Introduction

The purpose of the Country Reports in this Staff Working Document is to take stock of the state of play, both in quantitative and qualitative terms, of the implementation and functioning of the energy market in the 28 Member States of the European Union.

These country reports are based on the most recent information available to the Commission during the first half of 2014. In order to allow for comparability a similar structure and set-up of these reports has been chosen as the structure used in the previous reports as published together with the Internal Energy Market Communication of November 2012. There is one significant difference: for each country a new Chapter on the electricity and gas security of supply situation has been added for each country.

As to the data used, the primary source of information is Eurostat. The data used to produce the figures included in the country reports on gross inland energy consumption, gross electricity generation and electricity and gas price changes are sourced from Eurostat. Also a significant part of the information included in the table with key indicators is sourced from Eurostat. This holds for information on the number of companies, market shares, market values, and (partly) installed generation capacity. Alternatively, installed generation capacity is taken from ENTSO-E’s Yearly Statistics & Adequacy Retrospect 2012.

Information included in the table with key indicators on switching rates, regulated prices and HHIs is mostly provided by the NRAs. Typically this information is taken from the NRAs’ national reports for 2012. National Regulatory Authorities (NRAs) have been given the opportunity to comment on draft versions of the reports related to their country and all 28 NRAs have done so.

In these reports we have also strived to give a country-individual breakdown of gas and electricity retail prices, showing the composition of these prices in an energy, a network and a tax component (based on Directive 2008/92/EC, Annex I) and demonstrating the development between 2009 and 2012. This work is a follow-up of the data gathering exercise carried out in the context of the Energy Prices and Costs Communication earlier in 2014. On the basis of the data gathered we have not been able to provide meaningful graphs related to gas prices for Austria, Finland, Greece and Ireland.

The chapter in each country report on consumers contains information on consumer satisfaction from the Commission's DG SANCO’s market monitoring surveys. The number of smart meters is taken from varying national sources. The remaining information on consumer affairs included in this chapter is typically provided by NRAs.

The chapters on the regulatory framework, wholesale markets, infrastructure and security of supply contain information from a variety of (mostly national) sources. Frequently used sources are publications by Ministries, NRAs, TSOs, ACER, CEER and DG Energy. References to these sources are included in the reports.

Austria

Key issues

In the electricity sector, market coupling with Southern and Eastern neighbouring countries would be beneficial.

In gas, the number of system operators could be reduced in view of the new gas-market model. An extension of the gas network based on market demand is needed to enable injections and withdrawals on a firm basis from the gas storage capacities. The efficiency of the gas balancing regime should be improved in order to create a level playing field on the retail market.

General overview

Energy consumption in 2012 (33.7 Mtoe) was based largely on crude oil and petroleum products (35.54%), renewables (30.05%) and natural gas (22.8%)[1]. Austria has committed to reach 34.2% of RES share in gross final energy consumption by 2020. The country is showing good progress towards its European target as the RES share in 2012 was 32.1%[2], well above its 2011/2012 indicative trajectory.

Figure 1: Gross inland consumption mix 2008 – 2012 (source: Eurostat)

In 2011, approximately two thirds of the electricity generated (67.5%) was provided by renewables and 21.8% by natural gas.

Figure 2: Gross electricity generation mix 2008 – 2011 (source: EU Energy in Figures - Pocketbook 2012 and 2013)

Cogeneration[3] accounted for 15.7% of the total electricity generation in 2011, which is in line with the last few years[4]. The relevant indicator for pump storage generation (base/peak spread) decreased by 10.5% (EUR 11.5/MWh) and the generation from hydro power stations reduced due to high tides and dry periods. Full load hours of gas fired power plants reduced by 17.9% in 2012 (1859 hours, 2011: 2265 hours).

Regulatory framework

General

The Directives of the Third Energy Package were transposed into national law in 2010 for electricity and in 2012 for gas.

An important development has been the introduction of an entry-exit system in gas in January 2013, replacing the previous system based on contractually agreed transport paths. Austria has three market areas and entry-exit zone (East, Tirol and Voralberg). As the market areas of Tirol and Voralberg are neither connected with East or each other but supplied via the market area Net Connect Germany, they have been partly integrated in to the German market area Net Connect Germany (NCG) since October 2013. Approximately 95% of Austrian gas consumption takes place in the Eastern market area. The new regime foresees that any gas transported through the Austrian network is traded at a centralised virtual trading point (Central European Gas Hub – CEGH) both bilateral and exchange trades are possible. The new regime also foresees new balancing rules of which the efficiency is however not proven. The new market model delegates system-relevant tasks to a number of system-operators beyond the TSOs and DSOs (Distribution Area Manager, Market Area Manager, Clearing and settlement agent, Operator of the virtual trading point) which leads to administrative burden for market participants.

National Energy Regulator

In 2012 the Austrian Energy Regulator “Energie-Control Austria für die Regulierung der Elektrizitäts- und Erdgaswirtschaft” (E-Control) had an average of 113 employees and a budget of around EUR 20 million[5].

Unbundling

The electricity TSO Austrian Power Grid (APG) was legally unbundled in March 2012 from its shareholder Verbund AG, whose main shareholder is the Austrian Government (51%). APG was certified as an Independent Transmission Operator (ITO). The second electricity TSO in Austria, Vorarlberger Übertragungsnetz GmbH (VÜN), whose main shareholder is the federal state Vorarlberg (51%), was certified as an Ownership Unbundled TSO in June 2012. The gas TSO, Gas Connect Austria GmbH (GCA) was for the first time certified as an ITO in July 2012 and received in July 2014 an updated certification as ITO covering the operation of WAG pipeline which was until September 2014 operated by Baumgarten-Oberkappel Gasleitungsgesellschaft mbH (BOG). [6] After the rejection of the application to be certified as ISO in March 2013 Trans Austria Gasleitung GmbH (TAG) was in July 2014 certified as ITO.

Wholesale markets

Electricity

On the Austrian energy exchange for electricity (EXAA, Energy Exchange Austria), electricity is traded on a day-ahead basis for delivery in Austria or Germany. In the absence of congestion, the wholesale market for electricity is fully coupled with Germany and forms a single price zone. Therefore electricity can also be traded at EPEX Spot situated in Paris on an Intraday and Day-Ahead basis for the Austrian/German delivery zone. Similarly, derivatives at EEX (European Energy Exchange) situated in Leipzig, such as Phelix Futures can be traded for Austria/Germany. Hence, through Germany, Austria is indirectly coupled with the North West European electricity market. It is not yet coupled with its Eastern and Southern neighbours.

The average wholesale electricity price was EUR 51.9/MWh in 2011 but decreased in 2012, caused mainly by the low worldwide prices for coal and emission certificates, increasing generation of subsidised RES in the joint German-Austrian price zone and a bleak economic outlook. In summer 2013 Austria has introduced an obligation for electricity suppliers supplying Austrian end consumers to provide a certificate of origin of the energy supplied. It will need to be assessed further whether this new obligation restricts imports of supplies from other Member States.

Gas

The wholesale gas market in Austria was still very concentrated (Herfindahl-Hirschmann Index - HHI - of 3,371) in 2011. The wholesale gas market in particular was affected by significant price changes, which brought about major developments. On the one hand, new suppliers made use of the opportunity to enter the relatively high-priced retail gas market (including household consumers), which led to a larger spectrum of rates available. On the other hand, suppliers adapted their contracts with importers to reflect better actual market conditions, i.e. adjusting their prices to the short-term spot market.[7]

Being dependent on gas imports, it is essential for Austria to have cross-border transport capacity available to gas traders. In the past years, new entrants wanting to trade in the Austrian gas market faced congestions in the transmission system at the border with Germany and therefore only had limited access to transport capacity. With the implementation of the European guideline on congestion management procedures and the European network code on the allocation of capacity in gas pipelines, this situation has improved significantly.

In 2012, the average price for natural gas was EUR 26/MWh, a small increase from 2011. In 2012, the price varied between EUR 25/MWh and EUR 27/MWh, except in January and February 2012 when prices of up to EUR 39.5/MWh were recorded, which is the highest price seen at CEGH. This significant increase was due to extraordinary temperatures and lower imports from Russia. Usually spot prices at CEGH are above the German NCG prices, however in the fourth quarter of 2012 this spread was reversed. At CEGH a total volume of 48.9 bcm was traded OTC in 2012, which is a significant increase compared to 38.9 bcm in 2011. The average churn rate was 3.53 in 2012 and 3.38 in 2011. On the normal exchange 3.06 TWh was traded in total.[8]

The total Austrian gas demand was 4.391 Mtoe in 2011 of which approximately one third came from national production[9]. In 2011, the largest share of the imported gas came from Russia (52%). Austria also exported natural gas to Germany and Italy.[10]

Retail markets

Electricity

The retail market can be divided into three different sections: households, small business companies and large scale consumers with special contracts. The number of active suppliers for households decreased from 143 to 139 in 2011 and for small business companies from 142 to 137 as some smaller suppliers were taken over by bigger ones. The market consists just of domestic suppliers for households and SMEs, of which 15 are operating at a national level and the remainder-wide, the others are regional suppliers. This implies that there are regionally operating suppliers. For special contract consumers the number of suppliers has not changed, giving industrial customers a chance to choose between 12 different suppliers.[11] , which are either domestic or foreign suppliers. Normally, foreign suppliers only offer contracts if a certain amount (10-20 GWh) is supplied.[12]

Market concentration has not changed considerably and remains at a high level given the HHI of 1,769 for household customers (2011: 1,764) and 1,685 for commercial customers (2011: 1,696). The overall market share of the three largest retailers (for households and SMEs) remained at a level of about 56% across all consumer groups. Alternative suppliers gained some market share relative to the local suppliers who still have a strong market power.

Figure 3: Electricity price change by component 2008 – 2013 (source: Eurostat, energy statistics)

The household energy price increased by 3% in 2012 (EUR 0.2224/kWh), which is higher than the average electricity price in the EU (EUR 0.2061/kWh). In 2013, household prices consisted of energy costs (41%), network costs (25%) and taxes and levies (34%). Prices for industrial customers have decreased since 2010 and in 2012 the reduction was about 4.5% for large industrial customers.

Most of the suppliers slightly reduced their prices at the beginning of 2012 mainly because the reduction of transfer prices for the mandatory acquisition of renewable energy. Following the renewal of the law in respect of renewable energy (ÖSG), the costs for renewable energy became transparent and understandable as they are determined by law. Additional price reduction due to the positive developments on the wholesale market has not been passed through to the household customers by the suppliers.

Regarding smart meters, a cost-benefit analysis came out in favour of smart meters for both electricity and gas. A Ministerial Decree mandated the roll-out of smart meters for electricity customers by the end of 2019 at the latest with a specific timetable for implementation. A modification, in 2013, to the Elektrizitätswirtschafts-und-organisationsgesetzes of 2010 makes provision for up to 5% of consumers to express the wish to their supplier not to have a smart meter installed.

Regarding switching of energy supplier the switching rate dropped from 1.5% to 1.1% in 2012. In contrast, the switching rate of specially metered customers increased by almost 50% (to 6.8%) New rules, which came into force on 1 January 2013, have probably contributed to an increase in the number of consumers who subsequently switched gas and electricity supplier. During 2013, 148,000 consumers and businesses switched supplier. This represents an increase of 68% in comparison with 2012.

Gas

The Austrian gas market is divided into two segments. Prices for small consumers (households, smaller consumers etc.) with a consumption of less than 400 MWh are published. For large customers with consumption above 400 MWh, the prices and conditions are negotiated individually. In 2012, 49% of household prices were for the energy itself, network costs accounted for 22% and VAT and energy taxes made up the remaining 29%.

Market concentration for the small consumer group is still very high (HHI: 3,726) even though it reduced by 8% in 2012. The cumulated market share of the three largest gas suppliers was 72% in 2012. The largest individual market player is EnergieAllianz Austria GmbH with a market share of 60%. EnergieAllianz Austria GmbH includes the retail companies: Wien Energie GmbH, EVN AG and Energie Burgenland AG.

In 2012, about 23,400 final customers changed their supplier (about 1.7% of all final customers in Austria). Since January 2013 the process has been further simplified, so that the switching process can be successfully completed within three weeks.

Consumers

Overall consumer assessment of the retail electricity market is above the EU average (77.0 points compared to 72.0), corresponding to 8th place EU-wide. The market is also assessed just above the average of 31 domestic services markets (15th place). The electricity market has the second highest score in the EU on the 'overall consumer satisfaction' indicator. However, consumer assessment of the retail gas market is just below the EU average (74.0 points vs. 74.1[13], ranked 17th) as well as below the average of the 31 domestic services markets (ranked 21st). While the score on comparability has been increasing (although slowly) every year since 2010, it remains 4th lowest in the EU. Both electricity and gas markets have improved their performance since 2012 (respectively by 2.8 and 2.2. points).[14]

E-Control has launched a service hotline for all gas and electricity customers[15] where customers can find a wide range of information on electricity and gas markets. In 2012, the hotline recorded 6,373 calls, which is a reduction of 33.4% on 2011 when the price comparison tool was introduced. The main reasons for calling the hotline were related to questions on switching and energy bills. In addition, E-Control offers a wide range of online applications. About 500,000 customers used the so-called “Spritpreisrechner” calculator to identify the cheapest petrol station.[16] Furthermore, a significant number of customers checked their opportunities for saving of energy in their households.

In 2012, the rights of vulnerable customers were strengthened. If consumers fail to pay their bills, then the supplier may only switch off supply after repeatedly sending reminders, including threatening disconnection. Moreover, suppliers are obliged to deliver natural gas or electricity to vulnerable costumers who claim their respective right, at their general terms and conditions in force and at rates for universal service to vulnerable costumers that may not exceed the rates at which most of their customers are supplied (universal service obligation).

Whilst a protection mechanism for vulnerable customers does exist in Austria, the authorities have still to make a precise definition of the concept of vulnerable customers.

New regulatory guidance (ordinance) has been put in place defining the format of consumption information by system operators towards consumers. These measures seem to have had a positive impact on the overall consumers' assessment of both electricity and gas markets between 2012 and 2013.

Infrastructure

In accordance with the TEN-E Regulation, Austria has designated one national competent authority responsible for facilitating and coordinating the permit granting process for the Projects of Common Interest (PCIs) in gas and electricity (“one-stop-shop”).

Electricity

The Austrian energy market faces substantial challenges due to the proposed increase of electricity from renewables and the integration of European energy markets. The high capacity high-tension 380-kV ring in Austria remains to be completed and cross-border capacities to Italy, Slovenia, Switzerland and Germany enhanced. To address these mentioned challenges extensive network reinforcements and network expansion are required. Therefore Austria is involved in 13 projects of common interest (PCI) under the guidelines for trans-European energy infrastructure, including large scale projects like the new construction of the 174 km long Salzburg line (380 kV) with a capacity of 2 x 2400 MVA. Remaining PCIs include five internal lines, three interconnectors to Italy and three hydro-pump storages.

Gas

In gas, the network development needs to be closely coordinated with neighbouring countries especially with regard to the development of new gas sources from the Caspian Region.

Gas Connect Austria (in its role as Market Area Manager) established the second Coordinated Network Development Plan (KNEP) for the Austrian Market Area. Potential bottle-necks have been identified at the entry-exit points Überackern SUDA and ABG, 7 Fields, and the exit point Mosonmagyaróvár. Even though extension was requested on a non-binding basis for Penta West to offer guaranteed capacities for the use of storage and incremental capacity at the entry-exit point Überackern[17], no bookings were made in the course of the auction of the respective incremental capacity via Prisma in March 2014. A total of six projects of common interest in the gas sector are carried out by Austria.

Security of Supply

Electricity

Generation capacities are expected to rise by 6.7 MW until 2020. The overall generation capacity will then be 29.6 MW, what implies that there should be no issues of generation adequacy. However, in periods when hydro generation capacities are not able to generate due to high tides or dry periods and gas fired stations are no longer running, maintaining security of supply may need complementary measures.

Gas

Given the latest survey regarding the security of gas supply Austrian suppliers fulfil the requirements of Regulation 994/2010. One important element is the storage capacities (67.8 GWh) which cover about 90% of annual gas demand (91.2 GWh).

Key indicators

Electricity || || Gas ||

Number of companies representing at least 95% of net power generation || 145 || Number of entities bringing natural gas into country || 6

Number of main power-generation companies || 4 || Number of main gas entities || 3

Market share of the largest power-generation company 2012 || 56.6% || Market share of the largest entity bringing natural gas || N/A

Number of electricity retailers || 152 || Number of retailers selling natural gas to final customers || 41

Number of main electricity retailers || 6 || Number of main natural gas retailers || N/A

Switching rates (entire electricity retail market) || 1.1 || Switching rates for gas (entire retail market) || 1.7

Regulated prices for households – electricity || No || Regulated prices for households – gas || No

Regulated prices for non-households – electricity || No || Regulated prices for non-households – gas || No

HHI in power-generation market || N/A || HHI in gas supply market || 3,371

HHI in electricity retail market || ̴1,800 || HHI in gas retail market || ̴2,200

Electricity market value[18] (bn€) || 7.265 || Gas market value19 (bn€) || 2.658

Installed generation capacity (MW, 2011) || 22,787 || ||

Peak demand (MW) || 11,617 || ||

Number of Smart meter installed || 590 || ||

Belgium

Key issues

The level of market concentration remains high, despite a high switching rate of consumers that tend to reduce the market share of incumbent suppliers on the retail markets.

Due to changes in the generation mix and retirement of generation capacity, risks for security of supply will increase in the upcoming years. Increased cooperation with neighbouring countries and demand side response are required to tackle such risks. Efforts to further integrate the physical grid and electricity markets with neighbouring countries should be pursued. Enhanced interconnection could help to accommodate peaks in demand.

Belgium should take measures to further stimulate consumer empowerment leading to enhanced retail competition. This is necessary to ensure that when decrease in wholesale gas and electricity prices is observed, it is also passed on to the final consumers.

Belgium should also ensure that distribution charges reflect efficient costs of distribution, network operations and development. Proper regulatory oversight at federal as well as regional level is essential to ensure that all network tariffs reflect efficient costs and are incentive based.

General overview

Gross energy consumption in 2012 (56.3 Mtoe) was based largely on crude oil and petroleum products (39.0%), natural gas (27.0%), and nuclear energy (18.5%). Solid fuels and renewable energy sources (RES) were less important in the energy mix (with shares of 5.3% and 5.9%, respectively)[19].

Figure 1: Gross inland consumption mix 2008 – 2012 (source: Eurostat)

The power generation mix in 2012 (82.9 TWh) was dominated by nuclear power (with a share of 48.6%) and by gas-fired plants (30.9%). RES and solid fuels accounted for 14.2% and 0.12% respectively[20]. Electricity demand in Belgium decreased by 2.8% in 2012 compared to the 2011 level.[21]

Figure 2: Gross electricity generation mix 2008 – 2011 (source: EU Energy in Figures - Pocketbook 2012 and 2013)

Belgium’s renewable energy target is 13 % by 2020[22]. In 2012, the share of renewables in gross final energy consumption reached 6.8%[23] and the country is on track to achieve its 2020 national RES target. Belgium also has plans to reduce its greenhouse gas emissions by 15%, but these have yet to be aligned with regional initiatives.

Regulatory framework

General

The Third Energy Package was transposed into national law by a law issued on 8 January 2012. This resulted in an increase in the powers of the national regulator, while at the same time strengthening consumer protection and increasing the competence of regional authorities.[24]

The indexation of the energy component of electricity and gas prices was capped provisionally from 1st April 2012 to 31st December 2012. The aim of the Belgian authorities was to increase transparency and price comparability in variable contracts, protecting the consumer against price increases based on opaque indices and information asymmetries. These measures and the subsequent public debate encouraged Belgian consumers to become more price-conscious and ignited their interest in changing providers.

To further increase competition and liquidity in the Belgium gas market a new entry-exit transmission model was implemented as of 1st October 2012.

National Regulatory Authority

In January 2014, the Belgian federal energy regulator, the CREG ("Commission de Régulation de l’Électricité et du Gaz") employed 64 employees (including 1 president and 3 directors) and had an annual budget of EUR 14,952,254.[25] Its independence from the Ministry was increased by the provisions of the law of January 2012 and the decision of the Constitutional Court of 7th August 2013, which confirmed that the regulator had exclusive jurisdiction with respect to application, determination and exemption of tariffs. Since 1st July 2014, the competence for setting distribution tariffs has been transferred to the regions. Regional regulators (CWaPE in Wallonia, VREG in Flanders, BRUGEL in Brussels) are now responsible for the control of tariffs regarding public distribution of gas and electricity (low-voltage (≤ 70kV) or low-pressure networks).

Unbundling

The CREG certified S.A. Elia System Operator (Elia) as the Belgian TSO for electricity as fully ownership unbundled on 6 January 2012, along with S.A. Fluxys Belgium as TSO for natural gas on 12 October 2012 and Interconnector (UK) on 11 July 2013.

Elia has been listed on the stock exchange since 2005. Its core shareholder is the municipal holding company Publi-T (45.22%), founded in 2001 when Elia was established.

Major shareholders of S.A. Fluxys Belgium are Euronext Brussels (10,03%), Belgium State (1%) and Fluxys Holding (89,97%). Fluxys Holding, parent company of S.A. Fluxys Belgium, is owned by a municipal holding Publigas (77.7%) and Caisse de dépôt et placement du Québec (20%).

The regional governments of Flanders, Wallonia and Brussels-Capital have also transposed the DSO unbundling provisions of the Third Energy Package in their respective legislations for the 24 electricity and 18 gas DSOs.[26] Articles 28 of Directives 2009/72/EC and 2009/73/EC, relating to Closed Distribution Systems (CDS), have been transposed into law in the Flemish and Walloon region. In the Walloon and Brussels-Capital regions, the new concept of CDSs has not (yet) been introduced, but its legislation provides for a concept of private distribution networks.

Wholesale markets

Electricity

The Belgian electricity generation market is still highly concentrated (Herfindahl Hirschmann Index – HHI- in: 2013 of 4,770 and 7,390 in 2008) but it has been improving as the generation market share of Electrabel (2013: 67%) dropped significantly in the last 5 years[27]. The three largest firms, Electrabel, EDF Luminus and E.ON had a market share of 89% in 2013. The average price on day-ahead wholesale market in 2013 (EUR 47.45/MWh) at the Belgian exchange market Belpex was slightly higher than in 2012 and about two euros lower than in 2011. At the same time the total trading volume increased from 12.3 TWh (2011) to 17.0 TWh (2013). The sharp increase in traded volume correlates with a reduced availability of two nuclear power plants at the end of 2012. The number of market participants on the Belpex Day-Ahead Market has increased significantly in recent years and totaled 42 at the end of 2013.

Gas

Eighteen supply companies operated in 2012 on the Belgian gas wholesale market. The largest supplier was Eni Gas & Power with a market share of 36.9% in 2012 (2011: 45.7%). GDF Suez is the second largest supplier on the market with 31.9% market share (+4.5 % in 2012). EDF Luminus also strengthened its third place (10.2% in 2012, up 1.6%). The remaining fifteen supply companies hold market shares of less than 5% each and nine of these do not even reach 1%. The level of market concentration, although still high, has improved (HHI 2013: 2,332)[28], as pressure is exerted by emerging companies.

The total natural gas consumption was constant at 185.6 TWh (+1.2%) even though end-consumers connected to the distribution networks increased their consumption (+11.5%). However, at the same time consumption for electricity generation (possibly combined with the production of heat) dropped by 10.7% and consumption by industrial customers dropped by 3.3%. Most gas supply is provided via direct long term contracts (duration > 5 years) with natural gas producers (61.9% in 2012). However, the share of short-term contracts (< 1 year) grew from 22.3% in 2011 to 33.9% in 2012.[29] This effect was supported by the recently set up virtual trading point ZTP(L) (Zeebrugge Trading Point) as part of the new entry-exit regime.

Retail markets

Electricity

Despite reduction of the largest three players’ market shares, concentration was still high in 2012. The largest supplier was Electrabel Customer Service (ECS) with a market share of 45% (2011).

Figure 3: Electricity price change by component 2008 – 2013 (source: Eurostat, energy statistics)

The electricity prices for household consumers declined from EUR 0.1590/kWh in 2012 to EUR 0.1583/kWh in 2013[30] and for industrial consumers from EUR 0.0950/kWh to 0.0914/kWh.[31] In 2013 the share of energy and supply costs was 38,75% of household prices, while the share of network costs was 37,25%. Taxes and other levies made up for the remaining 24%.[32]

On 1st April 2014, a VAT reduction from 21% to 6% on electricity entered into force.

Gas

On the gas market, concentration is still high. In 2012, especially in the Flanders region, the market share of the largest three retailing companies fell from 91.26% to 76.01%. The HHI also fell in the Brussels region from 7,402 to 6,476. As in the electricity market, ECS was the largest supplier.

Figure 4: Natural gas price change by component 2008 – 2012 (source: EC, EPCR metadata)

Smart meters

Belgium formally decided, under current conditions, not to proceed until 2020 with the wide-scale roll-out of smart meters in the electricity and gas markets as the outcome of the cost-benefit analysis conducted by the regional regulators were negative.[33]

Each of the three Belgian regions (Flanders, Wallonia and Brussels-Capital) has been in charge of their region-specific cost-benefit analysis (CBA) for the smart metering roll-out.[34]

Consumers

Consumers' assessment of the retail gas and electricity markets is above EU average (75.7 points vs. 74.1[35] and 75.6 vs. 72.0, respectively), which in both cases corresponds to the 11th position in the EU ranking. The gas market has improved by 6.7 points since 2012 and the electricity market by 7.4 (highest and 2nd highest in the EU). Both markets have the highest proportion of consumers switching tariff plan or service provider in the EU (about 3 times higher than the EU average), and choice of providers and the ease of switching are within the 5 best ratings in the EU (the latter component is assessed 3rd highest in the EU for the gas market). While the incidence of problems in both markets is below the EU average, the number of consumers complaining is higher than average (2nd highest in the case of gas services). Especially the share of complaints to third parties is 3rd highest in the EU. [36]

The improvement of market performance from 2012 could be linked to several measures taken by the Belgian government: a modification of the energy law making it easier to switch provider; a campaign organised together with local communes informing and assisting consumers in using comparison tools for comparing energy prices; and promotion of joint energy purchases. The information campaigns that took place in 2012 were continued in 2013; at least one collective switching was organised by a consumer organisation. New regulatory guidance specified that contract termination can take place at any moment without cancelation fees (as long as the one month notification period is respected).

Customers became more price-conscious and suppliers kept their prices constant in 2013 after the end of the provisional capping. Since 2013, suppliers’ prices are more transparent and through the introduction of the safety net regulation these prices are constantly monitored by the CREG. As a result, the average price of the electricity and gas component is now moving closer to the average prices seen in neighbouring countries.

However, there is still divergence among the various regions in Belgium. A positive outlook is seen for Flanders, but not for Wallonia, as reported by regional regulators.

The number of customers benefiting from social tariffs remained stable compared to 2011 (400,000 for electricity and 230,000 for gas). The Federal Mediation Service for Energy received 8,331 complaints during 2012 (compared to 8,736 complaints in 2011). Of these complaints, 50% were considered admissible.

Infrastructure

The Belgian authorities have establish a one-stop-shop for the permitting of Projects of Common Interest (PCIs) pursuant the TEN-E Regulation and a cooperation agreement between the Federal State and the Regions on the establishment of the Coordination Committee has been signed.

Electricity

The Belgian network forms an integral part of the European transmission network and has connections with the Netherlands, France and Luxembourg. The infrastructure at the interconnection point also includes phase shifters, which limit the impact of loop flows which originate most frequently from Germany and help to stabilize the grid in Belgium and in the region.

Several projects have been identified as PCIs in accordance with the guidelines on Trans-European energy network as they are cross border connections and improve security of supply. The “NEMO” project will create the first interconnection to the United Kingdom via the North Sea. The “ALEGro” project will also create the first direct interconnection to Germany. Finally there is another interconnection project with Luxembourg.

Gas

Belgium occupies a key position in the European gas grids and serves as an important transit country. In particular, the development of the Zeebrugge hub is attracting International trade as a collection of connection points of several pipelines and as an important LNG terminal, which contributes significantly to the security of supply in North-West Europe. In addition, Belgium is also well interconnected with its neighbours – Germany, France, The Netherlands, and Luxembourg.

Based on market consultation Fluxys Belgium will build additional interconnection lines to the LNG terminal in Dunkirk and Fluxys LNG will build a second landing stage for loading and unloading at Zeebrugge terminal which also qualified as PCI. In addition, there is another project to improve the interconnection of the Belgium gas market to Italy (reverse-flow on TENP).

In total, ten projects involving Belgium have been identified as PCIs.

Security of Supply

Electricity

A combination of factors has led to concerns about generation adequacy in Belgium: the nuclear phase-out, delays in several new plants for fossil-based generation and in the construction of high-voltage lines. These factors have been exacerbated by unforeseen outages in major nuclear units which have reduced the generation capacity by 3 GW.

Elia, as TSO, and the Government have taken measures to address the situation which include an increased strategic reserve and industrial load reduction. An updated plan for controlled regional power cuts has been presented to avoid black-outs in a worst-case scenario.

In the medium term, in order to encourage investments, the Belgian government has launched a call for tender for the construction of new CCGT plants.

Gas

Following the transition to an entry-exit market model, the network was enforced with a new compressor station on the rTr/VTN pipeline in Winksele, which increases entry and exit capacities both in the East and the West. Moreover, Fluxys Belgium reactivated the former liquid nitrogen (LIN) storage tank in Dudzele with a new LIN blending facility in order to stabilize the flows to the UK and to fulfil gas quality conditions. Finally, the gas network towards Luxembourg will be enhanced in order to be able to comply with the anticipated growing demand for natural gas in Luxembourg.

Key indicators

Electricity || || Gas ||

Number of companies representing at least 95% of net power generation || 46 || Number of entities bringing natural gas into country || N/A

Number of main power-generation companies || 2 || Number of main gas entities || N/A

Market share of the largest power-generation company || 65.8% || Market share of the largest entity bringing natural gas || N/A

Number of electricity retailers || 33 || Number of retailers selling natural gas to final customers || 22

Number of main electricity retailers || 4 || Number of main natural gas retailers || 4

Switching rates (entire electricity retail market) || 10% || Switching rates for gas (entire retail market) || 11.2%

Regulated prices for households – electricity || No || Regulated prices for households – gas || No

Regulated prices for non-households – electricity || No || Regulated prices for non-households – gas || No

HHI in power-generation market || 4,010 || HHI in gas supply market || 4,000

HHI in electricity retail market || 3,000 || HHI in gas retail market || 3,900

Electricity market value[37] (bn€) || 9.677 || Gas market value (bn€) || 4.505

Installed generation capacity (MW, 2012) || 20,8 || ||

Peak demand (MW) || 14,234 || ||

Number of smart meters installed || N/A || ||

Bulgaria

Key issues

With regards to electricity, the domestic market is dominated by the Bulgarian Energy Holding and its daughter, the national electricity supply company Natsionalna Elektricheska Kompania EAD (NEK) and characterized by an overcapacity in electricity generation. To attract independent producers and traders, efforts on establishing a well-functioning balancing market including putting into place an organised independent power exchange and day-ahead market should be increased. The existing quota system for power plants in the regulated segment of the market should be phased out gradually and the current single-buyer model should also be removed. Bulgaria needs to gradually phase out regulated electricity prices also for households and small and medium-sized businesses connected at low voltage and take necessary steps towards a competitive retail market. Furthermore, an effort should be made to accelerate the implementation of electricity interconnection points and enhance the capacity to cope with disruptions.

With regards to the gas market, connection of the domestic gas transmission system and the transit system via adequate capacity level remains an outstanding issue and the delays observed in developing interconnections with neighbouring countries should be resolved and promoted. The certification process of the independent gas transmission operator should be completed.

The progressive dismantling of the Bulgarian Energy Holding conglomerate and an ownership unbundling of the transmission system operators would essentially help reducing the dominance of the incumbent company and introduce more competition on the Bulgarian electricity and gas markets.

Bulgaria should also strengthen the independence of the national regulatory authority and its administrative capacity in the energy sector.

General overview

Gross national energy consumption in 2012 reached 18.2 Mtoe, a decrease of 4.5% compared to 2011. The country’s energy mix was largely based on solid fuels (36.3%), followed by nuclear (21.4%) and oil (20.1%). Compared to 2011, solid fuels decreased significantly.

Figure 1: Gross inland consumption mix 2008 – 2012 (source: Eurostat)

Gross electricity generation in 2011 reached 50.8 TWh, with the largest contributor being solid fuels (54.2%), followed by nuclear power (32.1%). Renewables (9.3%) and natural gas (4.1%) also had a visible presence in the electricity mix, while the contribution by oil is negligible (0.3%). Gross electricity generation in 2012 reached 47,3 TWh, with the largest contributor being solid fuels, followed by nuclear power.

Figure 2: Gross electricity generation 2008 – 2011 (source: EU Energy in Figures – Pocketbook 2012 and 2013)

Cogeneration[38] (with 6.7% in 2011) has been in decline since 2008, when it represented 10% of gross electricity generation[39]. The country’s overall renewables target share for 2020 is 16%. In 2012, the renewable share in gross final energy consumption was 16.3%[40] and Bulgaria has thus already achieved its national 2020 RES target.

Regulatory framework

General

The Energy Act was amended in July 2012 to implement the Directives 2009/72/EC and 2009/73/EC[41] and the Energy Efficiency Act was amended in February 2013 to implement Directive 2010/31/EC[42].

The Renewable Energy Act, adopted in July 2012 was amended in 2013 to abolish the “green surcharge for transit“[43] and introduce a fee (or tax) for solar PV and wind production.[44] Also the limitation on the volume of electricity purchased at the feed-in tariff price was amended. Production above the cap will be purchased at the regulated retail price.

National Energy Regulator

The Bulgarian Energy Regulator is the State Energy and Water Regulatory Commission (SEWRC), established in 1999. SEWRC is an autonomous regulatory agency responsible for electricity, heat, natural gas, water and sewerage. In 2012, SEWRC employed 128 staff, with an operating budget of approximately EUR 1.86 million. Although SEWRC's budget increased by EUR 70,000 in 2013, this did not translate into a significant increase of resources and number of employees. The current budget does not allow SEWRC to build up the stable and high quality staff that is demanded to carry out its legal tasks. The fact that SEWRC's Chairpersons changed four times in the course of 2013, raises concerns about the independence, professional stability and continuity of the management of the Regulator. The selection of the Chairperson of SEWRC should take place in a more transparent manner based on transparently defined professional criteria and respecting general principles of conflict of interest.

Unbundling

In February 2014, the public provider NEK completed the last phase of its split from the Electricity System Operator (ESO). ESO is now able to start the process of its certification as an independent transmission operator, although no draft certification decision was submitted to the European Commission until September 2014.[45] In April 2013, the gas TSO Bulgartransgaz EAD submitted an application to SEWRC for certification as an independent gas transmission operator[46]. SEWRC's initial draft decision was withdrawn and is to be resubmitted in the autumn of 2014[47].

The electricity distribution network is privatized and owned by CEZ, EVN and Energo-Pro. The distribution and supply companies are legally unbundled. None of the 30 gas distribution companies are legally unbundled since they have less than 100,000 customers.[48]

Wholesale Markets

Electricity

The state owned Bulgarian Energy Holding EAD (BEH) and its subsidiary NEK, hold generation assets representing 45% of the installed capacity. NEK acts as a single buyer from the power generators on the high voltage grid and remains the sole electricity supplier at regulated prices for end suppliers. Moreover, NEK has the legal obligation to purchase electricity produced by CHP plants, renewables and industrial producers at regulated prices.

Dispatching of power plants takes place based on regulated quota and priority rules. As a result, NEK purchases electricity at a wide range of prices, from EUR 21/MWh up to more than EUR 350/MWh. Overall, the Bulgarian electricity market operates mainly at regulated prices, covering roughly half of the electricity transactions. The Rules on Electricity Trade were amended in May 2014[49]; a company within the BEH group, Independent Bulgarian Energy Exchange (IBEX), has been licensed for operating an organized power exchange and day-ahead market in electricity[50].

About a third of the electricity market was first opened in 2012, including consumers using their right to choose a supplier and commercial exports. The open electricity market in 2012 included mainly consumers connected to high voltage network and some medium voltage consumers.

Traditionally Bulgaria is a net electricity exporter. In 2012, the share of net country exports was 20.4% of the net electricity country output. [51] This was lower than 2011 because of decreasing demand from the Greek market and other neighbouring markets having sufficient hydro resources. In January and February 2012, the export of domestically produced electricity was curtailed twice from Bulgaria to the neighbouring markets. Following the removal of surcharges imposed on power generators electricity exports increased in 2014 compared to previous years.

Gas

Bulgaria largely depends on gas imports from Gazprom. Bulgargaz EAD, which is part of BEH, is the largest natural gas importer. In 2013, a second trader, affiliated with Gazprom, entered the gas market, which imported gas from Russia and sold gas to its distribution companies as well as end users.

The tariff model for transmission is “postage stamp” (flat fee). At present, transit flows through Bulgaria to inter alia Turkey and Greece are excluded from the regulatory oversight by SEWRC and based on historic long term transport contracts with preferential access to cross-border capacities. Bulgartransgaz EAD is expected to implement an entry-exit model, to meet the requirements of the Third Energy Package, however this system is not envisaged to include the transit.[52]

Retail Markets

Electricity

The retail electricity market remained highly concentrated. In 2012, 8 out of total 24 power retailers took 92% of the market.

Figure 3: Electricity price change by component 2008 – 2013 (source: Eurostat, energy statistics)

From the beginning of 2013, the market was only regulated at the low voltage level. The renewables charge makes up for 15% of the total electricity price for household consumers in Bulgaria.

Although electricity consumers are allowed to switch, no actual switching is observed. Due to the regulated prices for household consumers, there is no benefit in switching and there is no incentive for traders to enter this segment.[53]

Gas

Overall gas demand in Bulgaria increased in 2013 by 7% compared to 2012[54]. The traded volumes were 2854.8 mcm for non-households and 70.2 mcm for households.

Figure 4: Natural gas price change by component 2008 – 2012 (source: EC, EPCR metadata)

In 2012, Bulgaria registered an annual price decrease for natural gas close to 4%, for both household and industrial customers. Taking purchasing power into account, retail gas prices for the average consumer in Bulgaria are the highest in Europe. Natural gas prices (including taxes and levies) increased by 42.2% for residential consumers and by 49.2% for industrial users from 2008 to 2012. The main drivers behind these price rises were energy and supply costs, although VAT rises and higher distribution costs (for industrial users) were also significant factors[55].

Although consumers have the right to select their natural gas supplier, no actual switching is observed as DSOs operate exclusively in their licensed areas of operation.

Consumers

The retail electricity market in Bulgaria is by far the lowest scoring in the EU (48.9 points compared to 72.0) and has seen a highest decrease in score (6.9 points) since 2012. The market is also at the very bottom of the domestic ranking of 31 services markets. In fact, it has the lowest score of all surveyed services markets in the 28 EU Member States. The market scores the lowest or second lowest on all components surveyed (comparability, trust in providers, overall consumer satisfaction, choice of providers, problems, switching and ease of switching), except for the proportion of complaints (which are just below the EU average). The gas market in Bulgaria is scoring better, although also below the EU average (72.0 points vs. 74.1[56], corresponding to 18th position in the EU and has seen an increase of 2.1[57] points since 2012. This market scores particularly low on trust (lowest place among the EU countries). [58]

In July 2013, SEWRC concluded that the implementation of smart metering was not economically viable. The powers of the SEWRC include the review of complaints of consumers against licensees. In 2013, 2,332 complaints against electricity licensees were filed at SEWRC, and 45 complaints against gas licensees. The majority of the gas related complaints were concerned with delays in getting connected to the gas transmission network and gas disruptions.[59] From July 2012, vulnerable customers are defined in the Energy Act.

Infrastructure

The Bulgarian authorities should ensure a proper and timely adoption of the measures stemming from the TEN-E Regulation, including the establishment of the one-stop-shop for Projects of Common Interest (PCIs) (due by 16 November 2013), and other measures foreseen for 2014 and 2015, including the publication of the manual on the permit granting process for project promoters, and the adoption of legislative and non-legislative measures streamlining the environmental assessment procedures.

Electricity

Total installed capacity in 2012 was 13.8 MW, with the peak load of 7.8 MW observed in February 2012.[60] There are several PCIs under the guidelines for trans-European energy infrastructure to be developed within the interconnecting lines with Greece and Romania that increase the cross-border capacity and open North-South priority corridor. Another important PCI is hydro-pumped storage in Yadenitsa.

Technical measures and rehabilitation of the electricity transmission system were approved by the Regulator in 2012. A number of reconstructions and an enlargement of the transmission network was realised and new substations and lines were constructed to satisfy the requirements from new renewable capacities in certain regions of the country.[61]

Gas

In 2013, approximately EUR 15.7 million has been invested in the improvement of the gas distribution infrastructure, through the construction of 194 km of pipelines[62]. Currently there is no physical congestion in the system, either national or cross-border. However, cross-border connection points suffer from heavy contractual congestion and there is minor entry capacity from neighbouring Member States into Bulgaria. Annual gas consumption is below half of the projected transmission capacity.

Progress on the interconnections, PCIs, with Romania, Serbia, Greece, and Turkey is ongoing. The interconnection with Romania – originally expected to be commissioned in June 2014 – is facing delays. Firm reverse flow capacity from Greece has been installed at the level of 1 mcm/d. However, the interconnection between Bulgaria and Turkey is delayed. The reverse flow project with Romania, entailing the connection of the domestic Romanian system to the trunk line, has been suspended.

Security of supply

Electricity

Bulgaria is one of the largest electricity exporters in South Eastern Europe, and thus faces no particular security of supply issues. The electricity transmission network of the country has not faced any significant problems related to security of supply and congestions in the electricity system, including the cross-border capacities. Short-term congestions were rare in the interconnectors with neighbouring countries. Scheduled and non-scheduled interruptions were lower than forecasted.[63] To increase the security of supply in the Burgas region, the construction of two new 400kV substations and three 400kV lines in the North-Eastern part of Bulgaria is envisaged, accommodating the high penetration of renewables in the region and allowing the North-South connection[64].

Gas

In 2014 Bulgaria remains fully dependent on a single source of gas on a single route by a single supplier. It has only limited domestic underground storage capacities that could help in balancing disruptions in high demand periods. Interconnections with the neighbouring countries are very poor and still under development. To ensure security of supply, there are possibilities for reverse physical flow of natural gas from Greece and, after eventually reaching an agreement, from Turkey. The Kula-Sidirokastro interconnector exhibits an existing capacity of 4.3 bcm annually, with the planned reverse flow capacity of 0.36 bcm[65]. There is an underground gas storage facility, Chiren, with a capacity of 550 mcm, of which 250 mcm is reserved for emergency situations. Expansion of the Chiren capacity is envisaged[66].

Key Indicators

Electricity || || Gas ||

Number of companies representing at least 95% of net power generation || 20 || Number of entities bringing natural gas into country || 2

Number of main power-generation companies || 5 || Number of main gas entities || 3

Market share of the largest power-generation company || N/A || Market share of the largest entity bringing natural gas || N/A for 2012, 99.8 for 2011

Number of electricity retailers || 24 || Number of retailers selling natural gas to final customers || 30

Number of main electricity retailers || 8 || Number of main natural gas retailers || 3

Switching rates (entire electricity retail market) || 0% || Switching rates for gas (entire retail market) || 0%

Regulated prices for households – electricity || Yes[67] || Regulated prices for households – gas || Yes

Regulated prices for non-households – electricity || Yes[68] || Regulated prices for non-households – gas || Yes

HHI in power-generation market || N/A || HHI in gas supply market || 7,753

HHI in electricity retail market || N/A || HHI in gas retail market || Approx. 1,000

Electricity market value[69] (bn€) || 1.706 || Gas market value34 (bn€) || 0.434

Installed generation capacity (MW) || 10,236 || ||

Peak load (MW) || 7967 || ||

Number of smart meters installed || N/A || ||

Croatia

Key Issues

Competition in Croatia’s energy market is still very limited. Market opening is needed to improve the investment climate and create incentives for new entrants.

Croatia should step up its efforts to deregulate wholesale prices and prices for end-users and complete the unbundling process. Market liberalization depends on the effective enforcement of EU law including competition and State aid rules and the removal of barriers to the export and import of gas.

Investment in LNG terminal on the Croatian island of KrK is of strategic importance to regional energy security.

1. General Overview

Croatian national gross energy consumption in 2012 amounted to 8.12 Mtoe[70]. Crude oil, petroleum products and natural gas contributed the largest shares to the energy mix.

Figure 1: Gross inland consumption mix 2008 – 2012 (source: Eurostat)

In 2012, total power generation reached 10.5 TWh (a significant decrease compared to 2010, when it was 14.1 TWh). Almost half of power generation mix comes from hydro.

Figure 2: Gross electricity generation mix 2008 – 2012 (source: Eurostat)

Croatia has a long tradition of gas production by which it covers over 70% of its annual domestic demand. In 2012, the domestic production of natural gas decreased. Imports increased significantly and a large amount of imported gas has been stored in underground facilities[71]. The share of renewable energy sources in gross final energy consumption in 2012 amounted to 16.8%[72], above Croatia's 2011/2012 interim trajectory, and is showing good progress towards its national target of 20% by 2020.

2. Regulatory framework

General

The Energy Law adopted in 2012 aims at incorporating the Third Energy Package into Croatian national legislation[73]. Implementation has not yet taken place. In 2013, the Croatian Parliament enacted the Strategic Investments Act[74]. It gives preferential treatment to energy projects of national interest, regardless if they are private or public.

National Energy Regulator

The Croatian Energy Regulatory Agency (HERA) was established in 2004. HERA’s annual budget of 4.5m EUR is not part of the government budget. Funds for financing the work of HERA are secured from income from its own activities (collection of one-off fees and compensations).

Unbundling

The unbundling process in Croatia is not yet completed. The HEP Group (Hrvatska Elektroprivreda) is a state owned electricity company, engaged in electricity production, transmission and distribution, supply and trade, as well as in many other supporting activities including other energy sectors such as heat and natural gas.

In mid-2013 the Croatian TSO, HEP-OPS changed its name to Croatian Transmission System Operator (HOPS). The equity capital of HOPS was increased and founding acts amended to ensure functional unbundling from the rest of HEP Group, including a different visual identity. However, unbundling certification by HERA has not been yet notified to the Commission. The HEP Group has a monopoly on the energy market but the TSO and DSOs have independent accounting, legal and management systems.

The gas grid operator Plinacro has been separated from the company INA for more than a decade, but its certification is still pending. Gas is distributed by 36 companies which operate at a local level, of which 13 have unbundled their supply and distribution operations[75]. The remaining DSOs serve less than 100,000 customers and are exempted from the unbundling rules.

3. Wholesale markets

Electricity

The power generation sector is also dominated by HEP. It was the largest electricity generator, covering 82% of the market in 2012. It owns a 50% stake in the Krsko nuclear power plant in Slovenia, near the Croatian border. HERA has so far issued 24 licenses for electricity generation, the most significant two being HEP and the independent producer TE Plomin d.o.o., co-owned by HEP and RWE Power[76] (50:50), operating a 210 MW power plant[77]. At the wholesale level, the market is based on bilateral contracts.

The Cross-border transmission and allocation of interconnection capacity is progressing. In 2012, HEP TSO carried out its first multilateral coordinated cross-border transmission capacity auctions with Slovenian and Hungarian operators. HOPS is striving to improve further integration with neighbouring electricity systems, including models for market coupling.

Gas

There is currently no commodity exchange or gas hub. Wholesale gas trading is based on bilateral contracts. The conditions for a de facto opening of the gas market have been met with the construction of the interconnecting gas pipeline between Croatia and Hungary which became operational on 3 August 2011. The Croatian gas market began its transition to an entry/exit model on 1 January 2014. Rather than seeking a new long-term deal (the supply contract with Italy's ENI ended last December), the Croatian oil and gas group INA-Industrija Nafte is focusing on domestic gas resources and spot markets. INA’s plan to purchase all its gas imports on the spot market has sparked interest from Slovenia and Hungary, from which shippers can import. By moving to the new model, traders will be able to book entry and exit capacity separately and shipping gas to Croatia will be easier. However, some provisions in the Gas Market Act represent a serious obstacle to cross border gas flows, by obliging domestic gas producers to offer their gas primarily to suppliers of customers in the territory of Croatia and obliging public service suppliers to primarily purchase gas from domestic producers.

Until 31 March 2014, the company Prirodni Plin (owned by INA) remained the "supplier of suppliers" under the public service obligation of gas procurement at regulated prices. From April 2014 until 2017, this function was transferred to HEP, which purchases the necessary gas from INA also at a regulated price. This marked the beginning of a three year transitional period before complete liberalisation of the market, which contradicts Croatia's commitments under the accession negotiations. During this period households prices will remain regulated.

4. Retail Markets

Electricity

In June 2013, two new power retailers entered the market offering electricity to customers connected to the distribution network. The response of small customers and households at first seemed high, although the actual switching rate is unclear. This development is significant given that the price for household customers remains fully regulated. Recently the competition for customers gained momentum. Operators launched advertising campaigns, promising savings on energy bills of 30%. Though the Croatian regulator issued 15 electrical energy supply licences, the two companies leading the campaign for swapping suppliers are Slovenia’s GEN-I and Germany’s RWE. In practice, supplier switching rules are yet to be developed.

Figure 3: Electricity price change by component 2008 – 2013 (source: Eurostat, energy statistics)

Although below the EU average, Croatia's domestic electricity prices rose by 16.9% between 2008 and 2012. Industrial price rises were lower (4%), in part due to a decrease in the network costs paid by industry. In 2012, energy and supply costs accounted for 60% of domestic prices, while network costs accounted for 40% (share in price without taxes and levies). For industrial consumers, the shares were 58% and 42% respectively. In 2013, the price for industrial customers (without VAT) was EUR 91/MWh. For households, price reached a value of EUR 106/MWh (without VAT and other taxes).

Gas

Between 2008 and 2012, Croatia's gas prices rose by 45% and 94% for domestic and industrial consumers respectively.[78] The growth was due to a VAT increase (25% for both electricity and gas), and a major rise in the natural gas shipping rate. Although permitted, there were almost no switches of supplier in 2012. The steep rise in gas prices has made helping customers a priority for the government. In 2013, industrial consumers paid 12.9 EUR/GJ on average, which is more than industry pays for gas in North West Europe. High prices negatively impact competitiveness of the Croatian economy.

Figure 4: Natural gas price change by component 2008 – 2012 (source: EC, EPCR metadata)

5. Consumers

According to the law, all customers are eligible and free to choose their supplier. Protection of customers is strengthened, particularly in terms of ensuring quality of service and protection of vulnerable customers. HERA is in the process of preparing a rule which should simplify the switching procedure and ensure it takes no more than 3 weeks. It has appointed a council for customer protection, which makes recommendations and opinions to assist the ongoing transformation of the sector.

6. Infrastructure

The Croatian authorities should ensure a proper and timely adoption of the measures stemming from the TEN-E Regulation, including the establishment of the one-stop-shop for Projects of Common Interest (PCIs) (due by 16 November 2013), and other measures foreseen for 2014 and 2015, including the publication of the manual on the permit granting process for project promoters, and the adoption of legislative and non-legislative measures streamlining the environmental assessment procedures.

Electricity

There are several Projects of Common Interest under the guidelines for trans-European energy infrastructure planned in Croatia, including two electricity clusters, a high voltage transmission line between Croatia and Bosnia and Herzegovina and a high voltage transmission line between Croatia, Hungary and Slovenia. Considerable investment is expected. An 800 million EUR investment in a 500 MW coal-fired power plant Plomin, is underway. The government is trying to find investors that would enable the delivery of a 500 MW gas plant in Osijek, which would help reduce imports of electricity, especially from Serbia. Investment scenarios are optimistic.

Gas

The gas pipeline Donji-Miholjac – Dravaszerdahely between Croatia and Hungary has created conditions for gas market opening. This is the second supply route for imported natural gas with an annual pipeline capacity of 6.5 bcm. The cross-border interconnector in Rogatec between Croatia and Slovenia is the supply route for Russian gas. Plinacro has finalised the implementation of its previous Network Development Plan by putting into operation the transmission pipeline Benkovac-Split[79].

The LNG terminal on Krk, on the list of PCIs, would open a cross European North-South corridor. To deliver the project, the government should encourage investors but for the time being contradictory signals are being conveyed. In January 2013, Gazprom and Plinarco adopted an action plan to implement the South Stream project in Croatia by 2016. A strategically important PCI (a least costly N‐1 solution for Croatia) is the Ionian-Adriatic Pipeline to Albania which creates a new energy corridor for the region.

7. Security of Supply

Electricity

The Croatian power system is one of the smallest in Europe. It has 4 GW of installed generation capacity and 15.000 MVA[80] of gross installed interconnection capacity. Due to its geographical position and location of generating plants, electricity is transported for most of the year from the south to the north and vice versa, and from the north towards the east[81]. Croatian security of power supply is strengthened by interconnecting infrastructure with the systems of neighboring countries[82].

Gas

Croatian Regulation on Security of Natural Gas Supply is not fully aligned with EU Regulation 994/2010. The Preventive Action and Emergency Plan have not yet been adopted; there is no bi‐directional flow obligation; no obligation to perform the Risk Assessment and no official obligation for a N‐1 rule application. Croatia is strategically located in terms of regional security of gas supply. A recent survey revealed the existence of promising deposits of gas and oil in the central and southern Adriatic. Delivery of a PCI in LNG terminal in Krk is quickest way to improve the whole region’s natural gas supply security.

8. Key Indicators

Electricity || Gas

Number of companies representing at least 95% of net power generation || 2 || Number of entities bringing natural gas into country || 5

Number of main power-generation companies || 2 || Number of main gas entities || 2

Market share of the largest power-generation company || 82% || Market share of the largest entity bringing natural gas || 60.8%

Total Number of electricity retailers || 9 || Number of retailers selling natural gas to final customers || 36

Number of main electricity retailers || 2 || Number of main natural gas retailers || 3

Switching rates (entire electricity retail market) || N/A || Switching rates for gas (entire retail market) || N/A

Regulated prices for households – electricity || Yes || Regulated prices for households – gas || Yes

Regulated prices for non-households – electricity || Yes || Regulated prices for non-households – gas || Yes

HHI in power-generation market || 7,738 || HHI in gas supply market || 4,833

HHI in electricity retail market || 4,516 || HHI in gas retail market || 1,588

Electricity market value[83] (bn€) || 1.197 || Gas market value13 (bn€) || 0.505

Installed generation capacity (MW) || 4,000 || ||

Peak demand (MW) || 3,193 || ||

Number of smart meters installed || N/A || ||

Cyprus

Key issues

The full liberalisation of the electricity market was formally achieved on 1st January 2014, but it is not yet implemented in practice, as EAC, a semi-public body, is currently the sole supplier. Consequently, there is no scope yet for consumer switching.

Liberalisation should be planned in detail, taking into account the EU targets for renewables, energy efficiency and GHG emissions. There is a need to create an investment-friendly framework in order to attract alternative suppliers and ensure a smooth transition for consumers.

Renewable energy could play a vital role in security of supply and should be promoted.

General overview

The gross inland energy consumption in 2012 was 2.51 Mtoe, a drop of 6.3% from 2011. The energy mix pattern continues to be dominated by oil and petroleum products, which represent 94.9% of the gross energy consumption in 2012. The contribution of renewable energy to the gross inland energy consumption has steadily increased over recent years and the renewables share has reached 6.8%[84] in 2012. Cyprus remained above its 2011/2012 interim trajectory and is on track to reach its national 2020 RES target of 16% by 2020[85].

Figure 1: Gross inland energy consumption mix 2008-2012 (source: Eurostat)

The gross electricity generation in 2012 was 4.72 TWh, a drop of 4.3% compared to 2011. Electricity in Cyprus is generated mainly by crude oil and petroleum products. Only 3.6% of electricity is generated by renewables, despite Cyprus' remarkable potential in solar and wind. However, renewables are increasing their contribution in electricity generation. In 2012, electricity generation from renewables more than tripled compared to 2010 levels, mainly due to the increase of wind power generation. The National Renewable Energy Action Plan projected that by 2018 the electricity generation capacity from renewable energy sources would reach 400 MW. In 2012, the installed renewables have reached 172 MW. The gross electricity generation is presented graphically the period 2008-2011[86].

Figure 2: Gross electricity generation mix 2008 – 2011 (source: EU Energy in Figures – Pocketbook 2012 and 2013)

Regulatory framework

General

An important regulatory development for 2012 was the implementing legislation of the Third Energy Package, which came into force in late 2012[87].

National Energy Regulator

The Cyprus Energy Regulatory Authority (CERA) was established in 2003. The objective of CERA is to regulate and monitor the Electricity and Natural Gas Markets. CERA employs 11 people. Further recruitment has been postponed as a result of government decisions for the wider public sector; CERA's lack of resources is a source of concern. The revenue of CERA for the year 2012 was EUR 1.96 million, an increase of approximately 14% from 2011. CERA closed the year with a net surplus of EUR 0.97 million[88].

Unbundling

The incumbent Electricity Authority of Cyprus (EAC) owns both the transmission and the distribution system. The TSO is legally but not functionally unbundled from EAC, since all its staff is seconded from EAC. The obligation of ownership unbundling of the TSO does not apply, since Cyprus has obtained a derogation from Article 9 of the 2009/72/EC Directive. The DSO is responsible for managing, operating and developing the network, safeguarding access to the distribution network and equal treatment for all users. EAC has unbundled the accounts of the DSO.

Wholesale Markets

Electricity

Whilst full liberalisation of the market was legally achieved on 1st January 2014 when a derogation granted under the Second Energy Package pursuant to its status of small isolated system expired, Cyprus is not integrated and not interconnected with any neighbouring power systems. No wholesale market is currently operating in Cyprus; in the Memorandum of Understanding with the “Troika” (the European Commission, the International Monetary Fund and the European Central Bank) Cyprus engaged to develop open and competitive energy markets.

The installed generating capacity in 2012 was 1,546 MW, out of which 1,374 MW was thermal power stations and 172 MW was renewable capacity mainly from wind parks. The installed capacity of cogeneration of heat and power was 9.4 MW in 2012[89].

Based on the supply interruption data for 2012 the overall minutes lost per voltage level per year are estimated at 41 minutes for H/V, 157 minutes for M/V and 8 minutes for L/V. This represents an increase over the years for which data was available[90].

Gas

Currently, natural gas is not supplied to Cyprus. However in December 2011, significant gas resources were discovered within the Eastern Mediterranean Sea. The Cypriot authorities have established two National Hydrocarbons Companies whose respective tasks and functions are currently being defined: in principle EYK (formerly KRETYK) should be in charge of upstream and export issues, while DEFA should focus on the development of domestic market. Both have the legal form of private companies 100% owned by the State. In addition, an interim solution was planned for the supply of the electricity generation sector with natural gas until the indigenous natural gas reserves are made available. On 27 September 2012, DEFA and EAC issued an invitation for the Expression of Interest for the supply of natural gas to Cyprus. Seventeen applications were submitted, but none was accepted. A second invitation was issued in January 2014 with a deadline of 24 March 2014[91], subsequently extended to 14 April 2014.

Retail Markets

Domestic consumers became legally eligible to switch suppliers on 1st January 2014. However, EAC is still the sole electricity supplier in Cyprus and thus switching procedures do not exist. Electricity prices are well above the EU average. The network component in households represented 15% of the total bill, while in industry it represented 11% of the end price[92].

Figure 3: Electricity price change by component 2010 – 2013 (source: Eurostat, energy statistics)

Electricity demand in 2012 decreased by 4.6% compared to 2011, which was the largest drop amongst all EU Member States[93].

According to EU law, Member States are obliged to ensure the deployment of smart metering systems, which may be subject to a cost-benefit analysis, on 80% of electricity customer premises by 2020 where positively assessed. To prepare for this medium-term goal, the EAC is implementing a pilot project of 3,000 smart meters[94] [95].

Consumers

The retail electricity market in Cyprus is performing just below the EU average (70.7 points compared to 72.0[96]) and ranks 18th EU-wide. The proportion of consumers encountering problems in this market is the lowest in the EU. (The questions on switching, ease of switching and choice have not been asked given that the market is a monopoly).[97]

The consumer protection measures, including those set out in Annex I of the directives 2009/72/EC and 2009/73/EC, are effective and enforced through the Laws N.211(I)/2012 and N.219(I)/2013 on Regulating the Electricity and Gas Markets, respectively. As stated earlier, from 1st January 2014 the electricity market is technically fully liberalised, but there is still only one supplier, and no scope for switching. Energy poverty, vulnerable consumers' categories and measures to protect them were defined in a Ministerial Decree, which includes measures such as reduced prices on electricity tariffs and financial incentives for participating in a Plan for setting up a Photovoltaic system at their house, with a capacity of up to 3kW with the net-metering method. In 2012, 3% of all household consumers were defined as consumers with special needs.

Infrastructure

In accordance with the requirement in the TEN-E Regulation, Cyprus authorities have established a one stop shop for the permitting of Projects of Common Interest (PCIs).

Prior to the discovery of gas resources in the EEZ of Cyprus, the construction of an LNG regasification terminal and pipelines to the three power stations in Vasilikos, Moni and Dhekelia were planned by the Cypriot Authorities. The construction of the pipelines is supported under the European Energy Program for Recovery (EEPR) and entitled to a EUR 10 million grant.

With the recent discoveries, infrastructures are also planned for the export of gas. Pipeline and LNG projects are currently being assessed and should allow for gas export by the end of the decade. These infrastructures have been identified as PCIs under the Regulation on the Guidelines for the Trans-European Energy Network.

A future interconnection project called “Euroasia Interconnector” is in the feasibility phase. The project will have a capacity of 2,000 MW and interconnect the Cypriot, Israeli and the Greek transmission networks.

In total four projects involving Cyprus have been identified as PCIs in accordance with the guidelines for Trans-European energy infrastructure.

Security of supply

The consequences of the energy crisis after the explosion which damaged the Vassilikos Power Station in July 2011, ended earlier than originally estimated. This was due to both the adequacy and the swift repair achieved in restoring Vassilikos Power Station and to a reduction in demand. Although the installed capacity of thermal power stations in 2012 was 1,374 MW (a decrease of 13.6% compared to 2011[98]), including 286.6 MW of temporary generating units, the maximum generation demand was 997 MW, achieving a reserve of 38%, which was the largest reserve recorded since 2004[99] [100]. All existing fossil fuel generators run on heavy fuel oil or diesel oil, and some can be converted to run on natural gas.

Key indicators

Electricity || || Gas ||

Number of companies representing at least 95% of net power generation || 1 || Number of entities bringing natural gas into country || N/A

Number of main power-generation companies || 1 || Number of main gas entities || N/A

Market share of the largest power-generation company || 100% || Market share of the largest entity bringing natural gas || N/A

Number of electricity retailers || 1 || Number of retailers selling natural gas to final customers || N/A

Number of main electricity retailers || 1 || Number of main natural gas retailers || N/A

Switching rates (entire electricity retail market) || N/A || Switching rates for gas (entire retail market) || N/A

Regulated prices for households – electricity || Yes || Regulated prices for households – gas || N/A

Regulated prices for non-households – electricity || Yes || Regulated prices for non-households – gas || N/A

HHI in power-generation market || 10000 || HHI in gas supply market || N/A

HHI in electricity retail market || 10000 || HHI in gas retail market || N/A

Electricity market value[101] (bn€) || 1.2 || Gas market value18 (bn€) || N/A

Installed generation capacity (MW) || 1,742 || ||

Peak load (MW) || 997 || ||

Number of smart meters installed || N/A || ||

Czech Republic

Key issues

Coupling of the day-ahead markets between the Czech Republic, Slovakia and Hungary improved price stability in the region. Market coupling with the rest of European regions remains a priority.

Further investment in cross-border interconnectors will increase market competition and energy security. Unscheduled power flows from Germany remain a big concern for the Czech Republic as they risk the safe operation of its transmission networks.

The Czech Republic should reinforce its power distribution and transmission network in order to integrate power generating facilities, including dispersed renewables.

The major concerns regarding security of supply relate to depleting lignite reserves, an ageing electricity infrastructure (including the generation portfolio) and high networks costs, which influence the electricity prices for end-users.

1. General Overview

Energy consumption in 2012 (42.78 Mtoe) was based largely on fossil fuels, notably coal (with a share of 40% in the energy consumption mix). The renewable energy share is increasing and has reached 11,2%[102] in 2012, mainly due to solar and hydro contributions (8%[103]). The Czech Republic was above its 2011/2012 interim trajectory and is on track to achieve its national 2020 RES target of 13% by 2020. The power generation mix in 2011 (87.5 TWh) was dominated by solid fuels. Cogeneration[104] provided for 12.8% of the total electricity generation in 2011, falling slightly comparing to 2010.

Figure 1: Gross inland consumption 2008 – 2012 (source: Eurostat)

Figure 2: Gross electricity generation 2008 – 2011 (source: EU Energy in Figures – Pocketbook 2012 and 2013)

Regulatory framework

General

The Czech Republic has introduced amendments to their incentive scheme for renewables[105] and the support for all new installations except small hydro ceased at the end of 2013. This has slowed down the development of the sector which had increased rapidly in the previous period.

National Energy Regulator

The Energy Regulatory Office ("Energetický regulační úřad", ERO) is responsible for energy regulation in the Czech Republic. In 2012/13, ERO employed 178 staff. The 2012 budget of EUR 8 million doubled compared to 2011[106], due to the amendment to the Energy Act which markedly reinforced the ERO’s powers, in particular those of supervision, oversight penalisation and remedial measures in cases of violations of legal regulations and in the enforcement of sanctions.

Unbundling

In 2012, ERO certified the ownership unbundling of the electricity TSO, ČEPS. In the gas sector, at the beginning of 2013 ERO issued a certification decision concerning NET4GAS, which opted for the status of Independent Operator (ITO). Gas distribution companies are legally unbundled from the TSO, gas trading companies and gas storage operators.

Wholesale markets

Electricity

The concentration of wholesale power generation remains very high. ČEZ is the dominant electricity generator with a market share close to 80%[107].

In the Czech Republic, electricity is traded at Prague-based Power Exchange Central Europe (PXE), and in spot markets (day-ahead and intraday) organised by OTE, a.s. (a joint stock company established in 2001 which acts as the Czech electricity and gas market operator). In 2012, a total of 112 TWh was traded under bilateral contracts registered in the OTE system with an additional 11 TWh traded in the organised spot markets. A total of 19,8 TWh was traded at the PXE in future energy exchange products (a market volume of EUR 944 million).

The market coupling of the Czech, Slovak and Hungarian day-ahead markets started in September 2012 and has been successful so far. The price convergence between the countries reached 76% [108] after the launch of the market coupling. Cross-border capacity allocation for power transmission for German, Polish and Austrian borders takes place through Central Allocation Office, GmbH. Capacity allocation with Slovakia is based on long-term nominations. The average Czech day ahead wholesale price in 2012 was approximately EUR 43 /MWh for base load power (a decrease compared to 2011).

Gas

In 2012, 25 entities imported gas into the Czech Republic. The largest entities importing gas were RWE Transgas, WINGAS GmbH & Co. KG, and VNG Energie. The volume of natural gas imports reached 6.9 Mtoe[109] in 2012. It was bought mostly from Russia and Norway under long-term contracts, but also at European energy exchanges, or from domestic resellers. The average price for gas imported from Russia was EUR 37.4/MWh in the third quarter of 2012[110].

Trading activity on the Czech virtual trading point increased significantly in 2012 and reached 107 TWh in bilateral contracts (compared to 0,258 TWh in 2011). The increase was due to new brokering activities of three companies: 42 Financial Services (42FS), Tradition Financial Services (TFS) and ICAP.[111] In 2012, a bi-directional transmission between the Czech virtual trading point and Slovakia was enabled.

Retail markets

Electricity

Market concentration remains very high, but the dominant position of three main power suppliers, ČEZ, E.ON and PRE is gradually decreasing. The three companies covered close to 70% of the market in 2012 down from 85% in 2011.[112]

Czech power prices are fully liberalized. The supplier switching ratio in 2012 was relatively high (7.96%[113]).

Between 2008 and 2012, power prices decreased for industrial consumers and increased for household consumers[114].

Figure 3: Electricity price change by component 2008 – 2013 (source: Eurostat, energy statistics)

The network component of electric energy prices for households has increased since 2010 (figure 3). The levies related to the share of renewables in electricity consumption grew from less than 2% of the total energy bill for households in 2009 to more than 9% in 2012.

Gas

Competition in the retail supply market is increasing. In 2012, there were 59 active gas suppliers in the retail market, 10 more than in 2011[115]. Nevertheless concentration remains high. ERO reports that the retail market may saturate if the number of traders continues to grow[116]. In 2012, gas was distributed by six regional companies.

Figure 4: Natural gas price change by component 2008 – 2012 (source: EC, EPCR metadata)

Gas prices are generally determined by long-term contracts but a growing number of suppliers offer prices reflecting spot market prices. Gas prices for industrial consumers decreased between 2008 and 2012 as network and tax related components of natural gas prices for industry decreased (figure 4). In the first part of 2013, gas prices for household consumers reached EUR 0.064/kWh. In the same period, gas prices for industrial consumers reached EUR 0.034 EUR/kWh.[117]

In the gas sector, switching rates have remained stable in the past few years, at around 12% for both the whole retail market and households[118].

Smart meters

The outcome of the cost benefit analysis of smart meter deployment, undertaken by the Czech government, was negative. Consequently, a formal decision was made not to proceed with the roll-out of smart metering in both the electricity and gas sectors[119]. In 2014 the European Commission formally requested the Czech Republic to ensure that final energy consumers are provided with individual meters[120].

Consumers

Retail gas market is assessed below the EU average (72.0 points compared to 74.1[121]) and ranks 19th EU-wide. The market is also assessed below the average of 31 domestic services markets (24th position). In particular, trust in providers is 4th lowest in the EU. However, switching rates are the second highest in the EU while the ease of switching receives the fourth highest score. Overall, this market has remained stable compared to 2012. Consumer assessment of the electricity retail market is above the EU average (72.9 points compared to 72.0[122]), corresponding to 15th place. It increased by 3 points between 2012 and 2013, in particular with regard to overall consumer satisfaction, choice of providers, actual switching and ease of switching. The two last components have the 5th highest score in the EU. [123]

Czech consumers no longer only switch from vertically integrated incumbents to new suppliers, but also between suppliers to obtain the lowest price. The total number of switches in the electricity sector was 472,000 in 2012 (from that 382,000 households) and in the gas sector it was 348,000 (from that 316,000 households).

Consumers can access a tool providing information on electricity suppliers on ERO’s website[124]. Consumers may address their complaints, questions, and suggestions to the Consumer Protection Unit operating with ERO. The most frequent subject of complaints concern unfair commercial practises, switching and billing. Czech law does not define a “vulnerable customer”[125]. The amendment of the Energy Act is currently under preparation and non-economic support should be foreseen in it.

Infrastructure

The Czech authorities should ensure a proper and timely adoption of the measures stemming from the TEN-E Regulation, including the establishment of the one-stop-shop for Projects of Common Interest (PCIs) (due by 16 November 2013), and other measures foreseen for 2014 and 2015, including the publication of the manual on the permit granting process for project promoters, and the adoption of legislative and non-legislative measures streamlining the environmental assessment procedures.

Electricity

The increasing share of renewables in the energy mix of the Czech Republic and other countries in the region, as well as the foreseen increasing demand (up of about 200 MW per year depending on scenarios), call for an ambitious investment in the Czech energy infrastructure.

Several Projects of Common Interest (five in total) being developed in the Czech Republic aim to increase capacity at the country’s North-Western and Southern borders. Pending investments also include the upgrade of the transmission network to connect the new and modernised power plants. Improvement of distribution infrastructure is needed to enable the expansion of dispersed renewables. There is an on-going replacement and expansion project for the 400 kV grid. It is planned to be completed by 2030, but investment is slow and lead times are long.

Gas

In 2012, the GAZELLE gas pipeline was completed to connect to the OPAL and MEGAL gas pipelines that expand to the transmission system supplying Germany and France. Also, in 2012, the interconnector between the Czech and Polish gas transmission systems (the STORK project) was completed (partly financed with funds from the European Energy Programme for Recovery). The Czech-Polish interconnector plays an important role in the integration and liberalisation of the gas market in the region. Following the implementation of reverse flow projects (also co-financed by the EEPR), security of supply has substantially improved in the Czech Republic and Slovakia. A second pipeline between the Czech Republic and Poland is already planned to start operation end 2018, with two other projects with Austria planned to come online after 2020 (all these three are PCIs under the guidelines for Trans-European energy networks)[126].

Security of Supply

Electricity

The Czech Republic's degree of electricity dependence is one of the lowest in the EU (25.2 % in 2012)[127]. The generation mix is well diversified as the national strategy does not allow any single source of energy to provide for more than 65% of the total. Abundant domestic coal resources are gradually declining. They can be exploited until 2050. The country is a net electricity exporter. Major concerns relate to the depleting lignite reserves, ageing electricity infrastructure and high networks costs which influence the electricity prices for end-users.

The Czech Republic is interconnected with the Austrian, German, Polish and Slovak markets. The relatively high interconnection rate is generally positive for Czech security of supply, but has a downside. The Czech network suffers from unscheduled flows of power originating in Germany (loop flows).

Gas

Almost all gas consumed in the Czech Republic is imported from Russia (90%) and Norway (9%)[128]. Security of supply is relatively robust and has benefited from the new interconnectors and reverse flow capabilities on existing pipelines being put in place. The contractual gas prices are mostly linked to oil products and hard coal. This maintains stable prices, but carries financial penalties in case of early termination. In this regard, an important precedent was set in October 2012 when RWE’s Czech subsidiary succeeded in its dispute with Gazprom over gas contracts. The court ruled for the first time that a company did not have to pay fines under a "take-or-pay" clause[129].

Key indicators

Electricity || || Gas ||

Number of companies representing at least 95% of net power generation || 73 || Number of entities bringing natural gas into country || 25

Number of main power-generation companies || 1 || Number of main gas entities || 1

Market share of the largest power-generation company || 78% || Market share of the largest entity bringing natural gas || 82.3%

Number of electricity retailers || 360 || Number of retailers selling natural gas to final customers || 59

Number of main electricity retailers || 3 || Number of main natural gas retailers || 11

Switching rates || 7.96[130] || Switching rates for gas (entire retail market) || 12.03

Regulated prices for households – electricity || No || Regulated prices for households – gas || No

Regulated prices for non-households – electricity || No || Regulated prices for non-households – gas || No

HHI in power-generation market || N/A || HHI in gas supply market (domestic) || 3,358

HHI in electricity retail market (domestic) || N/A || HHI in gas retail market (domestic) || 1,632

Electricity market value[131] (bn€) || 5.001 || Gas market value30 (bn€) || 2.505

Installed generation capacity (MW) || 20,520 || ||

Peak demand (2012, MW) || 11,324 || ||

Number of smart meters installed || 50,000 || ||

Denmark

Key Issues

The energy mix will change significantly due to ambitious policy targets for renewable energy (wind power set to account for up to 50% of electricity generation by 2020). To address this interconnection capacities with neighbouring countries are being developed to maintain a high level of security of supply.

Danish household customers pay one of the highest electricity prices in EU, mainly due to a very high level of energy taxes. Compared to electricity prices for industrial consumers the price for household customers is three times higher. However, the electricity price without taxes for industrial consumers is below the EU-27 average (5% in 2012).

Annual domestic gas production was reduced by approximately 10% in 2012. Denmark now partly relies on imports through Germany to balance its gas supply and demand. Denmark's security of supply is closely linked to that of Sweden due to the fact that the latter is entirely dependent on Denmark.

Regulated end-user prices will be phased out by October 2015 (electricity) and, based on legislation yet to be proposed, by October 2016 (gas). A bill on a supplier centric model for the electricity retail market was adopted in June 2012 and will come into force by October 2015.

General overview

Gross energy consumption has decreased from 20.2 Mtoe (2008) to 18.1 Mtoe (2012). In 2012, Denmark relied on crude oil and petroleum products (39.0%), renewable energy sources (23.3%), natural gas (21.8%) and solid fuels (13.6%)[132].

Figure 1: Gross inland consumption mix 2008 – 2012 (source: Eurostat)

Total gross electricity generation in 2012 dropped to 30.7 TWh[133]. In 2011, renewable energy sources provided the largest share for the first time (40.34%), whereas solid fuels were the second most important source (39.77%). Natural gas had a share of 16.48 % and crude oil of 1.42 %.

Figure 2: Gross electricity generation 2008 – 2011 (source: EU Energy in Figures - Pocketbook 2012 and 2013)

The RES share in gross final energy consumption in Denmark reached 26% in 2012 and is expected to rise to more than 35% by 2020. In spring 2011, the Danish government decided to raise the share of renewable power to 50% by 2020, thus exceeding the European targets. Cogeneration[134] provided between 40.7% and 49.2% of the total energy generation between 2008 and 2011.[135]

Regulatory framework

General

The Third Energy Package was implemented in national law with the adoption of Act no. 466 on 18 May 2011.[136]

National energy regulator

The Danish Energy Regulatory Authority (DERA) was founded in 2000 and employs about 50 employees with a budget of about EUR 5.56 million in 2012. Compared with 2011 this is an increase by more than 10% in staff and budget.[137]

Unbundling

The TSO for both gas and electricity is Energinet.dk. DERA adopted final certification decisions in February 2012 in accordance with the rules of the ownership unbundling model and making use of the provisions related to separation within the state.

Wholesale markets

Electricity

The largest electricity generators in Denmark are Dong Energy and Vattenfall who together account for about 56.7% of the total generation capacities. Denmark is part of the Nord Pool Spot, a joint energy exchange for the Scandinavian countries. More than 70% of the energy generated in the area is traded at Nord Pool Spot.

Denmark is divided into two market areas (Western Denmark DK1 and Eastern Denmark DK2). The energy is either traded day-ahead or intraday. The total volume traded day-ahead was 20.3 TWh in DK1 and 15.3 TWh in DK2 (2012), while the volume traded intraday was 0.2 TWh in DK1 and 0.2 TWh in DK2 (2012)[138]. The average price (arithmetic mean) in 2012 was EUR 36.33/MWh in DK1 and EUR 37.56/MWh in DK2.

The Danish electricity wholesale market is part of the day-ahead market coupling project which began operation in February 2014.

Gas

The annual gas production for 2012 in Denmark was 5.455 mcm, production decreased by about 10% compared with 2011. The gas consumption was at 3.696 mcm while an amount of 2.830 mcm was exported. Only a very small amount was imported from Germany. The three important export countries were Sweden (37.84 %), the Netherlands (35.19 %) and Germany (26.96%).[139]

The Danish wholesale market is mostly based on bilateral trading (OTC trading), but volumes traded at the Danish gas exchange (Gas Point Nordic) have by 2014 reached 25%. It has been possible to trade gas on the gas exchange since 2008. The gas exchange was established in 2007. The average prices were EUR 27.98/MWh in 2013, EUR 25.16/MWh in 2012 and EUR 23.25/MWh in 2011.

Retail markets

Electricity

The electricity market was liberalised in 2003. There are currently 33 active suppliers in the retail market. DERA recognises that the level of competition needs to improve. In 2012, 6.7% of the end consumers switched supplier, which is an increase on 2011 levels (3.18%), but still low. Since 2003, all Danish electricity consumers are free to choose whether to join the regulated market with regulated prices or the liberalised market where prices are not regulated. Consumers above 100,000 kWh, covering about 50% of the retail market (in terms of consumption), are active in the market, whilst at least until the end of 2012, between 90 and 95% of electricity consumers had not exercised their right to change supplier and remained on default contracts with regulated prices. However, for most consumers, the regulated prices will cease by October 2015.

Figure 3: Electricity price change by component 2008 – 2013 (source: Eurostat, energy statistics)

The electricity prices for consumers are frequently updated by DERA and published on www.elspristavlen.dk where both fixed and variable prices are shown. The prices did not rise between the first half of 2012 and the first half of 2013, remaining constant at EUR 0.3/kWh, which is the highest electricity price within the EU and primarily caused by the highest level of taxes and levies including VAT (56.7%).[140]

In 2013, the Danish Energy Agency issued a new regulation securing the full roll-out of smart meters in Denmark by 2020. Large scale replacement of existing meters began in 2010/2011 and currently more than 50% of consumers have smart meters. There are already 1.63 million metering points where a smart meter is installed following a voluntary roll-out led by the distribution system operators (DSOs), and the remaining 1.38 million will be also equipped following a positive cost-benefit analysis.

On 1st October 2015, the electricity retail market will change to a supplier ce