1. Overview

1.1 Introduction

1.1.1 The Romanian electricity sector has been liberalised since 2007. However, in parallel, a large regulated electricity supply market (i.e. the electricity retail market) also continues to exist. Consequently, electricity is supplied under two systems: the regulated market, which covers households and customers, and the competitive market, represented by industrial customers. The distribution and supply sectors have been partly privatised, but the majority of the conventional power generation companies are still governmentcontrolled. Transelectrica SA, the transmission system operator (TSO) and Operatorul Pieței de Energie Electrică şi de Gaze Naturale “OPCOM” SA, the power market operator (OPCOM) are fully state-owned. The renewable generation sector is booming with over 4GW (wind, solar and biomass generating capacity) installed up to July 2014.

1.1.2 In July 2012, the Romanian authorities adopted the new electricity and gas law no 123/2012 (Electricity and Gas Law), in order to meet the EU requirements of the Third Energy Package.

1.1.3 One of the major amendments brought in by the Electricity and Gas Law is the ban of negotiated power purchase agreements (PPAs) outside the electricity trading platform operated by OPCOM. Electricity generators must therefore make offers to sell and trade their entire output on the electricity trading platform operated by OPCOM. The traders and end customers must make their purchase offers on the same platform and PPAs are signed provided that the transparency principle is observed.

1.2 Structure of electricity market

1.2.1 In Romania, the most important electricity generating stations are state-owned. Also, the Romanian state owns the majority of the shares in the TSO. Romania has chosen the Independent System Operator model in respect of the Third Energy Package. Unlike the generation and transmission sectors, the distribution sector has been partially privatised; five of the eight distribution operators are privatised.

1.2.2 The main piece of legislation governing the electricity (and gas) sectors in Romania is the Electricity and Gas Law. There are also technical and commercial regulations applicable for each part of the electricity sector (e.g. transmission, distribution, supply) such as the Technical Code of the Distribution Grids applicable to the distribution sector, the Technical Code of the Transmission Grid for the transmission sector, the Measuring Code, the Commercial Code of the Wholesale Electricity Market which regulates the operation of the electricity market, tariffs calculation methodologies and special regulations with respect to the licences and authorisations and connection to the electricity grid.

1.2.3 The electricity market is divided into two components as follows:   

  1. the retail electricity market where the electricity is sold by producers or electricity traders to end customers (including the regulated sector). The non-regulated segment of the retail market consists of transactions entered into on the electricity trading platforms operated by OPCOM as follows:
    • regulated bilateral contracts market;
    • negotiated bilateral contracts market;
    • double negotiated bilateral contracts market; and
  2. the wholesale electricity market, where the electricity is traded between licenced producers and traders and consisting of the following markets:
    • Day Ahead Market (DAM) operated by OPCOM;
    • Intra-Day Market (IDM) operated by OPCOM, which is not fully operational yet;
    • Balancing Market (BM) operated by the TSO; and
    • Ancillary Services Market (ASM) operated by the TSO.

1.3 Key players

1.3.1 The key players in the Romanian electricity market are the generators, the TSO, OPCOM (which is also the operator of the green certificates market), and eight geographically based distributors.

1.3.2 The electricity generation sector is mainly state owned (i.e. 89% of the national electricity output is generated by state-owned generators). In addition to the state owned generators, OMV PETROM, a former state-owned company, currently controlled by the OMV Group, has commissioned an 860MW combined cycle gas turbine generating station (the Brazi Gas Turbine Generating Station) which is expected to provide up to nine per cent of Romania’s electricity demand.

1.3.3 The TSO is the sole operator of the electricity transmission grid. It is a joint stock company with the majority stake (approx. 59%) owned by the Romanian state through the Ministry of Public Finances. The other stakeholders are Fondul Proprietatea (13.5%) and private entities (approx. 28%).

1.3.4 OPCOM is a joint stock company 100% owned by the TSO. It is responsible for providing an organised, viable and efficient framework for trading on the wholesale electricity market and green certificates market in a transparent and non-discriminatory manner.

1.3.5 Five out of the eight distribution operators are privatised and, since its liberalisation in 2007, the supply market currently has 189 licensed suppliers registered with the National Energy Regulatory Authority (ANRE). The majority of the suppliers are active in both the retail and wholesale electricity markets.

1.4 Current issues and drivers

Romanian conventional generation sector

1.4.1 The Romanian power generation sector is facing major challenges as a significant percentage of its generating stations are already past their useful economic life expectancy. Nearly 3GW of conventional generating stations have been decommissioned in Romania. Further decommissioning is expected in the coming years as many generating stations require major refurbishments and modernisation to meet EU requirements.

EU CO² emission targets

1.4.2 Although there are plans for upgrades, many of the existing coal-fired generating stations are expected to be affected by the costs of CO² emission targets imposed under EU laws. However, coal-fired generating stations will continue to play an important role in the Romanian electricity generation sector given the country’s significant coal reserves.

Renewable energy generation – challenges and perspectives

1.4.3 Romania also has significant wind resources and the wind generation industry has boomed since 2011 with over 2.7GW of capacity installed (as at July 2014). However, the TSO anticipates that in the current circumstances (i.e. the state of the transmission system and reduced electricity consumption) the grid capacity can accommodate up to around 3GW of wind generation.

1.4.4 Solar photovoltaic capacities have also boomed in recent years with over 1.2GW installed up to the middle of 2014. Biomass and biogas growth is more limited with only 101MW installed up to July 2014.

National plans/strategies 

1.4.5 The TSO intends to carry out grid upgrades as per the Power Transmission Grid Perspective Plan for 2014-20231 in order to accommodate the new investments in generation. Significant financing (over RON 4.5b) is needed to sustain the upgrade of the current electricity grid infrastructure.

1.4.6 Since publication of the Energy Strategy for Romania for 2011-20352, the government has been considering and consulting on a new Energy Strategy for 2014-2035. As this is still at the discussion phase, this Guide does not contain any further information on the new Energy Strategy for 2014-2035.

1.4.7 The Energy Strategy for Romania for 2011-2035 is intended to consider the international context, the current situation in the energy sector in Romania, the main objectives and development directions as well as the forecasts for the electricity sector up to 2035 and the measures necessary to fulfil such objectives. The strategy’s main focus points include:   

  • the active involvement of Romania in achieving the regional electricity market in Central and Eastern Europe and South-Eastern Europe in order to integrate the Romanian electricity market in the internal EU electricity market;
  • the connection of OPCOM’s centralised markets with corresponding electricity markets from neighbouring countries;
  • improving the current legal framework as well as the market surveillance mechanisms and decreasing the time necessary to remedy any market operation malfunctions;
  • ensuring the predictability of the regulatory framework and operation of the electricity market in a transparent and non-discriminatory manner.

2. Sector Analysis

2.1 Generation

Structure of generation sector

2.1.1 As a result of the legacy structuring, the Romanian state (through the Ministry of Economy) owns the majority of the conventional generating stations via controlling stakes in their operating companies. Accordingly, the state is the majority shareholder in:   

  • Hidroelectrica SA, which owns and operates 259 hydro generating stations;
  • SN Nuclearelectrica SA, which owns and operates the Cernavoda nuclear generating station (two operational units, the first was commissioned in 1996 and the second in 2007);
  • Complexul Energetic Oltenia SA, which owns and operates Turceni, Rovinari, Craiova and Isalnita lignite-fired generating stations;
  • Termoelectrica Deva SA, which owns and operates the Mintia coal-fired generating station; and
  • Electrocentrale Bucureşti SA, which owns and operates the Elcen Bucureşti gas-fired generating station.

2.1.2 The plans to privatise the conventional generation sector have so far not succeeded. The coal-fired generating stations are reliant on government support but coal generation is politically supported to bolster employment in areas of the country that depend on the mining industry.

2.1.3 However, various projects designed to upgrade old conventional generating stations have been implemented successfully. The upgrades were implemented by obtaining financing from the state budget, contracting international loans guaranteed by the Romanian state or loans granted by international financing institutions. These are usually carried out by awarding the construction contracts through public tender to private entities.

2.1.4 The upgrade of old generating stations brings with it the requirement for higher levels of compliance with the EU environmental requirements and the extension of the operational lifespan of the generating stations by approximately 15 years. For example, in 2005 Hidroelectrica SA began the EUR 350m upgrade of five hydro generating stations located within the Slatina-Dunare area (Ipotesti, Draganesti, Frunzaru, Rusanesti and Izbiceni). By 2009, seven out of 20 hydropower units located within those five generating stations were upgraded and works are ongoing. The technological upgrade works were awarded through public auction to Voith-Siemens Hydro Power Generation and VA-Tech Escher Wyss consortium. Following the entire upgrade process the installed capacity for each generating station is expected to increase by 4MW.

Energy Mix 

2.1.5 Electricity generation in Romania is primarily from thermal generating stations (12,244MW installed capacity of coal, natural gas and oil) with the balance of production from hydro generating stations (6,563MW installed capacity) and from one nuclear power plant (Cernavoda NPP) with a total installed capacity of 1,413MW.3 The thermal plants are predominantly lignite-fired, although there are some gas-fired and oilfired power plants as well.

2.1.6 According to ANRE (see further on ANRE at paragraph 3.1.2 below) in 2013, power generation based on resource type within the national power system was divided as follows: hydro 28.3%; nuclear 20.6%; wind 7.1%; solid 29%; liquid 0.2% and gas 14.7%.4

2.1.7 In 2014, the current renewables installed capacity in Romania benefiting from green certificates is comprised of wind energy (over 3GW), solar energy (over 1.2GW), biomass and biogas (approximately 101MW) and hydro power (approximately 578MW).5

2.1.8 According to the Energy Strategy for Romania for 2011-2035, Romania intends to expand its nuclear generation capacities. Nuclearelectrica SA intended to begin construction of the two nuclear units of Cernavoda NPP in 2010. However, Nuclearelectrica SA is still seeking joint-venture partners to build units 3 and 4 of Cernavoda NPP (with 720MW of installed capacity each) and construction has been postponed. Currently, the two existing nuclear reactors provide almost 20% of the national electricity demand and the new units 3 and 4 are expected to double the production capacity. In November 2013 a Memorandum of Understanding was signed between the Romanian Energy Department and the Chinese National Energy Authority concerning the involvement of China in the finalisation of units 3 and 4. Also on 24 July 2014, Candu Energy Inc. and China Nuclear Power Engineering Company Ltd signed a binding and exclusive cooperation agreement.6 On 27 August 2014, Nuclearelectrica SA initiated the investors’ selection procedure for the completion of the units 3 and 4.7

2.1.9 Romania has significant potential for renewables generation, especially wind and hydro. The government estimates that investment in the renewables sector will reach EUR 1,800m by 2015.8 According to a study by Transelectrica SA, 4GWh of wind energy is expected to be integrated into the grid system by 2020.

2.1.10 Further, the Romanian government committed to the EU in 2007 to privatise the majority of its hydro generating stations. Hidroelectrica, which owns these plants now, was required to sell off 162 of its micro hydro generating stations. The privatisation process began in 2005 but stopped in 2008. However, the privatisation process was expected to restart in September 2014 when Hidroelectrica was to offer to sell 27 micro hydro generating stations grouped in 17 corporate stocks of assets by way of open auction.9

2.1.11 According to the Energy Strategy for Romania for 2011-2035, a new pumped storage hydro generating station is expected to be constructed in the Cluj County, on the Somes river (Tarnita-Lapustesti generating station). The construction of the 1GW generating station is envisaged to be completed between 2019-2021 and the value of the investment is approximately EUR 1bn.10

2.1.12 The upgrade and refurbishment program of the hydro generating stations started in 2000 and is expected to continue to 2020. According to the draft Energy Strategy for Romania for 2007-2020 updated for the period 2011-2020 over 2.3GW is to be refurbished by 2020.

2.2 Transmission

Structure of transmission sector

2.2.1 Transelectrica SA is both OPCOM and TSO. The TSO is responsible for the maintenance and development of the grid infrastructure, as well as electricity exchange with Central and Eastern European countries. Third parties may access the transmission grid provided that the connection is technically and economically feasible and the security of the national energy system is not endangered. The actual connection works are contracted by way of a regulated grid connection agreement. Only a very small part of the connection tariff is regulated, the remainder is for costs incurred by the TSO for the required electrical works involved in the construction of the connection installations.

2.2.2 According to the TSO’s Development Plan for 2014-202311, if production of wind electricity exceeds 3GW in the Dobrogea region, upgrades to the electricity grid will be necessary. In order to ensure the growth of the exchange capacity with Serbia and Western Europe and to evacuate the electricity from the wind power plants and hydropower plants from Portile de Fier –Resita (Western Romania), upgrades to the transmission grid will also be necessary in that region (Portile de Fier-Resita-Timisoara-Arad). Another development plan is the upgrade of the electricity transmission grid by reinforcing the 400kV line between the North-East and North-West of the national electricity system.

Cross border 

2.2.3 Romania has interconnection lines with all its neighbouring countries: Moldova, Ukraine (100MW), Hungary (450MW), Serbia (250MW) (still in the conceptual phase, although it was proposed years ago), and Bulgaria (200MW).12

2.2.4 ANRE’s official report13 indicates that in 2013, Romania imported approximately 450GWh and exported a total of 2,466GWh.

2.3 Distribution

Structure of distribution sector 

2.3.1 Unlike the generation and transmission sectors, the distribution sector has been partially privatised by investors taking shares in the distribution companies. Currently, there are eight distribution companies:   

  1. CEZ Distribute SA;
  2. ENEL Distributie Banat SA;
  3. ENEL Distributie Dobrogea SA;
  4. E.ON Moldova Distributie SA;
  5. ENEL Distributie Muntenia SUD SA;
  6. FDEE Electrica Distributie Muntenia Nord SA;
  7. FDEE Electrica Distributie Transilvania Sud SA; and
  8. FDEE Electrica Distributie Transilvania Nord SA.

2.3.2 Electrica SA (owner of the three companies listed at paragraph 2.3.1(vi) to (viii) above) holds the largest market share (39.27%) according to the ANRE official report14 and was majority state owned by the Ministry of Economy. In June 2014 Electrica SA was listed on the Bucharest and London stock markets through an initial public offering. After this process the shareholding structure is as follows: Ministry of Economy 48.58%, other legal entities 41.41% and individual investors 9.81%.15

2.3.3 Five out of Romania’s eight distribution companies were privatised between 2005 and 2007. Electrica Dobrogea, Electrica Banat (both privatised in April 2005) and Electrica Muntenia Sud (privatised in June 2008) are owned by ENEL.16 Electrica Moldova is owned by E-ON (since April 2005); and Electrica Oltenia is owned by CEZ (since April 2005).

2.3.4 Access by third parties to the distribution grid is governed in a way similar to access to the transmission system, as described in paragraph 2.2.1 above.

2.4 Supply

2.4.1 The electricity retail market was officially liberalised on 1 July 2007. Currently, there are 189 licensed suppliers registered with ANRE. The electricity market was completely liberalised for non-household customers starting on 1 January 2014 but the regulated tariffs will still be available until 31 December 2017 for household customers.

2.4.2 According to the Electricity and Gas Law, the following categories of customers are eligible for the regulated tariffs:   

  • end customers who have not exercised their option to choose an electricity supplier; and
  • household customers and non-household customers with a maximum of 50 employees and an annual turnover / asset value not exceeding EUR 10m.

2.4.3 Regulated tariffs apply to supply provided by suppliers of last resort. Suppliers of last resort are suppliers appointed by ANRE every year to provide electricity supply services at regulated tariffs to household and small non-household consumers who have not exercised their right to choose an electricity supplier.

2.5 Energy trading

2.5.1 The electricity market participants are:   

  • generators;
  • Transelectrica SA (both as the TSO and OPCOM);
  • distributors;
  • suppliers;
  • any legal or natural person who is free to purchase electricity from a supplier of its choice (Eligible Consumers); and
  • a consumer who, for technical, economical or regulatory considerations, cannot choose its supplier or a consumer who is an Eligible Consumer, but does not exercise the right to choose a supplier (Captive Consumers).

2.5.2 The wholesale electricity market consists of the sub-markets specified below:

Bilateral contracts market 

2.5.3 Under the Electricity and Gas Law17 electricity must be traded in a public and transparent manner, through a tender on a public trading platform operated by OPCOM. Thus the generators of electricity and the suppliers (traders) of electricity cannot enter into bilateral PPAs negotiated outside the trading platform. All negotiated PPAs concluded before the Electricity and Gas Law came into force remain valid.

2.5.4 On the current OPCOM platform generators and suppliers may enter into two types of agreements: closed PPAs and open PPAs.

2.5.5 Closed PPAs (“contracte bilaterale de energie electrica”) have fixed quantities and prices, which cannot be amended following completion of the PPA. The offer to sell must include the following mandatory terms:   

  • defined quantity of electricity;
  • duration of delivery (start date and end date, minimum term of one month);
  • daily profile of the delivery (high/low load, banded delivery);
  • minimum price requested (lei/MW); and
  • form of the PPA proposed by the initiator of the offer.

2.5.6 In order to ensure that the parties do not amend the mandatory elements of the offer, the closed PPA explicitly excluded ability of the parties to amend the PPA terms after its signature.

2.5.7 Open PPAs (“contracte bilaterale încheiate prin negociere continuă”) allow for ongoing negotiations and their standard terms, as set by OPCOM, include:   

  • hourly medium power per contract - 1MW (i.e. the quantity of energy contracted by the parties for each hour has to the multiple of 1MW);
  • duration of delivery - one week/month/trimester/year (start date and end date must be clearly defined);
  • daily profile of the delivery (high/low load, band delivery) with hourly intervals clearly defined;
  • number of hours during which the electricity is to be delivered; and
  • mandatory conclusion of a standard sale and purchase agreement provided by OPCOM.

2.5.8 With an open PPA, the selling party must first make a public offer. The selling offer is submitted on the online electricity trading platform managed by OPCOM. OPCOM organises online auction sessions by which it allows interested participants to negotiate. During this negotiation phase offers may be modified, withdrawn or annulled depending on the participant’s own bidding strategy or on the market’s evolution. At the end of negotiations, an open PPA is concluded at the negotiated price and verified by OPCOM for conformity with the standard version.

2.5.9 Both open PPAs and closed PPAs are made by way of tenders on the public tender platform operated by OPCOM. The main difference between the two trading options is that within the public tender for closed PPAs there is no negotiation phase.

2.5.10 This system for trading of electricity through the OPCOM platform was available before 19 July 2012, the date when the Electricity and Gas Law entered into force but it was optional.

2.5.11 The mandatory trading system has been criticised as not offering enough flexibility. As a result, on 16 May 2014, a new “over the counter” type electricity trading platform became operational, i.e. the double negotiated bilateral contracts market (CMBC).18 This new platform allows the seller to define the sale-purchase elements in line with its own needs (including taking into account its financing conditions, as appropriate), as detailed in paragraphs 2.5.12 to 2.5.15 below.

Double negotiated bilateral contracts (CMBC)

2.5.12 The registration of participants is voluntary and is performed at their written request, upon the execution of the participation agreement. Similarly, a participant may withdraw from this market at any time, on a written notice of the relevant participant.

2.5.13 Each participant must establish and maintain on the trading platform its list of eligible partners (Eligibility List), established separately for the sale/purchase operations and for each product. The Eligibility List of each participant will include at least four other participants, with whom such participant agreed the sale/purchase and the Eligibility List of each participant is published on OPCOM’s website.

2.5.14 The participants trade electricity based on bilateral agreements, following the template of the standard EFET contract. Under extraordinary circumstances, for a transient period of time of 6 months as of the closure of the first transaction on this market, the contracts agreed by the market participants may be of a type other than EFET, however, such contracts must be published on OPCOM’s website.

2.5.15 The contract regulates all aspects of the electricity sale/purchase, except for the delivery profile, the price and the delivery term.

Day Ahead Market (DAM)

2.5.16 In addition to bilateral contracts, participants in the wholesale electricity market also have the opportunity to take part in the short term physical electricity market, organised one day before the day of dispatch. The DAM is also organised and operated by OPCOM.

2.5.17 Participation on the DAM is restricted to registered participants and transactions on the DAM are concluded each trading day for the day ahead. Offers are subsequently validated based on market clearing price.

2.5.18 The Commercial Code for the Electricity Wholesale Market defines the parameters of the DAM. These include defining that:   

  • every calendar day is a trading day (Trading Day);
  • the day on which a transaction is closed, by way of physical delivery of electricity to the National Electricity System, is a delivery day (Delivery Day);
  • each Delivery Day is made up of 24 units, starting at midnight on each respective day (Trading Intervals); and
  • 11:00 on the Trading Day prior to the Delivery Day is the closing hour (DAM Closing Hour).

2.5.19 DAM participants may submit offers up to seven days prior to the Delivery Day until the DAM Closing Hour. Participants may only submit one ‘buy’ offer and one ‘sell’ offer for the national trading zone for each Trading Interval. The offer must contain the prices at which the participant is willing to buy and/or sell the electricity and offers must not exceed the MWh volume limits, as established by OPCOM (currently 99.999MWh).

2.5.20 OPCOM notifies the DAM participants regarding the acceptance or withdrawal of their offers. Such notifications are issued on every dispatch interval for the respective Delivery Day, the first dispatch interval starting at midnight on the Delivery Day. Transactions must be confirmed no later than 00:00 on the Trading Day.

2.5.21 Participation on the DAM is voluntary. According to the Synthesis Annual Report regarding the results of the Centralised Markets Operated by OPCOM, in 2013, 68.95% of the market participated on the DAM.19 OPCOM’s report also shows that the volume of electricity traded on the DAM has grown by 52.51% compared to 2012.

The Intra-Day Market (IDM)

2.5.22 Participation on the IDM is voluntary and open for all licensed participants (i.e. generators, traders and grid operators) based on a participation agreement executed with OPCOM. On the IDM, the electricity is traded in hourly intervals of the delivery day.

2.5.23 According to the Synthesis Annual Report regarding the results of the Centralised Markets Operated by OPCOM, in 2013, 24.41% of the market participated on the IDM.

The Balancing Market (BM)

2.5.24 On the BM, the TSO purchases and sells electricity from market participants with dispatchable units/consumption points (i.e. units/consumption points where the electricity output/consumption may be modified on TSO’s request for the purpose of settling deviations from the scheduled values for generation and consumption of electricity, respectively).

2.5.25 The specific regulations regarding the participation in and operation of the BM are drafted by the TSO and endorsed by ANRE. Together with the Commercial Code of the Electricity Wholesale Market, these BM regulations aim to ensure flexibility and stability within the national energy system and find solutions to solve network restrictions in the national energy system.

2.5.26 The TSO is responsible for registering participants in the BM, the verification of offers and the calculation of quantities necessary for transactions on the BM. All licence-holders that own dispatchable units and/or loads must be participants on the BM.

2.5.27 Dispatchable units are defined as power plants with an installed capacity; (i) in excess of 10MWh for hydro units; (ii) in excess of 20MWh for cogeneration units; and (iii) in excess of 5MWh for wind and solar units and dispatchable loads are defined as a load where the consumption of energy (i.e. the quantity of energy) can be modified at the TSO’s request.20

2.5.28 The BM begins after the approval of the physical notifications of the delivery day and ends at the end of the delivery day. All participants are under an obligation to make daily offers for any dispatchable interval of any Delivery Day. Offers can be made one week before the Delivery Day but in any case no later than 17:00 on the Trading Day before the Delivery Day. The TSO is required to confirm the offer no later than 18:30 on the Trading Day. Transactions on the BM are closed when the TSO accepts (wholly or in part) the offers made by the participants.

Ancillary Services Market (ASM)

2.5.29 On the ASM, the TSO purchases technological (or ancillary) system services from electricity generators under a procedure regulated by ANRE. The types of ancillary services purchased include secondary reserves, slow tertiary reserves from conventional and cogeneration sources and fast tertiary reserves.

EEX 

2.5.30 Romania auctions green gas emission allowances. In April 2013, EEX admitted SSIF Vienna Investment Trust SA, Bucharest, as a new participant on the spot market (Spot Market) for emission allowances, and as the first Romanian trading member of EEX.

2.5.31 Romania resumed trading of green gas emission allowances on 13 July 2012 after almost one year’s suspension by the Kyoto Protocol Compliance Committee for failing to meet the eligibility criteria.

3. Regulation

3.1 Authorities

3.1.1 The Ministry of Economy, in accordance with the Electricity and Gas Law sets the national energy strategy and the national policy with respect to electricity. It is also responsible for ensuring its implementation, by promoting new legislation to regulate the energy sector, commissioning studies to establish priorities regarding strategic investments in the sector, acting as the contracting authority for the granting of concessions and other initiatives.

3.1.2 ANRE was established in 2007 and is the independent regulatory authority for the electricity sector. Initially, ANRE was co-ordinated by the Romanian executive, but following the European Commission’s criticism regarding the independence of ANRE, responsibility for ANRE was transferred to the parliament, and its functional, decisional and organisational independence has been codified by Government Emergency Ordinance no 33/2007. As such the management of ANRE and responsibility for day-to-day activities is appointed by parliament and is funded directly by revenues generated from fees payable for the receipt of various authorisations.

3.1.3 The objectives of ANRE are to create and implement an appropriate regulatory system to ensure effective operation of the power sector in terms of efficiency, competition, transparency and consumer protection. As part of this ANRE:   

  • issues mandatory regulations for all participants in the electricity and gas sectors;
  • grants, amends, suspends or revokes authorisations and licences for operators in the electricity and gas sectors;
  • creates and approves calculation methodologies necessary to establish regulated prices and tariffs;
  • sets up regulated prices and tariffs for transmission, distribution and system services;
  • controls the compliance of the electricity and gas producers and suppliers with the regulations in force from time to time, with approved tariffs and prices, and applies penalties for infringements where necessary;
  • notifies the competent ministry and the Competition Council regarding any alleged abuse of a dominant position on the power market and breaches of competition rules; and
  • monitors the power market in regard to its efficiency, transparency and competition.

3.1.4 In relation to competition, the Competition Council is the autonomous administrative body responsible for promoting competition and consumers’ interests. It is responsible for monitoring behaviour of market players, approving mergers that result in significant market concentration and state aid issues.

3.1.5 OPCOM, the electricity market operator, is responsible for providing an organised, viable and efficient framework for commercial trade on the wholesale electricity market while ensuring transparency and conditions of non–discrimination. It is also the operator of the green certificates market. OPCOM is involved in drafting and reviewing regulations that are related to its activity. Such regulations have to be approved by ANRE prior to coming into effect.

3.2 Key legislation

3.2.1 The Electricity and Gas Law (that repealed and replaced the former law governing the electricity sector in Romania, being Electricity Law no 13/2007) sets out the principles and the legal framework governing the electricity sector, such as attributions of ANRE, licences and authorisations, transmission, distribution, trading and gradual liberalisation of electricity prices. The Electricity and Gas Law was implemented by way of secondary legislation (regulations and government decisions).

3.2.2 There are two grid codes: one regulating the transmission grid and the other regulating the distribution grid. In addition, there is a Code of the Electricity Wholesale Market, a government decision regulating authorisations and licences in the electricity sector and a government decision regulating connection to the grid.

3.3 Regulatory framework

3.3.1 Both foreign and Romanian entities can apply for electricity authorisations and licences. As a general principle, however, foreign legal entities should be established in Romania throughout the validity period of the authorisation or licence, unless they hold a similar license in an EU jurisdiction which is recognised in Romania by way of a reciprocity convention with the respective EU member state.

3.3.2 Applicants who have had bankruptcy or insolvency proceedings made against them or those from whom a licence or authorisation was withdrawn within five years prior to the date of application are not eligible for authorisation.

3.3.3 ANRE is entitled to withdraw authorisations or licences in cases of:   

  • the disqualification, incapacity or bankruptcy of the authorisation/licence holder;
  • the termination of the concession (for example, where the land is in the public domain of the state or local authority) or lease of the energy capacity; or
  • the sale of the facility by the holder of the licence/authorisation.

3.3.4 The rights granted to holders under their authorisations and licences may not be transferred (in whole or in part) without ANRE’s consent. Any transfer without such consent is null and void represents a violation of the conditions of the authorisation or licence and attracts administrative sanctions.

3.3.5 Licensee must notify ANRE of any changes to the conditions existing at the issue date of the relevant authorisation or licence such as:   

  • a change in the holder’s shareholding structure or assets held;
  • any merger or demerger;
  • a change in the holder’s sector of activity; and
  • a change in the technical characteristics of the electricity capacity.

3.3.6 This notification must be made within 30 days of the occurrence of the change. Upon receiving an application for approval, ANRE has discretion to decide to revoke the authorisation or licence already issued and grant a new authorisation/licence or modify the conditions attaching to the relevant authorisation or licence.

3.4 Support schemes

3.4.1 According to the Romanian support mechanism, electricity, regardless of the source, is sold at the market price as detailed in paragraph 2.5 above.

3.4.2 In addition to the market price, generators of electricity from renewable sources (other than hydro generating stations where the installed capacity exceeds 10MWh) receive green certificates from the TSO (variable depending on the sources of energy) for each MWh of green energy delivered onto the national grid.

3.4.3 The green certificates may be traded separately from the electricity on the green certificates markets operated by OPCOM (i.e. green certificates spot market and/or green certificates bilateral contracts market) in a transparent and non-discriminatory manner between the generators that have the obligation to buy green certificates and the renewable energy generators. Conventional generators of electricity for supply either to end customers connected by direct lines, or for their own use (other than technological) and electricity suppliers supplying to end customers or consuming electricity themselves have an obligation to buy green certificates. This is a similar restriction to the restriction on trading electricity by individually negotiated power purchase agreements outside OPCOM’s markets. New regulations for the operation of the green certificates centralised markets came into force at the start of 2014. Traders of electricity (i.e. companies that only trade on the wholesale market but do not supply electricity to end customers) are no longer allowed to trade green certificates.

3.4.4 The minimum and maximum price levels for green certificates are established by Law no 220/2008 for the promotion of renewable energy (Law 220). From 2011, green certificates prices have been annually indexed by ANRE in accordance with the annual average inflation index for the European Union Euro area for the previous year. ANRE established that the indexed trading price of a green certificate in 2014 shall range between a minimum of EUR 29,280 and a maximum of EUR 59,647. The value of the green certificates is calculated in national currency (RON) at the exchange rate established by the National Bank of Romania for the last month of the previous year.

3.4.5 Romania amended Law 220 by Government Emergency Ordinance no 57/2013 published in the Romanian Official Gazette no 335 dated 7 June 2013 which entered into force on 1 July 2013 with amendments made by parliamentary law 23/2014 (Law 23), dated 14 March 2014.

3.4.6 As of 1 January 2014, the Romanian government also adopted Government Decision no 994/2013 for the reduction in the number of green certificates.

3.4.7 Law 23 abolished the legal mandatory quotas of renewable electricity that can benefit of green certificates available from 2014 until 2020 (i.e. from 15% to 20%) and gave ANRE the freedom to propose a mandatory quota each year depending on the developments on the market and the impact of the support mechanism on the end customers. Therefore, from 2014 ANRE estimates and informs the Romanian government (by 30 June of the respective year) of the annual mandatory quota for the forthcoming year. For the 2015 to 2020 period, such annual mandatory quota must be approved by Government Decision within 60 days’ from its notification by ANRE. The quota for 2014 is 11.1%.

3.4.8 Under Law 23, ANRE must publish every December the annual estimated mandatory quota for acquisition of green certificates for the following year, based on the information regarding the estimated electricity produced from renewable sources and the estimated consumption for the following year. The mandatory estimated quota for acquisition of green certificates for 2014 is 0.237 green certificates per MWh.

3.4.9 The quota of 0.237 was estimated based on: a final consumption of electricity of 45,902GWh and a total of 17,591,558 green certificates issued in 2014.

3.4.10 ANRE may until 1 March of each year revise its estimated annual mandatory quota for the previous year based on actual quantities of electricity from renewable sources and final consumption of electricity from the previous year.

3.4.11 Energy traders and generators (if applicable) are required to acquire a set number of green certificates each year. This is based on the value of the estimated mandatory quota for acquisition of green certificates established by ANRE for the respective year multiplied by the total number of MWh:   

  • acquired by traders for their own consumption or for re-sale to end customers;
  • delivered by generators to end customers connected to their generating stations by direct lines.
  • used by generators for their own consumption (excluding technological consumption); and

3.4.12 The value of green certificates is passed on by the suppliers to end customers. This value depends on ANRE’s estimated annual mandatory quota portion applying to the number of MWh supplied to such customers and the price of green certificates acquired by the respective supplier on the OPCOM markets.

3.4.13 Failure by the suppliers and the producers (if applicable) to comply with (i) the above mentioned regulations, (ii) payment of the EUR 119,293 for each acquired green certificate (i.e. failure to comply with their annual mandatory quota) or (iii) ANRE regulations regarding the promotion of energy from renewable sources, is penalised by a fine between RON 10,000 (EUR 2,270) and RON 100,000 (EUR 22,700).

3.5 Upcoming regulatory changes

3.5.1 Following the publication of the European Commission Guidelines on state aid for environmental protection and energy 2014 to 2020 (EU Guidelines)which deal with aid to energy intensive consumers and criteria for such aid to be declared compatible with EU rules, the Romanian government adopted Government Decision no 495/2014 which came into force on 1 October 2014 exempting energy intensive consumers from the obligation to cover part of the costs of green certificates as follows:   

  1. The exemption can only be granted if the undertaking belongs to the sectors listed in Annex 3 of the EU Guidelines (e.g. mining of hard coal, of other non-ferrous metal ores and of chemical and fertiliser minerals, manufacture of oils and fat, copper and aluminium production, etc.).
  2. The validity period for the exemption is for a maximum of ten years and its total maximum value of the aid support mechanism for renewables cannot exceed 85% of the maximum value. The estimated value of the support mechanism is RON 750m and about 300 entities are expected to benefit from the exemption.
  3. The scope of the exemption depends on the electro-intensity of the economic operators, as follows: (a) 85% in the case of an electro-intensity over 20%, i.e. the exempted customers will pay only 15% of the green certificates as per the mandatory quota; (b) 60% in the case of an electro-intensity of 5%-10%, i.e. the exempted customers will pay only 40% of the green certificates as per the mandatory quota; and (c) 40% in the case of an electro-intensity of 10%-20%, i.e. the exempted customers will pay only 60% of the green certificates as per the mandatory quota.

4. Country Statistics

4.1.1 Romania has approximately 8,800km of overhead transmission lines, 310,127km of distribution lines, 76 transmission substations and 1,296 distribution substations.21

4.1.2 In terms of country statistics, the internal electricity consumption was 52.36TWh in 2012 and 49.69TWh in 2013. Romania exported 1.15TWh of its generated capacity in 2012 and 2.47TWh in 2013.22

4.1.3 Transactions on the DAM covered approximately 25.1% of the internal consumption January 2013, and 37.42% in January 2014, whilst transactions on the BM in January 2013 covered approximately 6.8% of the internal consumption and in January 2014 approximately 8.4% of the internal consumption.23

4.1.4 ANRE stated that the electricity wholesale market had the following participants in January 2014: one TSO, one electricity market operator, 21 electricity generators (owners of dispatchable generation units using conventional resources), 43 electricity generators (owners of dispatchable wind generation units), 30 electricity generators (owners of dispatchable solar generation units), one electricity generator (owner of dispatchable hydro generation units), one electricity generator (owner of dispatchable nuclear generation units), eight distribution operators, five last resort electricity suppliers (i.e. the only licensed supplier in the area), 22 electricity suppliers operating exclusively on the wholesale market and 47 electricity suppliers operating on both the wholesale market and retail market.24