000 MWh].

[2]       Consumption band Dc, all taxes included.

[3]       Consumption band Ic, all taxes included.

[4]       More detailed country-specific information can be found in
Part III of this publication.

[5]       Note that industrial consumer prices are quoted without VAT
due to the fact that industrial consumers recover VAT payments.

[6]       This is the share of renewables in Gross Final Energy
Consumption.

[7]       The share of electricity produced in combined heat and power
plants (CHP).

[8]       Austrian power is also traded together with German power on
EPEX Spot. For information on prices please see the chapter on Germany.

[9]       For a comparison with wholesale prices in neighbouring
countries, please refer to Table 9 in the Staff Working Document on Energy Markets
in the EU part 2.

[10]     The reporting methodologies differ among hubs, so volumes are
not entirely comparable across them.

[11]     European Consumer Markets Monitoring Surveys, http://ec.europa.eu/consumers/strategy/cons_satisfaction_en.htm

[12]     The share of electricity produced in combined heat and power
plants (CHP).

[13]     Production plus imports minus exports and changes in stocks.

[14]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[15]     The share of electricity produced in combined heat and power
plants (CHP).

[16]     The matter was referred to the Court of Justice by the College of Commissioners in November 2011 (see IP/11/1437). In concrete terms, the
Commission considers that Bulgaria does not offer interruptible backhaul
capacity at all interconnection points. The inclusion of backhaul capacity is
essential to use the network to its maximum capacity. Moreover, interruptible
capacity and short-term services are vital for newcomers to enter the market.

[17]     According to SEWRC, regulated prices have applied since July
2012 to household consumers and enterprises with less than 50 employees, and an
annual turnover below BGN 19.5 million, which have not selected another
supplier or have left the electricity market.

[18]     8th Consumer Markets Scoreboard, 2012, European Commission, DG SANCO,
http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[19]     The share of electricity produced in combined heat and power
plants (CHP).

[20]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[21]     This is the share of renewables in Gross Final Energy
Consumption.

[22]     The share of electricity produced in combined heat and power
plants (CHP).

[23]     For a comparison with wholesale prices in neighbouring
countries, please refer to Table 9 in the Staff Working Document on Energy
Markets in the EU, part 2.

[24]     European Consumer Markets Monitoring Surveys, http://ec.europa.eu/consumers/strategy/cons_satisfaction_en.htm

[25]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[26]     This is the share of renewables in Gross Final Energy
Consumption.

[27]     The share of electricity produced in combined heat and power
plants (CHP).

[28]     For a comparison with wholesale prices in neighbouring
countries please refer to Table 9 in the Staff Working Document on Energy
Markets in the EU, part 2.

[29]     The GTF serves as a delivery point for the OTC market, whereas
the NPTF is a delivery point for the Danish gas exchange, Nord Pool Gas (NPG).

[30]     Another important component is the public service obligations
(PSO) tariff. This tariff mostly covers subsidies for renewable generation,
which in turn are linked to the Nord Pool price. The net energy price itself is
also linked to the price on Nord Pool, where most of Denmark’s power
consumption is traded.

[31]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[32]     These projections do not take account of recent developments in
  Germany, where production from nuclear plants will possibly be reduced in the
future, increasing the need to tackle the challenges posed.

[33]     The share of electricity produced in combined heat and power
plants (CHP).

[34]     Estonian power is also traded on the Baltic power exchange
BaltPool in Lithuania, although no data on Estonian volumes and prices alone
are available.

[35]     For comparisons with wholesale prices in neighbouring
countries, please refer to Table 9 in the Staff Working Document on Enerhy
Markets in the EU, part 2.

[36]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[37]     The share of electricity produced in combined heat and power
plants (CHP).

[38]     Nord Pool is the common power exchange for the Nordic countries
and runs the largest electricity market in the world.

[39]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[40]     This is the share of renewables in Gross Final Energy
Consumption.

[41]     The share of electricity produced in combined heat and power
plants (CHP).

[42]     French law No 2010-1488 of 7 December 2010 (Nouvelle Organisation du
Marché de l’Electricité).

[43]     Annual average day-ahead baseload power prices. For comparison
to wholesale prices in neighbouring countries, please see Table 9 in the Staff
Working Document on Energy Markets in the EU part 2.

[44]     CRE Activity Report 2011.

[45]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[46]     This is the share of renewables in Gross Final Energy
Consumption.

[47]     The share of electricity produced in combined heat and power
plants (CHP).

[48]     See European Commission, press release IP/08/1774, Antitrust:
Commission opens German electricity market to competition, 26.11.08.

[49]     However, this figure does not take into account subsidised
renewable electricity production. If this is included, the four accounted for
around 70 % of generation in 2010.

[50]     Germany and Austria form one trading area.

[51]     Source: EEX annual report.

[52]     For a comparison with wholesale prices in neighbouring
countries, please refer to Table 9 in the Staff Working Document on Energy
Markets in the EU, part 2.

[53]     Nonetheless, the 47,110 GWh traded on the EEX for spot and
futures products was less than 3 % of OTC trading. In parallel, there was
strong growth in OTC trading, so the volume traded on the EEX hardly changed in
percentage terms.

[54]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[55]     This is the share of renewables in Gross Final Energy
Consumption.

[56]     The share of electricity produced in combined heat and power
plants (CHP).

[57]     Greece has to privatise parts of its shares in PPC in the
coming months.

[58]     The final unbundling solution in gas depends on the way DEPA
will be privatised, i.e. as an integrated company or in an unbundled way.

[59]     In the Greek mandatory pool, all power trading is compulsorily
carried out through the pool, LAGIE, the new market operator (as opposed to
bilateral trading between buyers and sellers on other markets).

[60]     Source: Platts. Annual average day-ahead baseload power prices.
For a comparison with wholesale prices in neighbouring countries, please see
Table 9 in the Staff Working Document on Energy Markets in the EU, part 2.

[61]     At the beginning of 2012, the licenses of the two main
competitors of the incumbent supplier, PPC, were suspended following criminal
investigations and the freezing of the bank accounts of these suppliers.

[62]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[63]     The bodies responsible for the dispute settlement of
consumer complaints are: a) The Greek Ombudsman, b) The General Consumer’s
Secretariat of the Ministry of Employment & Social Security — the only one
with the power for legally binding decisions and recommendations and c) Local
non-governmental consumer organisations, which are overseen by the Hellenic
Consumer's Ombudsman.

[64]     These are customers in remote areas, in
particular non-interconnected islands, who are entitled to special services
both in terms of price and in terms of quality and security of supply and
transparency of contractual terms and conditions compared with other customers.

[65]     This is the share of RES in Gross Final Energy Consumption
(2020 target indicator).

[66]     The share of electricity produced in combined heat and power
plants (CHP).

[67]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[68]     This is the share of renewables in Gross Final Energy
Consumption.

[69]     The share of electricity produced in combined heat and power
plants (CHP).

[70]     The decision for referral of the matter to the Court of Justice
has been taken by the College of Commissioners in January 2012 (see IP 12/52).
In concrete terms, the Commission considers that, in violation of EU gas rules,
the maximum interconnection capacity is not offered in the UK and Ireland as the pipeline connecting Northern Ireland and Ireland is not open to the market.
This means that gas companies in Ireland cannot directly trade gas with Northern Ireland or vice versa. On the pipeline connecting Scotland to Northern Ireland short-term services are not available and neither is virtual reverse flow
capacity based on netting off physical forward flow to make capacity available
for commercial trade as required by EU legislation. However, following the
decision, the national authorities have taken some steps towards complying with
EU law and the Commission is overseeing progress in this respect.

[71]     This figure does not include the capacity of interconnectors or
wind generation.

[72]     For a comparison with wholesale prices in neighbouring
countries, please refer to Table 9 in Part 2 of the Staff Working Document on
Energy Markets in the EU.

[73]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[74]     This is the share of renewables in Gross Final Energy
Consumption.

[75]     The share of electricity produced in combined heat and power
plants (CHP).

[76]     For a comparison with wholesale prices in neighbouring
countries, please see Table 9 in the Staff Working Document on Energy Markets
in the EU part 2.

[77]     The reporting methodologies differ among hubs, therefore the
volumes are not entirely comparable.

[78]     Share of RES in Gross Final Energy Consumption.

[79]     The share of electricity produced in combined heat and power
plants (CHP).

[80]     The share of electricity produced in combined heat and power
plants (CHP).

[81]     For comparison with wholesale prices in neighbouring countries
please refer to Table 9 in the Staff Working Document on Energy Markets in the
EU part 2.

[82]     This is the share of renewables in Gross Final Energy
Consumption.

[83]     The share of electricity produced in combined heat and power
plants (CHP).

[84]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[85]     http://www.ilr.public.lu/stroumagas/comparaison_des_prix/index.html

[86]     This the share of renewables in Gross Final Energy Consumption.

[87]     The share of electricity produced in combined heat and power
plants (CHP).

[88]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[89]     Share of RES in Gross Final Energy Consumption.

[90]     The share of electricity produced in combined heat and power
plants (CHP).

[91]     Production plus imports less exports and changes in stocks.

[92]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[93]     This is the share of Renewables in Gross Final Energy
Consumption.

[94]     The share of electricity produced in combined heat and power
plants (CHP).

[95]     IP/12/1139.

[96]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[97]     This is the share of renewables in Gross Final Energy
Consumption.

[98]     The share of electricity produced in combined heat and power
plants (CHP).

[99]     8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[100]    Law 77/2011 on
electricity and Law 78/2011 on gas.

[101]    This is the share of renewables in Gross Final Energy
Consumption.

[102]    The share of electricity produced in combined heat and power
plants (CHP).

[103]    A decision to refer the matter to the Court of Justice by the College of Commissioners was taken in November 2011 (see IP/11/1437). In concrete terms,
the Commission considers that Romania does not offer interruptible backhaul
capacity at all interconnection points. The inclusion of backhaul capacity is
essential to use the network to its maximum capacity. Moreover, interruptible
capacity and short-term services are vital for newcomers to enter the market.
In addition, the TSO in Romania does not entirely comply with EU transparency requirements.
Without information on available capacity, the gas market cannot become really
competitive and new entrants cannot gain access to it. However, following the
Commission decision, the national authorities have taken some steps towards
complying with EU law and the Commission is overseeing progress in this
respect.

[104]    The Commission has launched in-depth inquiries into preferential
electricity tariffs granted by Romanian hydroelectricity generator
Hidroelectrica to various companies. See Cases SA. 33451, 33475 and 33581.

[105]    Annual average day-ahead baseload power prices. For a comparison
with wholesale prices in neighbouring countries, please refer to Table XXX in
the Staff Working Document, part 2.

[106]    8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[107]    The share of renewables in Gross Final Energy Consumption.

[108]    The share of electricity produced in combined heat and power
plants (CHP).

[109]    For a comparison with wholesale prices in neighbouring
countries, please refer to Table 9 in the Staff Working Document on Energy
Markets in the EU part 2.

[110]    8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[111]    This is the share of renewables in Gross Final Energy
Consumption.

[112]    The share of electricity produced in combined heat and power
plants (CHP).

[113]    IP/12/1139.

[114]    For a comparison with wholesale prices in neighbouring
countries, please see Table 9 in the Staff Working Document on Energy Markets
in the EU part 2.

[115]    8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[116]    The share of renewables in Gross Final Energy Consumption.

[117]    The share of electricity produced in combined heat and power
plants (CHP).

[118]    For a comparison with wholesale prices in neighbouring
countries, please refer to Table 9 in the Staff Working Document on Energy
Markets in the EU part 2.

[119]    The establishment by CNE of transparent cost-oriented and
non-discriminatory transmission tariffs should be dealt with as a priority.

[120]    European Consumer Markets Monitoring Surveys, http://ec.europa.eu/consumers/strategy/cons_satisfaction_en.htm

[121]    In the case of Spain Eurostat takes into account the costs
arising from renewables support schemes among the network costs, whereas costs
of renewable support schemes are normally included among taxes.

[122]    8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[123]    The share of electricity produced in combined heat and power
plants (CHP).

[124]    For a comparison with wholesale prices in neighbouring
countries, please refer to Table 9 in the Staff Working Document on Energy
Markets in the EU part 2.

[125]    Source: Eurostat data.

[126]    8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[127]    See Commission decision of 14.4.2010, DG COMP Case 39351 —
Swedish Interconnectors.

[128]    The share of electricity produced in combined heat and power
plants (CHP).

[129]    The decision for referral of the matter to the Court of Justice
has been taken by the College of Commissioners in January 2012 (see IP 12/52).
In concrete terms, the Commission considers that, in violation of EU gas rules,
the maximum interconnection capacity is not offered in the UK and Ireland as the pipeline connecting Northern Ireland and Ireland is not open to the market. This
means that gas companies in Ireland cannot directly trade gas with Northern Ireland or vice versa. On the pipeline connecting Scotland to Northern Ireland short-term services are not available and neither is virtual reverse flow
capacity based on netting off physical forward flow to make capacity available
for commercial trade as required by EU legislation. However, following the
decision, the national authorities have taken some steps towards complying with
EU law and the Commission is overseeing progress in this respect.

[130]    Measured as the ratio of the annual traded volume of power and
volume of generated power.

[131]    Production plus imports minus exports and changes in stocks.

[132]    8th Consumer Markets Scoreboard, 2012, European Commission, DG
SANCO, http://ec.europa.eu/consumers/consumer_research/editions/cms8_en.htm

[133] DECC
figures

[134] OFGEM,
The Retail Market Review - Findings and initial proposals, 2011 March,
reference 34/11.

Part IV: Infringement procedures on the 2nd
and 3rd energy package

Infringement procedures on the 2nd
and 3rd Energy Package[1]

|| 2nd energy package || 3rd energy package

|| Electricity[2] || Gas[3] || Electricity[4] || Gas[5]

Austria || Cases closed || Case closed || Non-transposition case closed* || Non- transposition case closed*

Belgium || Cases closed || Cases closed || Non-transposition case closed* || Non- transposition  case closed*

Bulgaria || Cases closed || One case pending || Non- transposition  case pending** || Non- transposition  case pending**

Cyprus || No case || No case || Non- transposition  case pending** || Non- transposition  case pending**

Czech Republic || Cases closed || Cases closed || No case* || No case*

Denmark || Case closed || Case closed || Non- transposition  case closed* || Non- transposition  case closed*

Estonia || Cases closed || Case closed || Non- transposition  case pending* || Non- transposition  case pending*

Finland || Cases closed || Cases closed || Non- transposition  case pending** || Non- transposition  case pending**

France || Cases closed || One case pending || Non- transposition  case closed* || Non- transposition  case closed*

Germany || One case pending || Cases closed || No case* || No case*

Greece || One case pending || One case pending || No case* || No case*

Hungary || Cases closed || Cases closed || No case* || No case*

Ireland || One case pending || One case pending || Non- transposition  case pending* || Non- transposition  case pending*

Italy || One case pending || Cases closed || No case* || No case*

Latvia || Cases closed || Cases closed || No case* || No case*

Lithuania || Cases closed || Cases closed || Non- transposition  case pending* || Non- transposition  case pending**

Luxembourg || Cases closed || Cases closed || Non- transposition  case pending* || Non- transposition  case pending*

Malta || Case closed || No case || No case* || No case*

Netherlands || Case closed || Case closed || Non- transposition  case closed* || Non- transposition  case closed*

Poland || One case pending || Two cases pending || Non-transposition  case pending* || Non- transposition  case pending*

Portugal || Cases closed || Cases closed || No case* || No case*

Romania || Cases closed || One case pending || Non- transposition  case pending* || Non- transposition  case pending*

Slovakia || Cases closed || Cases closed || Non- transposition  case pending* || Non- transposition  case pending*

Slovenia || Cases closed || Case closed || Non- transposition  case pending** || Non- transposition  case pending**

Spain || Cases closed || Cases closed || Non- transposition  case closed* || Non- transposition  case closed*

Sweden || One case pending || Cases closed || Non- transposition  case pending* || Non- transposition  case pending*

United Kingdom || One case pending || One case pending || Non- transposition case pending** || Non- transposition  case pending**

Glossary

Total primary energy supply –
shows the share of energy sources in the energy mix. It is the quantity of
energy consumed within the borders of a country. It is calculated using the
formula: primary production + recovered products + imports + stock changes -
exports - bunkers (i.e. quantities supplied to sea-going ships).

Total final consumption –
(Mtoe) – is the energy finally consumed in the
transport, industrial, commercial, agricultural, public and household sectors.
It excludes deliveries to the energy conversion sector and to the energy
industries themselves.

Electricity mix – represents
the share of the various energy sources used for electricity generation.

Electricity generation – (TWh)
– is the quantity of electricity produced within
the borders of a country.

Indigenous production –
shows the share of energy sources extracted and used from domestic natural
sources. The precise definition depends on the particular fuel involved.

Coal – quantities
of fuels extracted or produced, calculated after any operation to remove inert
matter. In general, production includes the quantities consumed by the producer
during the production process (e.g. for heating or operation of equipment and
auxiliaries) plus any quantities supplied to other on-site producers of energy
for conversion or other uses.

Crude oil – quantities
of fuels extracted or produced within national boundaries, including offshore
production. Production includes only marketable production and excludes any
quantities returned to formation. Production includes all crude oil, natural
gas liquids (NGL), condensates and oil from shale and tar sands, etc.

Natural gas –
quantities of dry gas, measured after purification and extraction of natural
gas liquids and sulphur. Production includes only marketable production, and
excludes any quantities that are re-injected, vented and flared, and any
extraction losses. Production includes all quantities used within the natural
gas industry, in gas extraction, pipeline systems and processing plants.

Nuclear
– quantities of heat produced in a reactor. Production is the actual heat
produced or the heat calculated on the basis of the gross electricity generated
and the thermal efficiency of the nuclear plant. All nuclear production is set
as fully indigenous.

Geothermal
– quantities of heat extracted from geothermal fluids. Production is calculated
on the basis of the difference between the enthalpy of the fluid produced in
the production borehole and that of the fluid disposed of via the re-injection
borehole.

Biomass/Waste
– in the case of municipal solid wastes (MSW), wood, wood wastes and other
solid wastes, production is the heat produced after combustion and corresponds
to the heat content (NCV) of the fuel. In the case of anaerobic digestion of
wet wastes, production is the heat content (NCV) of the biogases produced.
Production includes all quantities of gas consumed in the installation for the
fermentation processes, and excludes all quantities of flared gases. In the
case of biofuels, production is the heat content (NCV) of the fuel.

Hydro –
electricity generated by hydro power plant includes small hydro. Tide, wave and
ocean power plants are also included.

Wind –
electricity generated by onshore and offshore wind power plants. Figures relate
to the end of 2004, although there was a significant increase in the number of
new installed Wind Power Plants in 2005.

Net imports by fuels (Mtoe) – share
of all energy sources imported, excluding all nuclear, which is set as
indigenous by Eurostat. Net electricity imports are included.

Imports of crude oil –
imported crude oil divided by countries of origin, EU-27 is counted without
imports inside the EU.

Imports of natural gas –
imported natural gas divided by countries of origin, EU-27 is counted
without imports inside the EU.

Imports of hard coal –
imported hard coal divided by countries of origin, EU-27 is counted without
imports inside the EU.

Final energy intensity –
is calculated as final energy demand divided by value added at basic prices.
For some industrial sectors, such as the iron and steel industry, the
non-ferrous metals industry and the engineering industry, it was not possible
to calculate energy intensity values, because the value added at basic prices
is not given for these definitions of sectors in the national accounts data
from Eurostat. In contrast to primary energy intensity, final energy intensity
does not consider the efficiency of the energy transformation sector.

CO2 emissions per
capita – are calculated as total CO2
emissions divided by total population.

CO2 intensity –
is calculated by dividing total CO2 emissions by the gross inland
energy consumption. It is an indicator for the carbon intensity of the energy
system.

Import dependency
– net imports of a country or region divided by the sum of the gross inland
consumption and bunkers of that energy carrier. 'All Fuels' shows the import
dependency for oil, gas, solid fuels, electricity and renewable energy sources
in total. The aggregate 'renewables' considers all forms of renewable energy
carriers, such as electricity from wind or hydro power, as well as biofuels and
biomass in general. A negative import dependency has to be interpreted as net
exports.

Industry –
the sector is defined according to the following NACE Rev. 2 codes: B (Mining
and quarrying) C (Manufacturing) + D (Electricity, gas, steam and air
conditioning supply).

Services
- the sector is defined according to the following NACE Rev. 2 codes: from G to
S.

Transport
– the sector covers all types of transport (NACE Rev. 2 H 49-52). In order to
calculate energy intensity, the final energy consumption in transport was
divided by the value added at basic prices of the whole economy.

Abbreviations

API
degree – American Petroleum Institute (API) degree

bcm –
billion cubic metres

Cap –
capita

CIF
Price – cost, insurance and freight price

Dutch
TTF – Dutch Title Transfer Facility

EUR – euro

EUR/bbl
– euro per barrel

GDP –
Gross Domestic Product

GWh –
gigawatt hour

IEA –
International Energy Agency

KWh:
kilowatt hour

LNG –
Liquefied Natural Gas

Mb/d –
million barrels per day

Mbbl –
million barrels

MMBtu –
million British Thermal Units

Mt –
million tonnes

Mtoe –
million tonnes of oil equivalent

MWh –
megawatt hour

N/A -
Not available or not applicable

NBP –
National Balancing Point (UK)

OECD –
Organisation for Economic Cooperation and Development

OPEC –
Organisation of the Petroleum Exporting Countries

Platts
PEP – Platts Pan European Power index

pp –
percentage point

TJ –
terajoules

Toe –
ton of oil equivalent

TSO –
Transmission System Operator

TWh –
terawatt hour

USD –
US dollar

[1] The table reflects the situation on 29th  October
2012. As regards the transposition of the 3rd Package, the
Commission has not opened (or, respectively, not pursued further) infringement
proceedings against the Member States, which had declared full transposition of
the Directives and prima facie examination of the measures had indicated
that the transposition is complete. However, this is without prejudice of the
right of the Commission to pursue at a later stage a failure to transpose
certain provisions, should shortcomings be identified at a later stage, e.g. in
the context of a non-conformity check (all received notifications of national
transposition measures are subject to examination as to conformity with EU
law).

In the table,
the asterisks have the following meaning:

- The Member State has declared full
transposition in its notification of transposition measures.

** The Member State has declared partial
transposition in its notification of transposition measures.

[2] Directive 2003/54/EC of
the European Parliament and of the Council of 26 June 2003 concerning common
rules for the internal market in electricity and repealing Directive 96/92/EC (OJ
L 176, 15.7.2003, p. 37-53) and/or Regulation (EC) No 1228/2003 of the
European Parliament and of the Council of 26 June 2003 on conditions for access
to the network for cross-border exchanges in electricity (OJ L 176,
15.7.2003, p. 1-19)

[3] Directive
2003/55/EC of the European Parliament and of the Council of 26 June 2003
concerning common rules for the internal market in natural gas and repealing
Directive 98/30/EC (OJ L 176, 15.7.2003, p. 57-78)  and/or Regulation
(EC) No 1775/2005 of the European Parliament and of the Council of 28 September
2005 on conditions for access to the natural gas transmission networks (OJ L
289, 3.11.2005, p. 1–13)

[4] Directive 2009/72/EC of the European Parliament and
of the Council of 13 July 2009 concerning common rules for the internal market
in electricity and repealing Directive 2003/54/EC (OJ L 211, 14.8.2009, p.
55–93)

[5] Directive 2009/73/EC of the European Parliament and
of the Council of 13 July 2009 concerning common rules for the internal market
in natural gas and repealing Directive 2003/55/EC (OJ L 211, 14.8.2009, p.
94–136 )

TABLE OF CONTENTS

Part I: Executive summary.. 3

Part II: Overview of
energy markets in the European Union.. 8

1..... ENERGY
POSITION OF THE EU.. 8

1.1.    EU ENERGY CONSUMPTION.. 8

1.1.1.     Gross inland consumption
(energy mix) 8

1.1.2.     Uses of energy sources by
sectors. 9

1.1.3.     Energy intensity. 12

1.2.    EU ENERGY SUPPLY.. 13

1.2.1.     EU primary energy production. 13

1.2.2.     EU electricity generation. 14

1.2.3.     EU energy imports. 15

1.2.4.     EU import dependency. 17

EU-27
– RENEWABLE ENERGY SOURCES. 19

RES consumption. 19

RES production. 20

Electricity from RES. 21

2..... Market
developments in the EU gas sector.. 23

2.1.    Wholesale markets. 24

2.2.    Market structure and
unbundling. 32

2.3.    Retail markets. 37

3..... European
Electricity Markets. 43

3.1.    Power supply sources and
wholesale markets. 44

3.2.    Market structure and
unbundling. 50

3.3.    Retail markets. 54

Part III: Country
reports. 62

Part IV:
Infringement procedures on the 2nd and 3rd energy package. 215

Part
I: Executive summary

1.         BACKGROUND TO
THIS REPORT

This Staff Working Document contains important background
information relevant to the Communication on the Internal Energy Market 'Making
Energy Markets Work'. It consists of four parts: an Executive Summary (Part I),
an overview of the EU electricity and gas markets which includes key
statistical data of the European energy markets (Part II), a country chapter
(Part III) that provides country-specific analysis for all of the 27 Member
States of the EU and a state of play with infrigement procedures (Part IV)..
The Commission is legally bound to report on the progress towards the creation
of the internal energy market on the basis of Article 47(6) of the Electricity
Directive and Article 52(6) of the Gas Directive.

The purpose of the country reports (Part III) is to take stock, in
quantitative terms, of the state of the market in terms of energy mix, the
renewables target, the development of trade, wholesale and retail markets,
consumers' rights and empowerment and, finally, infrastructure in each Member State. As far as the implementation of the Third energy package is concerned, the
document assesses the status of notification by Member States of transposition
measures by 1 October 2012. Part IV provides an overview of all infringement
cases, including information as to whether they are pending or closed. The
Commission is conducting compliance checks on all notified transposition
measures. The reports also contain, for each Member State, the action points that
are most urgent, in the Commission's view and also in line with the Council
recommendations on the National Reform Programmes 2012[1].

The bulk of the information provided in the country reports is based
on the national monitoring reports as submitted by the national regulatory authorities
in the second half of 2011, monitoring the year 2010. Data on renewables,
energy mixes and energy import and export volumes are mostly based on Eurostat
data, and also refer to 2010. Where possible and appropriate, more recent data
have been taken into account. Annual average wholesale prices and traded
volumes of electricity and gas refer to 2011 and are derived either from
commercial data providers or from the national regulators. Electricity and gas
retail prices and a breakdown of price bewteen energy costs, network costs and
taxes are also taken from Eurostat and refer to year 2011. Data in the 'Key
indicators' table are derived from Eurostat, the European Energy regulators
database, the national regulators and ACER, backed up by own estimations.

2.         MAIN MESSAGES

Message 1: increasing share of RES and energy savings achieved

While crude oil and petroleum products still dominated energy
consumption in 2010 in the EU, their share continued to fall between 2009 and
2010. Over the same period, the share of nuclear and solid fuels was stable,
while that of natural gas and renewables increased. Renewables accounted for 12.5%
of the EU's energy consumption in 2010, an increase of four percentage points
in five years[2].

The production of crude oil and petroleum products in the EU also
declined in 2010, continuing the trend of recent years. While the production of
solid fuels declined slightly, that of natural gas and nuclear energy posted moderate
increases. Production of renewables grew by 12% in 2010 alone.

In power generation, only oil experienced negative growth between
2009 and 2010, while renewables registered the highest rate of growth (13%),
with solar power generation registering particularly high growth (63%).
Positive growth in both renewables and nuclear power generation led to almost
half of the EU's electricity being produced from low carbon sources in 2010 (21%
and 27% respectively).

In addition, there was evidence of energy savings achieved in the EU
in 2010, and in particular energy saving measures that contributed to lower electricity
consumption, mainly by industry.

Message 2: slight fall in import dependency and falling LNG imports

Between 2009 and 2010, overall energy import dependency in the EU
fell slightly, due to falling import dependency registered in solid fuels and
natural gas. The EU's import dependency had also fallen between 2008 and 2009,
due to falling import dependency of both crude oil and solid fuels. The EU's overall
energy import dependency in 2010 was 52.7%, compared to the historic high of
54.6% recorded in 2008.

Falling import dependency of solid fuels and crude oil in 2009 can
be explained in terms of both falling net imports as well as falling
consumption at a time of economic recession.

Falling import dependency in natural gas in 2010 occurred despite
both rising net imports and consumption; this was mainly due to big reductions
in gas storage levels to meet steep increases in demand during the fourth
quarter of 2010. In the case of solid fuels, substantial storage withdrawals were
also made to meet the much higher demand. Thus, the fact that a large
proportion of the - largely unexpected - increases in demand in both solid
fuels and natural gas in 2010 were met by domestically stocked resources
explains the falling dependency on imports in these two energy sources.

However, between 2010 and 2011, this was followed by a fall in natural
gas consumption, which registered its lowest level since 2000. Alongside this fall
in consumption, there was also evidence of falling imports in natural gas in
2011. In particular, LNG imports fell heavily (-26%) in the second half of
2011, relative to the first half of the year, in contrast to rising import levels
between the 1st and 2nd half of the previous year.

Having risen to represent an important share of natural gas imports
by 2011 (20%), a fall in LNG imports occurred, together with a continuing rise in
the difference between the superior prices paid for LNG deliveries to Japan and Asia relative to LNG prices in the EU. Parallel to this growing premium, there were
significant increases in demand for LNG from Japan, following the Fukushima nuclear outages earlier in the year due to the Tsunami.

Together with the growing domestic production of shale gas in the
US, events in Japan have therefore contributed - in a relatively short period
of time - to a shift from the EU being primarily in competition with the US for
LNG supplies, to competing with Asia.

Message 3: increased gas-to-gas competition alongside increases in
oil-indexed gas prices

Another key issue in the EU gas markets in 2011 was the continued
increases in oil-indexed prices of Long Term Contracts (LTC) for gas. Relative
to stable traded spot prices, this signified a reversal in the narrowing of the
gap between the two pricing mechanisms in 2010.

This renewed divergence in gas price contracts coincided with
reports of pressure being put by importers on gas producers to reflect
movements of hub-traded gas prices in their LTC contracts. If the price of gas
purchased via LTC contracts were to continue to exceed the price of spot gas in
the EU in the future, it would continue to give cause for concern on the part
of European utilities who would have to buy gas under long term, oil-indexed
contracts, while being pressured by their own customers to sell at lower spot
levels.

Competitive prices of traded gas provided a boost to spot traded
volumes in continental EU, which registered a
significant, double digit (27%) increase between 2010 and 2011. They also contributed
to a significant fall in the share of oil-indexed gas
contracts in 2010 in Europe (accounting for 68% of natural gas consumption in
2009, down to 59% in 2010), as the proportion of spot purchased gas increased
significantly (from 27% of natural gas consumption in 2009 to 37% in 2010).

In 2010 and 2011 there were therefore further signs of the continued
emergence of true gas-to-gas competition, whereby the price of gas is
ultimately determined by gas market fundamentals and by the interplay of gas
supply and demand, traded over a variety of different periods, rather than by
oil and oil product markets.

Message 4: increasing liquidity & higher integration of EU power
markets

While traded volumes of power in the EU have not grown to the same extent
as traded volumes of gas in recent years, power market liquidity[3] has increased almost continuously between 2005 and 2011. Increasing
market liquidity is indispensable for the proper functioning of a wholesale
market and for the formation of competitive prices, thereby ensuring welfare
benefits for consumers.

The increasing role of wholesale power trading markets in Europe has meant that electricity prices are increasingly being determined by the relationship
of demand and supply in the market.

In the process of integrating wholesale electricity markets among
neighbouring countries, market coupling is playing an increasingly important
role in the EU. Market coupling allows players to trade directly between
markets by benefiting automatically from cross-border capacities, without
having explicitly acquired the required transmission capacity in individual
markets. Market coupling has been spreading steadily from the North-West of the
EU to other regions, and there are currently 18 Member States which have such a
system in place[4].

In the Central West European (CWE) power markets, where market
coupling took place in November 2010, a steep fall in adverse power flows
(flows going from a high price area to a low price area) occurred in Q4 2010
and, from the first quarter of 2011, adverse flows became virtually
non-existent in the region. Disappearing adverse flows and a high ratio of
hourly converging prices within an observed time period both indicate a
well-functioning, integrated wholesale power market.

The lack of market coupling prevents prices from acting as effective
signals for the direction of power flows between markets. It should therefore be
regarded as an effective, market-based, tool contributing to the achievement of
a single European wholesale electricity market.

Better integration of European wholesale power markets, which has
enabled more convergent wholesale power prices, could be a factor explaining why
power prices did not follow the sharp increase in fossil fuel prices in the
last couple of years. This achievement also underlines the importance of
European-level electricity market policy and the need to fully implement the successive
energy packages.

Message 5: competition in place, but room for improvements.
Switching rates still too low

Gas

Between 2009 and 2010, the number of operators on the transmission
and distribution grid of the gas system in most Member States remained stable. By 2010, there were more than ten gas
supplying companies in the majority of Member States.

As regards the number of gas importers, less than half of the Member
States had more than ten gas importing companies. Furthermore, the market share
of the largest gas importers exceeded 50% in 14 out of the 20 Member States for which information was available (and over 80% in five Member States). On the
gas retail side, while all but six Member States had ten or more companies
supplying natural gas to final consumers, the market share of the largest
retailer exceeded 50% in 13 Member States (and it even exceeded 80% in eight
Member States).

The available data show that switching rates continued to be low
across all categories of consumers in 2010, with few exceptions (such as the UK and Italy). In addition, switching rates continue to be typically the lowest in the small
industry and household category.

Power

In power markets, concentration in power generation continues to be
high in most Member States, while the total number of power generation
companies present in the market reached a three-digit to four-digit figure in a
few Member States. The market share of the largest generators is however larger
than 50% in 11 Member States (and larger than 80% in six Member States).

There were 18 Member States in the power retail markets which had
more than 20 electricity suppliers, while there were three or more main
electricity suppliers in 20 Member States (i.e. selling more than 5% of the total
national electricity consumption).

By 2010, most of the EU Member States had only one TSO, while six Member
States had two or more. In addition, ownership unbundling had occurred in about
half of the EU Member States.

As for the gas sector, switching between power suppliers in 2010
remained low, and was more apparent among medium to large size industrial
consumers. In the case of household consumers, the ratio of households that
switched suppliers was low in all Member States of the EU.

In both the gas and the power markets, the data on switching rates
therefore seem to suggest that the issue of cost-effectiveness is still a cause
for concern, mainly among industrial customers.  Lack of knowledge about the
potential for switching also still seems to prevail among household consumers.

Message 6: retail prices on the increase, with little convergence
between Member States

Gas

Both EU households and industries experienced average increases in
excess of 10% in gas retail prices in 2011 relative to 2010.

Comparisons between the retail prices for gas across the EU in 2010
reveal significant differences between Member States, with the price paid in
the most expensive Member State representing several times the price paid in
the cheapest. In addition, the difference is greater for households than for
businesses, while the gap in the case of households has actually been widening in
recent years.

However, retail prices in some Member States are artificially low.
Indeed, some Member States continue to regulate the retail prices of natural
gas for groups of industrial and household consumers.

Power

With some exceptions, there were increases in retail power prices
for both households and industrial customers throughout the EU in 2011, although
on average by slightly lower than for gas retail prices.

As with gas retail prices, major differences persist between prices
in different EU Member States, with no significant change being observed in the
case of household prices in recent years.

Variations in retail prices between Member States can be explained
by differences in network costs and taxation, as the latter fall within the remit
of the national legislations in each Member State. In addition, the practice of
indexing retail electricity price to fossil fuel prices still exists in some
countries, which prevents falls in wholesale prices from being reflected in
retail prices.

Part
II: Overview of energy markets in the European Union
1. 
ENERGY POSITION OF THE EU
1.1. 
EU ENERGY CONSUMPTION
1.1.1. 
Gross inland consumption (energy mix)

Gross inland consumption increased by 3.3% in 2010, compared to 2009.
Crude oil and petroleum products continued to dominate the energy mix, although
their share dropped from 36.6% in 2009 to 35% in 2010 as a  result of a fall in
consumption (from 623 Mtoe to 617 Mtoe). By 2030, this share is likely to drop further
to 32%[5].

As far as natural gas is concerned, an increase in consumption was observed,
in both relative and absolute terms, between 2009 and 2010. The share rose from
24.5% to 25.1% and the quantity consumed rose from 417 Mtoe to 442 Mtoe. Nuclear
energy maintained the same share (13.5%), but increased from 231 Mtoe to 237
Mtoe overall. Similarly, there was also an increase (by 12 Mtoe to 280 Mtoe) in
the quantity of solid fuels consumed, although maintaining the same percentage share
(16%). In comparison, solid fuels accounted for 27% of gross inland consumption
in 1990. This could indicate a shift from CO2-intensive solid fuels to other,
less-CO2-intensive energy sources, thereby contributing to the objective of a
less CO2-intensive economy.

Figure 1: EU-27, Gross inland consumption (in
%) (2010)       Total = 1759.0 Mtoe

Source: Eurostat

One such energy source is renewables, the consumption of which increased
by 12.6% from 2009 to 2010, to reach 172 Mtoe. This represents a continuation
of the rising consumption of renewables that has been experienced in recent years,
which is itself a consequence of the policy of greening the energy mix. This
growing trend is projected to continue in the future.

Overall, the share of fossil fuels was down from its 2009 level by 0.7
of a percentage point to 76.1%. In absolute terms this amounted to 31 Mtoe less
consumption of fossil fuels.

1.1.2. 
Uses of energy sources by sectors

As in previous years, transport continued to be the largest consumer
of energy in 2010, followed by households and industry. However, compared to
2009, the share of transport was down by 1 percentage point.

Figure 2: EU-27, Total final energy
consumption (in Mtoe) (1995-2010) and final energy consumption by sector (in %)
(2010)       Total = 1153.2 Mtoe

Source: Eurostat

As far as the consumption of energy sources in different sectors was
concerned, natural gas was mostly used for power generation and in households. The
percentages were at similar levels to those of 2009. However, absolute values were
up in all categories. Consequently, the total gross inland consumption of
natural gas in 2010 was 6% higher than the previous year.

Figure 3: EU-27, Use of natural gas by sector
(in %) (2010)    Total = 441.7 Mtoe

Source:
Eurostat

Note: * final energy
consumption

In the area of petroleum products, transport was responsible for
almost two thirds of final consumption in 2010. Petroleum products were also
used in power plants, but to a much lesser extent than natural gas (20 Mtoe vs.
139 Mtoe).

Figure 4: EU-27, Use of petroleum products by
sector (in %) (2010) Energy available for final consumption = 548.5 Mtoe

Source: Eurostat

Unlike petroleum products, solid fuels and nuclear are predominantly
used for power generation.

Figure 5: EU-27, Use of solid fuels by sector
(in %) (2010)     Gross inland consumption = 280.0 Mtoe

Source: Eurostat

Turning now to electricity consumption, industry continued to be the
largest consumer. Household consumption increased by 21 TWh (surpassing the quantity
consumed in 2008 by 27 TWh)., Consumption was higher in the services sector than
in 2008 and 2009 (by 43 TWh and 37 TWh respectively), whereas in the other
sectors it was still below 2008 levels. Total final consumption of electricity
was lower than in 2008 (by 1%), but higher than in 2009 (by 4.6%).

Figure 6: EU-27, final use of electricity by
sector (in %) (2010)
Final electricity consumption = 243.9 Mtoe

Source: Eurostat

1.1.3. 
Energy intensity

Energy intensity is a measure of how much energy is used to produce
a unit of economic output. Final energy intensity measures the energy
efficiency of the economy against final energy consumption, i.e. the amount of
energy finally available to different sectors after conversion of energy
sources. The chart below shows that final energy intensity has been decreasing
over time, although in 2009 it increased slightly for the economy as a whole, as
a result of increases in transport and services. Nevertheless, the energy
intensity of industry continued to decline in 2009.

According to information provided by the Member States in their
second National Energy Efficiency Action Plans, total final energy savings in
the EU reached 60 Mtoe in 2010. This number can be broken down as follows: electricity
savings (20%), thermal energy savings (58%) and transport energy savings (22%).

This means that, without energy saving measures in the energy
end-use sector, the consumption of electricity itself in the EU-27 in 2010
would have been higher by some 10-12 Mtoe, mainly consumed by industry.

Figure 7: EU-27, Final energy intensity (in
toe/EUR million) (1995-2009)

Source: Eurostat

1.2. 
1.3. 
 EU ENERGY SUPPLY
1.3.1. 
EU primary energy production

After years of decline, EU energy production picked up again in 2010,
albeit to a level lower than in 2008 (837 Mtoe vs. 855 Mtoe). The decrease of recent
years is primarily due to lower levels of fossil fuel production.

Figure 8: EU-27, primary energy production (in
Mtoe) (1995-2010)

Source: Eurostat

Renewables production grew by 12% between 2009 and 2010. During the
same period, moderate increases were recorded in the production of natural gas (2%)
and nuclear energy (2.5%), while the production of crude oil and petroleum as
well as solid fuels both fell (by 7% and 1% respectively). These growth rates
indicate the ongoing transition towards a low-carbon economy.

Although the production of natural gas remained stable in 2010, the
declining trend from the earlier years is projected to continue. Between 1995
and 2010 the decrease reached 18%. The biggest producers in the EU are the Netherlands and United Kingdom. In 2010 their shares in total EU natural gas production were 41% and
33% respectively. Germany, the third largest producer, had a share of 6%.

The production of oil decreased at an even faster rate, i.e: by 40%,
between 1995 and 2010. The United Kingdom is by far the largest producer of crude
oil in the EU, with a 67% share of total EU oil production in 2010. Denmark is the EU's second largest producer, with a share of 14% of total EU production.

1.3.2. 
EU electricity generation

Total gross electricity generation in 2010 was 3,346 TWh, i.e. 4%
higher than in 2009 when it contracted due to the economic slowdown. Prior to
the crisis, electricity generation had been growing steadily. It then fell in
2009 to its 2003 level. However, as the chart shows, the changes after the
crisis were visibly different from one type of fuel to another.

Renewables experienced the highest rate of growth, up by 13% between
2009 and 2010. The most important source remains hydro power, representing more
than half of green electricity, followed by wind (21% of green generation). Solar
power grew by 63% between 2009 and 2010.

Figure 9: EU-27, Gross electricity generation (in
TWh) (1995-2010)

Source: Eurostat

Nuclear energy became the most important source of power production
in 2008, and remained so in 2010. Due to variations in electricity production,
it had often alternated with solid fuels in the past. As an example, the PRIMES
baseline scenario projections reveal that solid fuels could once again
contribute to the largest amount of electricity produced by 2020 due to a decrease
in installed nuclear capacities. However, with new capacities installed by 2030,
nuclear power could once again play a major role.

The importance of natural gas has been rapidly increasing since
1995,. This is due to the significantly greater importance of gas in some
Member States to provide the necessary back-up supply for variable generation
from renewables. During the observation period, its use in electricity
generation more than doubled. Oil, on the other hand, continued to register a negative
trend, and is likely to become even more marginal in the future. Cyprus and Malta, due to their geographical location, are the only two Member States which rely
almost entirely on this source of electricity production.

Almost half of the EU's electricity was produced from CO2-neutral
sources (renewables and nuclear). When natural gas is added, this covers more
than two thirds of generated electricity. Compared to 1995, these shares were 46%
and 57% respectively[6].

1.3.3. 
EU energy imports

Following a rise in 2008, energy imports fell sharply in 2009: by 7%
to 941 Mtoe, which was close to the 2004 level.  The decrease is in line with
lower energy consumption and electricity generation during the economic
recession. With recovering economic activity, net imports increased in  2010,
but by only1%.

Figure 10: EU-27, Net imports of energy (in
Mtoe) (1995-2010)

Source: Eurostat

In the category of solid fuels, hard coal experienced the largest
decrease – 18% in 2009. It posted a further slight fall the year after, which was
not the case for other categories, where net imports increased in 2010. 59% of total
energy imports consisted of crude oil and petroleum products in 2010. Renewables
again registered the biggest annual increase (28%), although their share in
total imports was very low, given that the EU relies mostly on indigenous
renewable sources (see the box on renewables for more details). Fossil fuels account
for 99% of EU energy imports. Partner countries differ from fuel to fuel,
although some of them are key partners in a number of fuel categories. In 2010,
 Russia was the main exporter of crude, natural gas and hard coal to the EU,
while Norway was the second most important exporter of both crude oil and
natural gas.

Figure 11: EU-27, Structure of imports of fossil
fuels (in %) (2010)

Source: Eurostat

The list of the top six countries which exported hard coal in 2010 was
the same as in 2009, although long-term developments have shown a changing
picture. Since 1990,  imports from Colombia, the second largest exporter of
hard coal to the EU, have been increasing. Imports from South Africa, on the other hand, have been dropping, while in the case of the US, imports have started to pick up again after years of decline. The increased US exports of coal can be attributed to the growing production, and consumption, of unconventional
gas. As far as South African exports are concerned, these are being redirected
towards the Pacific basin, due to increasing demand from China and India. The same trends can be observed for Australian and Indonesian coal and, in the
latter, growing domestic demand is having a large influence on the quantities
available for exports.

Figure 12: Import dependency by fossil fuels
and by MS (2010)

Source: Eurostat.

Note: Import
dependency is defined as the ratio of net imports and the sum of gross inland
consumption and bunkers. Negative numbers indicate that the country is a net
exporter. Values over 100% are possible due to changes of stocks.

1.3.4. 
EU import dependency

The overall energy import dependency[7] of the
EU fell slightly between 2009 and 2010, due to the falling import dependency
registered in solid fuels and natural gas. The EU's import dependency had also
fallen between 2008 and 2009, due to a drop in the import dependency of both
crude oil and solid fuels. The  overall energy import dependency of the EU in
2010 was 52.7%, compared to the historic high of 54.6% recorded in 2008.

Falling import dependency of solid fuels and crude oil in 2009 can
be explained by both falling net imports and falling consumption, unlike in
2010 for the former, when falling import dependency occurred, although net
imports remained stable as consumption increased.

Falling import dependency in natural gas in 2010 occurred in spite
of both rising net imports and consumption; this was mainly due to major reductions
in gas storage levels to meet high increases in demand during the fourth
quarter of 2010. In the case of solid fuels, substantial storage withdrawals were
also made to meet the much increased demand. Thus, the fact that a large
proportion of the - largely unexpected - increases in demand in both solid
fuels and natural gas in 2010 were met by domestically stocked resources
explains the drop in import dependency in these two energy sources.

Figure 13: EU-27, Import dependency (in %)
(1995-2010)

Source: Eurostat

The overall import
dependency of the EU has grown at a lower rate in recent years. Although it
increased by 3.5 percentage points between 1995 and 2000, and by 5.8 percentage
points between 2000 and 2005, the increase in the period between 2005 and 2010 was
only 0.2 percentage points. The impact assessment of the Energy Roadmap 2050 indicates
that EU's import dependency will not change significantly until 2030 (56.4%
according to the reference scenario)[8].

The majority of the EU
Member States are highly dependent on imports of oil and gas. In 2010, there
were a few Member States with significant production that made a considerable contribution
to the EU energy balance. Denmark and Netherlands were important net exporters
of gas, while the United Kingdom and Romania were able to satisfy most of their
needs through domestic production. Denmark was also a net exporter of crude oil
and petroleum products, whereas the United Kingdom was close to being self-sufficient
in oil and petroleum products.

Box

1.4. 
EU-27 – RENEWABLE
ENERGY SOURCES
RES consumption

Gross inland consumption of renewable energy sources (RES) reached 172
Mtoe in 2010, representing an annual increase of 13%, while the share of RES in
the EU's total gross final energy consumption accounted for 12.5% of the EU's
energy consumption in 2010, compared to 8.5% in 2005[9].

Biomass has been by far the largest source of RES consumed in the EU.
Consumption of biomass was up 13% in 2010, accounting for 69% of the total
consumption of renewables. Most of this was used for power generation and in
households.

Solar power was the renewable source with the highest growth in
consumption, up by 48% to 3.7 Mtoe. This was mainly due to the big increase in
photovoltaics, which saw consumption increase by 60% compared to 2009.

The use of wind power rose by 12%, while that of geothermal power
increased only by 1.2%, although hydropower is still the second most important
renewable source in the European energy mix.

Figure 14: EU-27, Renewable energy sources:
Gross inland consumption by source (in %) (2010)  Total = 172.1 Mtoe

Source: Eurostat

RES production

In 2010, the production of renewables reached 167 Mtoe, representing
a 12% increase compared to 2009 and a 100% increase compared to 1995. As
production was lower than consumption, the difference was covered by imports. In
2010, half of the imports were solid biomass and the other half biofuels, primarily
biodiesels.

Figure 15: EU-27, Renewable energy
production (in Mtoe) (1995-2010)

Source: Eurostat

Biomass and wastes have been the main driver
behind the growth in renewable energy production. As figure 16 shows, solid
biomass has the largest share. This is mainly due to its increased use in power
generation.

Figure 16: EU-27, Renewables: Production of
Biomass and Wastes (in Mtoe and %) (2010) Total=112.7 Mtoe

Source: Eurostat

Wind and solar energy also grew strongly in
recent years (see again figure 15). In 2010, the production of wind energy was
up by 12% over the previous year, while solar energy grew by 48%. There are two
categories of solar energy: solar thermal and solar photovoltaic. In 2000, the share
of solar thermal accounted for 98% of the solar energy produced, while in 2010
photovoltaics had grown to represent 52% of solar energy produced.

Electricity from RES

Renewable energy sources are playing an ever increasing role in
European electricity generation. In the period under review, their share
increased from 14% in 1995 to 21% in 2010.

Contrary to the total gross inland consumption of RES, where biomass
and wastes are the most important fuels, hydro power plays by far the most
important role in electricity generation. Nevertheless, the importance of RES
other than hydro has grown considerably. In 1995, they contributed only 8% of
green electricity. By 2010, this had risen to 43%.

Figure 17: EU-27, Gross electricity generation
(in TWh) (1995-2010)

Source: Eurostat

As figure 18 shows, between 2006 and 2010 the installed capacities of
wind and photovoltaic power experienced a rapid growth. In 2010, the installed
capacity of wind turbines was 75% higher than in 2006, representing an average
annual growth of 15%. Installations of photovoltaic panels grew even more
rapidly, ending at a level of capacity nine times higher than in 2006. The
average annual growth rate was 75% within the observed period.

Figure 18: EU-27, Evolution of installed
capacities for photovoltaics and wind (in GW)

Source: EurObserv'ER

Germany (27.2 GW) and Spain (20.8 GW) accounted for 56% of installed wind power capacity in 2010. In the case of
photovoltaic power, Germany accounted for 59% (17.4 GW) of the EU's net maximum capacity.

2. 
Market developments in the EU gas sector

2011 was an eventful year for natural gas markets, marked by political
unrest in the Middle East and the nuclear outages caused by the devastating
tsunami in Japan. Markets were concerned about the implication of these events
on the supply of gas. In the case of the former, the fear was the possibility
of interruption of important gas pipelines, and in the latter case, the concern
was the likely diversion of EU-bound LNG cargoes to Japan in order to compensate
for the loss of nuclear energy in Fukushima and elsewhere in Japan.

Middle Eastern exports of gas were affected in the form of the
complete shut-down of Libyan supplies to Europe. Only Italy – as the biggest importer of Libyan gas – was liable to be affected to any significant degree,
although additional supplies from Russia to Italy ultimately made up for the shortfall.
More importantly, disruptions in Tunisia did not affect transiting Algerian
supplies to Europe, and unrest in Egypt did not cause blockages of the Suez Canal, which is a key LNG supply route.

Prices were only temporarily affected by fears that flexible LNG
spot cargoes might be diverted to Japan. In the period following the outages,
it quickly became evident that exports of LNG from Qatar could match the
increasing demand from Japan in the short term, supported by diversions of LNG
from other parts of Asia, without there being any immediate impact on European
LNG imports. Markets were also reassured by signs of continued healthy supplies
of natural gas in the EU in the second quarter of 2011, thereby keeping price
rises. in check. The announcement in May that all nuclear capacity in Germany would be retired by 2022 also did not  appear to have any lasting effect on
day-ahead traded gas prices.

However, increases in the price of LNG deliveries sounded the first
alarm bells in terms of the pressures likely to come from heightened Asian
demand in the future. These price increases contributed to reducing the gap
between day-ahead prices and prices of LNG deliveries to the EU, which have
been low in recent times, partly as a result of ample gas supplies in the US.

Indeed, by the second half of 2011, marked falls in imports of LNG into
the EU were observed. Overall, 26% less LNG was imported into the EU in the
second half of 2011 compared to the first half of 2011, in contrast to a rise
in imports between the first and second halves of the previous year

Another key issue in EU gas markets in 2011 was the continued
increases in oil-indexed prices of Long Term Contracts (LTC) for gas. Relative
to stable traded prices, this denoted a reversal in the narrowing of the gap
between the two pricing mechanisms that had been observed in 2010. This meant
that, by the end of 2011, the issue of renegotiating LTC gas contracts between
suppliers and EU importers was still very firmly on the table.

The end of 2010/ beginning of 2011 was an important period for EU
gas-related policy. In a Communication published in November 2010, the European
Commission outlined the energy infrastructure priorities for 2020 and beyond, as
well as the new approach envisaged for the EU support of energy infrastructure during
the period 2014-2020.

The Commission’s proposals seek to address a number of issues with
regard to the integration and development of the EU's gas infrastructure, in
particular the absence of interconnections between the national and regional
gas markets, the need for more LNG terminals and storage facilities for
security of supply, sustainability and system resilience, and the need to push
ahead with the diversification of sources, routes and suppliers. Planned investment
in new gas transmission and import pipelines, storages and LNG terminals are likely
to be of the order of EUR 70 billion by 2020[10].

In addition, an important new regulation on the Security of Gas
Supply entered into force on the 2nd of December 2010. It calls on Member States and gas companies to be fully prepared in the event of disruption of supply, by
putting in place clear and effective emergency plans involving all stakeholders
and fully incorporating the EU dimension of any significant disruption in a spirit
of solidarity. In addition, Member States and gas companies are encouraged to
coordinate their preventive actions and emergency plans at regional and
European levels, while companies will need to be able to deliver gas for at
least 30 days of average demand, as well as in the case of an infrastructure
disruption under normal winter conditions. The regulation should enable the EU
to cope more effectively in the event of disruption of gas imports by fostering
a more coordinated approach, in order to guarantee a stable and secure energy
supply to citizens across the EU.

2.1. 
Wholesale markets

Continuing the trend which began in the first quarter of 2011,
natural gas consumption in the EU in the 4th quarter 2011 fell year-on-year,
contributing to a full year 2011 level of gas consumption for the EU which was
less than any of the years since the effects of the crisis were observed
(2009+), and even registering the lowest level since 2000.

By the fourth quarter of 2011, falling imports of natural gas were
also observed along with falling consumption. This is in contrast to trends observed
in the three previous quarters of the year, when there was positive
year-on-year growth in imports. This contributed to a marginal decrease in
imports of natural gas between 2010 and 2011, although 2011 levels of imports were higher than in 2009 and even
2008.

Figure 19. Balance of natural gas in the European Union

Falls in consumption and imports of natural gas occurred alongside a
prolonged period of sluggish economic growth[11].
By Q1, EU GDP growth in 2012 hit its lowest level since the fourth quarter of
2009 – when the EU economy was in recession.

The mild weather conditions across the continent in Q4 2011 contributed
to the relatively low demand for gas for heating. As a result, withdrawals from
underground storages started much later than usual during the winter season.
Storage levels proved to be an important factor in bringing the much needed
flexibility during the cold snap which occurred in February 2012.

As far as EU domestic production of natural gas is concerned, a
continued decline was observed in 2011, with the rate of fall since the year of
peak production (2001) to 2011 amounting to 34%, significantly exceeding the
reduction of gross inland consumption (of 19%) during the same period.

According to Eurostat data, gas imports into the EU totaled
4,621 TWh in 2010, with the most important trading partners being the Russian Federation (32%), Norway (28%) and Algeria (14%). The combined share of Nigeria, Libya, Qatar, Egypt and Trinidad & Tobago was less than 18%.

The EU's dependency on natural gas imports[12] increased from 48% in 2000 to 58%
in 2005, to 62% in 2010. As the first section of Table 1 shows, European Member
States - except for Denmark, the Netherlands and to a lesser extent also Romania and the United Kingdom - tended to rely on imports as their major source of gross inland
consumption.

Table 1. Gas
Security of Supply -2010

Sources:    National Regulators data, Eurostat,
- DECC (UK)

Notes:

(1) Gross Inland Consumption = Production +
Imports - Exports + Storage variations

(2) All dry marketable production within
national boundaries, including offshore production. Production is measured
after purification and extraction of NGLs and sulphur. Excludes extraction
losses and quantities reinjected, vented or flared.

(3) Maximum quantity of gas consumed in a
day during the year

(4) UK numbers include Great Britain only as gas demand from Northern Ireland and the Republic of Ireland is not possible
to differentiate

In the second section of Table 1, it can be seen that peak daily
consumption was higher than the maximal technical availability of the capacity
of the importing pipeline or the peak daily import flow in Member States such
as Spain, France, Italy and Poland,. In these Member States, gas storages and
market based measures, such as interruptible consumption and cross border
swaps, play an important part in balancing the gas system.

Turning to developments in the trading of natural gas on European
hubs, the volume of total spot traded gas was 1,640 BCM in 2011. The UK NBP –
the largest hub in Europe – traded 1,137 BCM in 2011, compared to 152 BCM in
the Netherlands - the next biggest hub in Europe - and a total of 542 BCM for
all continental hubs, which shows that there is still considerable scope for
further growth, contributing to greater liquidity of European wholesale gas
markets in Europe.

There has been a significant increase in traded
volume on the continental hubs. The amount of exchanged spot natural gas
increased more than tenfold between 2003 and 2011, and registered a 27%
increase between 2010 and 2011. In 2011, the volumes physically delivered on
continental hubs covered 58% of the total demand for natural gas in the
corresponding countries. This compares with only 35% in 2009 and 6% in 2006[13]. This shows that the role of trading hubs as an instrument for exchange
of natural gas ownership in the EU is already considerable and is on the
increase. Total traded (spot) volumes in the EU are around three times higher
than physical consumption (six times including the UK NBP hub).

As far as imports of liquefied natural gas (LNG) are concerned, in
addition to the increasing volumes of gas being imported into the EU, the share
of LNG deliveries has risen from 10% twenty years ago to just under 20% in
2011, as Figure 21 shows.

Figure 20. Annual traded volumes on European gas hubs

Notes: The chart covers the following
trading hubs: UK: NBP (National Balancing Point); Belgium: Zeebrugge; Netherlands: TTF (Title Transfer Facility); France: PEG (Point d'Echange Gaz); Italy: PSV (Punto di Scambio Virtuale); Germany: GASPOOL and NCG (Net Connect Germany); Austria: CEGH (Central European Gas Hub).

Reporting on 2011, the first signs of falling gas imports which we
highlighted above could be observed in the third quarter of 2011, as LNG
imports fell by 14% year on year, after having risen by 20% in the previous
quarter. By the fourth quarter of 2011, all exporters of LNG cut back considerably
on exports, with the result that 26% less LNG was imported into the EU in the
second half of 2011 compared to the first half of 2011, in contrast to the rising
levels of imports between the first and second halves of the previous year (see
also table 2 for a comparison of LNG capacities among Member States in 2011).

The outcome for the full year 2011, based on data for contracted
volumes, pointed to some slight growth between 2010 and 2011. Volumes
contracted via long term purchasing arrangements were about 100 bcm (1,040 TWh)
higher than what was actually imported, indicating that some market
participants were making good use of the flexibility clauses in their contracts
(using the so-called ‘take or pay’ clause). Based on data from Eurostat
and Gas Strategies, the gap between contracted and actually imported gas
exceeded 20% in 2011.

Figure 21. Imports of natural gas in the EU (contracted volumes)

Table 2. LNG capacities in the EU -2011

(N): Normal

Figure 22 below compares the trend of the price of natural gas
contracts (as represented by the UK NBP hub day-ahead average price and the
German border price) with the price of the Brent spot and Coal CIF Ara[14] spot prices. The graph shows
that, after the major correction in all energy commodity prices during the
second half of 2008/first half of 2009, there had been a period of renewed
growth which lasted until the last quarter of 2010/first quarter of 2011.

By that point, the price of Brent crude had hit a daily record
average (of 87.8 €/bbl), while both the price of coal and natural gas had also risen
significantly, reaching 95.2 €/tonne and 25.7 €/MWh respectively − somewhat
short of their historic daily highs of 135.8 €/tonne and 32.1 €/MWh respectively,
in August 2008. Thus, in the period between late 2008 and early 2011, the
prices of energy commodity prices followed a similar upward trend.

Figure 22. Prices of competitive fuels vs
prices of gas

However, there has been a clear decoupling between coal prices on
the one hand, and oil and gas prices on the other, since the beginning of 2011.
Coal has followed a slightly downward course throughout 2011, reaching a level
of 85.9 €/tonne at year end. It fell more sharply in the first quarter of 2012,
reaching a daily level of 76.5 €/tonne by the end of March 2012. Coal CIF ARA
prices were kept low due to the growing availability and supplies of US-produced
coal, on account of declining US demand for coal due to strong competition from
shale gas on the US power markets.

In contrast to coal, the price of Brent
stabilised at around 80 €/bbl during 2011, but then picked
up again, reaching a new record daily level of 97.7 €/bbl by mid-March 2012.

Similarly, the price of the NBP day-ahead contract for gas remained
within a range of between 20 and 24 €/MWh during 2011, but then temporarily hit
new record levels of 40.7 €/MWh in early February 2012, as a result of a sudden
and unexpected cold snap. By the end of March 2012, a price level of 25.2 €/MWh
was recorded which, not counting the exceptional February levels, was the
highest price attained by the NBP day-ahead since the first quarter of 2011.

The above graph also shows the price of actual gas imports at the
German border, as published by the German Federal Office of Economics and
Export Control (BAFA). This price has traditionally been taken as an indicator
of oil-index priced gas into Europe.

By comparing these two gas prices, it can be seen that the German
border price was briefly comparable to the NBP spot price at the end of 2010,
when high levels of demand for gas in the EU sent hub prices soaring to levels close
to the pre-crisis levels of 2008. Since then, however, relatively low demand
levels throughout 2011 have ensured the stability of the NBP price, while the
oil-indexed German border price has continued to rise in line with the
increases in oil prices of the previous months.

The UK NBP average monthly price represented 75% of the German
border price in December 2011, compared to 89% in June 2011 and 94% in January
2011. The difference between the long-term oil-indexed and spot prices for gas
has therefore been growing throughout 2011, in spite of reports that importers
have won concessions to reflect movements of hub-traded gas prices in their
long-term contracts. If such a large gap in the future between the two types of
contracts were to persist, it would continue to cause concern among European
utilities that have to buy gas under long term, oil-indexed contracts, but continue
to be pressured by their own customers to sell at lower spot levels.

The difference in prices between the different gas contracts is an
important issue, because the EU is continuing to buy a large proportion of its
gas under long-term, oil-indexed contracts. However, according to surveys
conducted by the International Gas Union since 2005 (see figure 23), it would
appear that − along with the increase in traded gas volumes reported previously
− the share of oil-indexed gas contracts is falling (representing 68% of natural
gas consumption in 2009 and only 59% in 2010) and is expected to decrease
further. At the same time, the proportion of spot purchased gas has increased
significantly (from 27% of natural gas consumption in 2009 to 37% in 2010). The
disparity between the prices of LTC contracts and hub prices has clearly been a
driving force behind this trend.

This paves the way for the gradual emergence of true gas-to-gas
competition, where the price of gas is ultimately determined by gas market
fundamentals and by the interplay of gas supply and demand, traded over a
variety of different periods, and no longer by oil and oil product markets.

Figure 23. Wholesale gas contracts breakdown in Europe (share of
consumption)

An additional key contributing factor of the development of hubs,
and of gas-to-gas competition, is in terms of adding to the diversity of gas
contracts available in the EU. As Map 1 shows, this diversity is important,
because markets with access to multiple sources of gas and competitive trading
arrangements (e.g. North-West Europe, UK) have benefitted from lower prices in
recent years. By contrast, Eastern European countries that depend predominantly
on long-term, oil-linked contracts have paid relatively higher prices.

It is worth noting, however, that not all EU markets have been equally
affected by the sharp rises in the oil price, which have pushed up natural gas
prices. EU Member States with well-developed gas hubs have not only enjoyed the
benefit of greater price stability; the prices of piped gas imported under
long-term contracts in these markets have also been lower. This further underlines
the importance of developing hub-trading in the EU.

Therefore, markets with more supply diversity not only enjoy greater
security, they also enable consumers in those markets to benefit from greater competition
and lower prices.

Map 1. Average wholesale price of natural
gas in the EU in 2011

Turning now to LNG prices, the continuing increases in the
production of unconventional gas in the United States (US) in 2011 ensured that
the US remained well supplied in gas, with the result that the discount between
the price for LNG deliveries in the US and the EU continued to increase, as
shown in Figure 24.

In spite of that, the difference between the prices paid for LNG
deliveries to Japan and Korea on EU LNG prices increased further in 2011. This
premium was attractive to LNG producers, and explains the declining imports of
LNG in the EU that were observed in the second half of 2011, as reported previously.
The significant increases in demand for LNG from Japan, following the Fukushima nuclear outages earlier in the year caused by the tsunami, also provided a fresh
opportunity for LNG exporters, following the loss of much of the US market. This combination of events in the US and Japan has led to a shift, in a
relatively short period of time, from the EU being primarily in competition
with the US for LNG supplies, to competing with Asia and the Far-East.

Figure 24. Prices of LNG

Notes:

- "Average EU" is a weighted
average price for monthly LNG deliveries in Belgium, Portugal, Spain, UK, Italy
(from January 2009) and France (from January 2010) as reported by Eurostat.

** The formula for calculating monthly
prices in Japan, Korea and the US was modified in Q4 2009. Previously these
prices were an average of prices charged by different suppliers. Starting from
October 2009, the averages are weighted by the monthly LNG deliveries of each
supplier.

More detailed information on developments in the EU markets for
natural gas can be found in the European Commission's Quarterly Reports on
European Gas Markets (QREGaM)[15].

2.2. 
Market structure and unbundling

For the majority of Member States the number of operators working on
the transmission and distribution grid of the gas system remained stable
between 2009 and 2010. By 2010, most Member States had 10 or more gas-supplying
companies.

Table 3. Unbundling of transmission system
operators (TSOs) in Gas - 2010

Source: CEER database

As far as the number of gas importers is concerned, fewer than half
of the gas importing Member States had more than ten gas importing companies.
Furthermore, the market share of the largest gas importers was over 50% in 14
out of the 20 Member States for which information is available (and over 80% in
five Member States). On the gas retail side, while all but six Member States
had ten or more suppliers of natural gas to final consumers, the market share
of the largest retailer exceeded 50% in 13 Member States (it also exceeded 80%
in 8 Member States).

Table 4. Unbundling of distribution system operators (DSOs) in Gas - 2010

Source: CEER database

As a rule, local consumers in the majority
of Member States have access to a restricted number of offers, and those local
suppliers may have difficulties in negotiating competitive conditions with the
importing company. Regulated prices are another reason why competition appears limited.

Table 5. Structure of the gas market in
2010

Source Eurostat,  2010 data and National
Regulators.

(1) Entities are considered as main if they
deal with at least 5% of the natural gas (indigeneous production or import).

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

(*) aggregated share of top 2 retailers

(**) aggregated share of top 3 retailers

Table 6 below illustrates the importance of having guidelines and
network codes for access conditions to gas transmission networks. Member States
tend to apply a varied range of tariff models, congestion management
procedures, capacity allocation mechanisms and balancing models, which are not
always friendly to market operators and do not send efficient market signals about
the value of existing and new capacity that the market may need.

Table 6. Access Conditions to Gas
Transmission Networks in 2010

Source: National Regulators data

Notes:

(1) BELGIUM: Inland transmission: tariff
based on an average distance Border-to-border transmission: tariff is distance
related

(2) ROMANIA: The mechanisms for calculation
of prices and regulated tariffs are of Revenue cap type for regulated
underground storage, and price-cap for regulated distribution and supply. For
the second regulatory period (2007-2012), until the entry-exit pricing system
shall be introduced, the tariff for the transmission through the national
transmission system is unique and has a binomial structure.

(3) BELGIUM: Rucksack-principle for inland
transmission, secondary market, day-ahead market, interruptible capacity, UIOSI

(4) CZECH REPUBLIC: supplementary 6,7

(5) FRANCE: UIOLI long term and short term

(6) LUXEMBOURG: UIOLI with priority for
non-incumbent suppliers

(7) ROMANIA: In order to settle the
congestions, the approved but unused capacity may make up the object of:
a)Voluntary return to the TSO; b)Capacity transfer facility (CTF); c)Mandatory
transfer from one network user to another by the TSO

(8) BELGIUM: Inland transmission: yearly
organised subscription period procedure Border-to-border transmission: LT
allocation via open season procedures

(9) CZECH REPUBLIC: 3+OSP; 5 between TSO and
DSOs

(10) FRANCE: GRTgaz and TIGF use the First
come first served rule and organise Open Subscription Periods with pro rata to
allocate their capacity. GRTgaz sells day ahead capacity according to the FCFS
rule in the first place and then through an auction mechanism. Capacity goes
with the customer is used for the regional transmission network. Open season
procedures are used for the allocation of new capacity.

(11) LUXEMBOURG: New capacity allocation
mechanism in 2012

(12) AUSTRIA: TSO uses balancing market

(13) BELGIUM: Balancing is the
responsibility of the individual shippers. TSO offers balancing services.

(14) DENMARK: TSO uses storage and linepack
for balancing

2.3. 
Retail markets

Switching rates

Data on switching rates are incomplete for many EU Member States, as
Table 7 shows. The available data show that, in 2010, switching rates remained relatively
low in most Member States across all categories of consumers. In Member States
for which data are available across the three industry groups, there are signs
that switching rates are lowest in the small industry and household category.

Table 7. Switching rate Gas (by meter
points, values are in %)

Source: CEER database and National
Regulators

Retail prices for natural gas

As far as retail prices for natural gas are concerned, households across
the EU paid 0.06 Euro/kWh on average for gas in 2011, while industrial
consumers paid 0.04 Euro/kWh. In absolute terms, households and industries in Romania paid the lowest gas prices, while households and industries in Sweden paid the highest
prices[16].
The ratio of the highest and 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 for
households and 0.06 Euro/kWh for industrial users.

Figure 25 Gas
retail prices paid by households and industrial consumers in 2011 (in EUR/kWh

Source: Eurostat Energy Statistics Note: Data for Austria (industrial consumers), Finland (domestic consumers) and Greece (domestic and industrial consumers) is not available. Range for annual consumption of : Household group D2 : [5,56 MWh – 55,6 MWh] ; Industry group I3 : [2,77 GWh – 27,8 GWh]

The ratio of the highest to  lowest household prices has been
increasing since 2008: from 2.9 in 2008 to 4.2 in 2011[17]. Over this period, Romanian
households have been paying the lowest prices for natural gas, while households
in Denmark and Sweden have paid the highest prices.

The ratio of highest to lowest consumer prices for industry fell
from 2.9 in 2008 to 2.6 in 2009, but then went back up to 2.9 in 2010 and to
3.1 in 2011[18].
During the period 2008-2011, industry in Sweden consistently paid the highest
prices for natural gas. The lowest industrial prices were paid by industry in Bulgaria (2008), Romania (2009 and 2011) and the UK (2010).

Decreasing highest to lowest price ratios may be interpreted in
different ways. For those Member States with established retail markets, this
points to greater price convergence. On the other hand, the interpretation of
the trend in highest to cheapest price ratios is limited by the existence of
regulated retail prices for industrial users who are still paying according to
an oil-indexed formula.

During the period under review, some Member States continued to
regulate retail prices of natural gas for groups of industrial and household
consumers. Cross subsidisation across consumer groups distorts prices and is
usually detrimental to competition. The Commission is against such practices,
as they are not in line with internal market principles. A number of
infringement procedures have therefore been launched.

When correcting retail prices for purchasing power standard (PPS),
the picture is much more balanced, with Bulgaria, Hungary, Sweden and Slovenia being the three countries where household consumers paid the highest prices in
2011. The lowest consumer prices corrected for PPS were paid by households in Luxembourg, the UK, Romania and Ireland.

As far as taxation is concerned, household and industrial consumers
in Luxembourg paid the lowest taxation on gas in absolute terms in 2011, while
consumers in Denmark paid the highest absolute levels of taxation. Taxation as
a share of consumer prices was lowest in the UK for households and in Luxembourg for industrial consumers. The highest share of taxation for both categories of
consumers was in Denmark.

As Map 2.1 below shows, in the smallest household consumption band[19] the average consumer price in
the second half of 2011 was 0.094 Euro/kWh, with households in Belgium, Czech Republic,
Denmark, Germany, France, Italy, the Netherlands, Slovakia and Sweden paying
higher than average prices,.

Map 2.1 Gas prices (inclusive of taxes) for
Households

Map 2.2 illustrates the case of the smallest industrial consumption
band[20],
where the average consumer price in the second half of 2011 was 0.059 Euro/kWh,
and where industries in Belgium, the Czech Republic, Denmark, France, Hungary, Italy, the Netherlands, Portugal, Slovakia, Slovenia and Sweden were paying higher than 
average prices.

Map 2.2 Gas prices (inclusive of taxes) for Industrial consumers

Over the period 2010-2011, households across the EU saw consumer
prices increase by an average of 10%, while industry experienced a 13% increase
over the same period (Figure 25 and Figure 26). At the same time, consumers living
in seven Member States were faced with a 15% or higher price increase, with the
biggest increases in prices being seen in Belgium and Luxembourg. Industries in Finland and Ireland experienced price increases of 30% or more.

Figure 26. Change in gas retail prices between 2010 and 2011

Source: Eurostat Energy Statistics Note: Prices for households are all taxes included. Prices for industrial consumers are VAT-excluded. Data for Austria (industrial consumers), Finland (domestic consumers) and Greece (domestic and industrial consumers) is not available. Range for annual consumption of : Household group D2 : [5,56 MWh – 55,6 MWh] ; Industry group I3 : [2,77 GWh – 27,8 GWh]

Figure 27 shows the trend in wholesale and retail gas prices in the UK and Germany. During the last decade, German retail prices (blue line) have largely moved in step
with German border prices (green line). After peaking in the second half of
2008, the second half of 2009 saw German wholesale border prices drop to a level
hitherto not experienced. The same trend was reflected in retail prices. All
quarters of 2010 and 2011 saw an upward trend, which was more pronounced in the
case of border prices than in retail prices.

The pattern of wholesale and retail prices in the UK during the past decade is somewhat less straightforward, and does not seem to exhibit the same degree
of correlation as that between the German
border and retail prices. Until 2004, hub and retail prices had often moved in
opposite directions.

Between 2005 and 2007, UK retail prices followed the same evolution
of hub prices with a certain time lag. The retail price peak in 2008 came at a
time of initially stable, and then falling, hub prices. There was then a better
alignment between the evolution of hub and retail prices in the UK in 2009. Since then, both hub and retail prices have been pursuing an upward course,
with convergence over the second half of 2010 and the first half of 2011, and
decoupling during the second half of 2011.

Figure 27. Evolution of selected wholesale
and retail gas prices

Note: Prior to 2008 the following Eurostat end consumer categories were used: Industry - I4-1(Annual consumption: 418 600 GJ; load factor: 250 days, 4 000 hours). From 2008 on, the following Eurostat end consumer category is used: Band I4 : 100 000 GJ < Consumption < 1 000 000 GJ All retail prices are net of taxes.

3. 
European Electricity Markets

While traded volumes of power in the EU have not grown to the same extent
as traded volumes of gas in recent years, power market liquidity[21] showed an almost continuous increase
between 2005 and 2011. Increasing market liquidity is essential for the proper
functioning of a wholesale market and for the formation of competitive prices, ensuring
welfare benefits for consumers.

As a direct result of the increasing role of wholesale power trading
markets in Europe, electricity prices are increasingly being determined by the
relationship of demand and supply in the market.

In the process of integration of wholesale electricity markets among
neighbouring countries, market coupling in the EU is playing an increasingly
important role. Market coupling enables players to trade directly between
markets by benefiting automatically from cross-border capacities without having
explicitly acquired the necessary transmission capacity in individual markets.

In the power markets of Central West European (CWE), where market
coupling took place in November 2010, a steep drop in adverse power flows
(flows going from a high price area to a low price area) was observed in Q4
2010, and adverse flows became virtually non-existent in the region from the
first quarter of 2011 onwards. The disappearance of adverse flows and a high
ratio of hourly converging prices within an observed time period both point to a
properly functioning, integrated wholesale power market.

The lack of market coupling prevents prices from acting as effective
signals for the direction of power flows between markets. It should therefore be
regarded as a market-based and effective tool contributing to the achievement of
a single European wholesale electricity market.

Better integration of European wholesale power markets, which has
enabled more convergent wholesale power prices, could be one reason why power
prices did not follow the sharp increase in fossil fuel prices in the last two
or so years. This achievement also underscores the importance of European-level
electricity market policy, and the need to fully implement the successive
energy packages adopted in the last couple of years.

3.1. 
Power supply sources and wholesale markets

Table 8 provides information on the most
important factors that influence the electricity import dependency/exporting
capacity of each Member State of the EU. It is plain to see that the ratio of
both power import and export flows are low compared to the electricity
consumption in those countries which are either geographically isolated from
other European markets, or have only few interconnections (islands such as Cyprus,
Malta, the UK or Ireland) On the other hand, smaller countries (such as
Luxembourg, Slovenia or the Baltic States), with good power grid connections to
their neighbours, have high import or export power flow ratios compared to
their annual electricity demand.

Maximum generation capacity plays an
important role in import dependency, because Member States that have large
generation capacities (e.g. Germany, France, Italy or Spain,) are able to produce more electricity than they consume, and to export the surplus power that
they generate.

According to the data presented above, a
distinction can be made between net electricity exporting countries
(e.g.Bulgaria, Estonia, Czech Republic) and net electricity importing countries
(e.g.Hungary, Lithunania or Latvia). The position of a given country as a net
exporter or importer position depends on the availability of cheap domestic
power generation sources, the size of the generation capacities compared to the
annual power demand and the cost of importing electricity from neigbouring
countries.

The trend in the traded volume of power in
the European wholesale markets also serves as a useful pointer to how the
European internal electricity market is evolving. The next chart shows the
combined traded volume of the European wholesale day-ahead power markets,
including data from all available trading platforms. Between 2005 and 2008 the
combined traded volume of power showed dynamic growth and, after a transitory
decrease triggered by the economic downturn in 2009, it stabilised in 2010-2011
at a level slightly higher than the pre-crisis peak of 2008.

Between 2005 and 2011, there was an almost
continuous increase in market liquidity, which is measured as the ratio of the
traded volume of wholesale day-ahead power contracts and the annual gross
inland electricity consumption in a given country (or group of countries)..
Increasing market liquidity is essential to the proper functioning of a
wholesale market and for the formation of competitive prices, ensuring welfare
benefits for consumers. Although there was no significant increase in power
traded volumes between 2008 and 2011, there was a rise in the liquidity ratio
during that period as a result of decreasing power consumption, which was due
to the sluggish economic recovery and to the increasing efficiency of
electricity use in many European economies.

Central Western Europe (CWE): Germany, France, Belgium, Netherlands, Luxembourg and Austria.

Nor pool (NP): Norway, Sweden, Finland, Denmark and Estonia

OMEL: Spain and Portugal

IPEX: Italy

Central Eastern Europe (CEE): Poland, Czech Republic, Slovakia, Hungary, Romania

DESMIE: Greece

The broadening role of wholesale power trading markets in Europe has meant that electricity prices are increasingly being determined by the relationship
of demand and supply in the market.

The next chart shows the trend of the Platts European Power Index
(PEP, which is a composite price index of the major European markets) side-by-side
with developments in prices of the Brent crude oil spot, German import gas and
coal import contracts between 2002 and 2011. Although the first half of the
period exhibited a strong correlation between the evolution of wholesale power
prices and fossil fuel prices, the increase in fossil fuel prices in more
recent years substantially exceeded the rise in the PEP index. Moreover, although
both power and fuel prices did recover from the lows recorded in the first half
of 2009, the increase in power prices was relatively modest compared to those of
coal, gas and  – especially − oil.

Platts PEP: Pan European Power Index

Brent crude spot: Benchmark price for crude oil in Europe

Coal CIF ARA: Principal coal import price benchmark in North Western
 Europe

DE border imp. long term contract based import natural gas price on the
German border

Better integration of European wholesale power markets, which has helped
wholesale power prices to converge, could be a factor explaining why power
prices did not follow the sharp increase in fossil fuel prices in the last
couple of years. This achievement also underlines the importance of
European-level electricity market policy, and the need to fully implement the successive
energy packages during that period. Apart from market integration, the
increasing deployment of renewable energy sources − mainly solar and wind power
generation − also had a beneficial impact on power generation costs, further
weakening the link between power prices and fossil fuels.

Market coupling plays an important role in the process of the integration
of wholesale electricity markets among neighbouring countries. Market coupling
refers to the integration of two or more electricity markets from different
areas through an implicit cross-border allocation mechanism. Instead of
explicitly auctioning the cross-border transmission capacities among the market
parties, the capacities are implicitly made available on the power exchanges of
the various areas. In this way, market coupling enables players to trade
directly between markets by benefiting automatically from the cross-border
capacities, without having explicitly acquired the requisite transmission
capacity across markets.

The next chart illustrates the benefits of market coupling. It shows
the quarterly trend of adverse power flow ratios between neighbouring European markets
in 2010-2011. Adverse cross border flows occur when commercial nominations for
cross border capacities are such that power is set to flow from a higher price
area to a lower price area. Adverse power flow ratios are calculated as the number
of hours during which adverse flow occurred in a quarter compared to the number
of hours of available power flow data for that quarter.

In those Central West European (CWE) markets where market coupling
took place in November 2010, a steep fall in adverse power flows was observed
in Q4 2010, and adverse flows were virtually non-existent in the region from
the first quarter of 2011 onwards. Disappearing adverse flows and a high ratio
of hourly converging prices within an observed time period both point to a properly
functioning, integrated wholesale power market. In 2011, the difference in hourly
power prices in the CWE region was less than 1% between all participating
markets in 64% of all hourly price observations.

Note: The Market Coupling took place on the 9th of November 2010 in the
Central West European Region

By contrast, in the Central Eastern European (CEE) region, where
market coupling exists only between the Czech Republic and Slovakia, adverse flow ratios remained permanently high during the period presented in the above chart.
The absence of market coupling prevents prices from acting as effective signals
for the direction of power flows between markets. In practice, it prevents
flows being directed from low price to high price areas, even in cases where
there are considerable price differentials between neighbouring markets. Besides
high adverse flow ratios, the CEE region can also be characterised by a low proportion
of price-converging hours among the different markets. The difference in power
prices in the CEE region was less than 1% in only 3-15% of the total hourly
observations in 2011, which was significantly lower than in the case of the CWE
region.

The obvious difference between the CWE and the CEE regions, as far
as the number of 'price-converging' hours and adverse flow frequencies is
concerned, further underlines the importance of promoting market coupling in
those power regions where it does not exist at present. Market coupling
should be regarded as a market-based and effective tool contributing to the achievement
of a single European wholesale electricity market.

The next table provides an overview of the trend in the annual
average day-ahead baseload power prices in the European power markets between
2009 and 2011., Prices in most of the observed markets in 2010 showed a
significant upturn compared to 2009, mainly as a result of the increasing
demand for power, in parallel with the economic recovery and increasing fossil
fuel prices. In 2011, prices rose further in many markets, although they fell in
the Nordic countries due to a milder winter and better hydro availability. Annual
average wholesale power prices in the CWE region rose in 2011 compared to 2010;
this was also due to the impact of the German government's decision to immediately
take eight nuclear reactors out of the power grid in spring 2011, following the
 Fukushima nuclear power plant accident in Japan. Although Austria is not part
of the market coupling in the region, its price trends closely those of the
German market, due to the agreement between EXAA and EPEX markets that enables
market participants to trade on both platforms.

The Nordpool spot market is the other large market coupling area in
Europe where prices were among the lowest on the continent, since the abundant hydro-based
power generation in Norway and Sweden had a beneficial impact on the whole
region. However, this effect was more limited in those countries (e.g. Finland or Denmark) which have fewer direct interconnections to these cheap hydro-power sources.

Annual average prices in the Central East European region increased
between 2009 and 2011, following their West European peers and responding to
increasing demand, as the economies of these countries started to recover.
Prices in Hungary, Romania and Slovenia were severely affected during certain
periods by the volatile demand for power in the Balkan countries; thereby providing
the power utilities of these three countries with excellent power exporting
opportunities, but resulting in higher wholesale prices in their domestic
markets.

Spanish and Portuguese power prices were strongly influenced by the
availability of renewable energy sources (hydro, wind and solar). In the UK and Italy, where gas fired power generation dominates the power mix, rising natural gas prices
led to power prices which were higher than in major West European markets. Lastly,
markets in Member States which have more limited capacity for electricity
interconnections to neighbouring countries that have a functioning wholesale
power market (such as Greece and Ireland) were normally characterised by higher
power prices than in other European markets.

Table 9. Annual
average day-ahead baseload power prices (€/MWh)

Source:
Platts, European power trading platforms

More detailed information on developments in the EU markets for
electricity can be found in the European Commission's Quarterly Reports on
European Electricity Markets[22].

3.2. 
Market structure and unbundling

There are significant differences between Member States in terms of the structure of the electricity generation and retail distribution markets.
Although there are between one and eight electricity utilities with more than
5% share of total national generation, the total number of power generation
companies representing at least 95% of national generation reached a
three-digit or even a four-digit figure in certain EU countries (e.g. Germany,
Netherlands and Denmark, see next table). However, such a low concentration of
electricity generation is unusual in the EU. As the table also shows,
concentration in electricity generation is high in most of the EU Member
States.

On the retail side, there is a similar picture as far as the number
of market participants that provide at least 5% of the national electricity
consumption - and also the number of retail companies - are concerned. However,
the link between the concentration in power generation and in the retail sector
is not particularly strong, as there are many countries where higher
concentration in power generation does not necessarily involve a high
concentration in the retail sector or vice-versa.

Table 10 Structure of
the electricity market

Source Eurostat, 2010 data and National Regulators

(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 sell at least
5% of the total national electricity consumption

The next two tables provide information on the unbundling solutions
applied for the Transmission System Operators (TSOs) and for the Distribution
System Operators (DSOs) in the EU Member States.

According to data from the national regulators for 2010, the
majority of EU Member States have only one TSO. The exceptions are: the Netherlands (two), Austria, the UK and Portugal (where there are three), Germany (four) and Italy, which has eleven TSOs. Ownership unbundling has taken place in about half of the EU Member
States. The share of public and private ownership in unbundled TSOs reveals a wide
range of situations among the EU Member States in 2010.

There are at least 800 DSOs present in Germany, many of which could
be linked to the so-called "Stadtwerke", which perform electricity
distribution functions and other public services. In most of the EU Member
States, legal unbundling seems to be more typical than ownership unbundling in
the case of DSOs. With the exception of Hungary and Slovenia, there are DSOs in
the EU Member States providing electricity for less than 100,000 customers. In the
majority of these countries, exemptions from DSO unbundling rules provided for
in Article 26 of the Electricity Directive (2009/72/EC) are applied in the
cases of DSOs which have fewer than 100,000 customers.

Table 11: Unbundling
of transmission system operators (TSOs) in Electricity - 2010

Source: CEER
database

Table 12: Unbundling
of distribution system operators (DSOs) in Electricity - 2010

Source: CEER
database

[1]       http://ec.europa.eu/europe2020/making-it-happen/country-specific-recommendations/index_en.htm

[2]       Share of renewables in gross final consumption (indicator
used for the 2020 target of 20%). The share of renewables in gross inland
consumption (energy mix) was 10% in 2010.

[3]       See definition under section 3.1

[4]       Central Western Europe (Germany, France, the Netherlands, Belgium and Luxembourg); Nordpool (Sweden, Finland, Denmark, Estonia, Lithuania and Norway), Czech Republic/Slovakia/Hungary, Slovenia/Italy, Spain/Portugal,
Poland/Sweden. Central Western Europe and Nordpool are also coupled.

[5]       According to the PRIMES baseline scenario.

[6]       Due to revisions of statistics, these numbers are not
necessarily the same as presented in previous annual reports.

[7]       Import dependency is measured as the
ratio of net imports to gross inland consumption plus international marine
bunkers.

[8]       SEC(2011)1565 final p136

[9] See
definition in Directive 2009/28/EC- Article 2 f). The objective set in the
Directive is to achieve a 20 % share of energy from renewable sources in the
EU’s gross final consumption of energy and a 10 % share of energy from
renewable sources in each Member State’s transport energy consumption by 2020.

[10]     Reference to the SWD on Investment projects in energy
infrastructure

[11]     See also section 1.2.4. Throughout 2011
the EU GDP growth rate was steadily decelerating, with every quarter recording
annual growth lower than the previous quarter.

[12]     Import dependency is defined as the ratio of net imports over
the sum of gross inland consumption and bunkers. The EU import dependency is
net of intra EU trade; calculated at national level however, it includes the
intra EU trade.

[13]     IEA Medium Term Gas Market Report 2012.

[14]     Price for a metric tonne of coal (calorific value of 6 000 kcal / kg) delivered at the Amsterdam-
Rotterdam-Antwerp area with cost, insurance and freight covered.

[15]     Publicly available at : http://ec.europa.eu/energy/observatory/gas/gas_en.htm

[16]     The data in this section refers to consumption band D2 for
households [annual consumption 5,56 MWh – 55,6 MWh] and I3 for industry [annual
consumption 2,77 GWh – 27,8 GWh].

[17]     Consumption bands D2, all taxes included. The ratio of highest
to lowest price in the same consumption band excluding taxes increased, from
2.74 in 2008 to 4.47 in 2011.

[18]     Consumption band I3, all taxes included. The ratio highest to
lowest price in the same consumption band excluding taxes increased from 2 in
2008 to 2.8 in 2011.

[19]     Consumption band D1 for households: annual consumption up to 5,56
MWh.

[20]     Consumption band I1 for industry: annual consumption up to 0.28
GWh.

[21]     See definition under section 3.1

[22]     Publicly available at : http://ec.europa.eu/energy/observatory/electricity/electricity_en.htm