COMMISSION FOR ELECTRICITY AND GAS REGULATION ANNUAL REPORT 2011
TABLE OF CONTENTS 1. FOREWORD................................................................... 3 2. THE MAIN LEGISLATIVE DEVELOPMENTS................................................. 5 3. THE ELECTRICITY MARKET.......................................................... 7 3.1. Regulation................................................ 8 3.1.1. Power generation.......................................... 8 3.1.1.1. Permits for new generation facilities.......................... 8 3.1.1.2. Offshore wind power generation........................... 8 A. Domain concessions for offshore wind power...................... 8 B. Green certificates and guarantees of origin....................... 9 C. Support measures in favour of green electricity..................... 10 3.1.2. Electricity supply..........................................11 3.1.2.1. Customers connected to the federal transmission system.................. 11 3.1.2.2. Price caps................................. 11 3.1.2.3. Indexation parameters............................. 12 3.1.3. Regulation of transmission and distribution..............................13 3.1.3.1. Unbundling and certification of the TSO and corporate governance............... 13 A. Unbundling of the TSO............................ 13 B. TSO certification.............................. 13 C. Corporate governance............................. 14 3.1.3.2. Technical operation.............................. 14 A. Connection and access............................ 14 B. Balancing and ancillary services......................... 14 C. Rules on grid security and reliability........................ 16 3.1.3.3. Network tariffs for connection and access....................... 17 A. Transmission system............................. 17 B. Distribution networks............................. 19 3.1.4. Cross-border issues.........................................25 3.1.4.1. Analysing access to cross-border infrastructure..................... 25 3.1.4.2. Cooperation (including capacity allocation procedures and congestion management).......... 27 3.1.5. Compliance............................................28 3.2. Competition................................................29 3.2.1. Monitoring wholesale and retail prices................................29 3.2.2. Monitoring market transparency and openness.............................33 3.2.2.1. Electrical power demand............................ 33 3.2.2.2. Wholesale generation market share......................... 34 3.2.2.3. Energy exchange............................... 35 3.2.2.4. REMIT................................. 37 3.2.3. Investigations with a view to promoting effective competition......................38 3.3. Consumer protection............................................39 3.4. Security of supply.............................................40 3.4.1. Monitoring the balance between supply and demand..........................40 3.4.2. Monitoring TSO investment plans...................................41 A. The development plan............................. 41 B. Main future developments of the transmission grid.................... 42 3.4.3. Monitoring investments in generation capacity.............................42 3.4.4. Operational security of the grid....................................42 3.4.5. Investments in cross-border interconnection capacity..........................43 3.4.6. Expected future supply and demand..................................44 4. THE NATURAL GAS MARKET........................................................ 45 4.1. Regulation............................................... 46 4.1.1. Natural gas supplies........................................ 46 4.1.1.1. Natural gas supply permits............................ 46 4.1.1.2. Price caps................................. 48 4.1.1.3. Indexation parameters............................. 48
4.1.2. Regulation of transmission and distribution.............................. 48 4.1.2.1. Unbundling and certification of system operators and corporate governance............ 48 A. Unbundling of system operators......................... 48 B. System operator certification.......................... 48 C. Corporate governance............................. 49 4.1.2.2. Technical operation.............................. 49 A. Natural gas transmission permits......................... 49 B. The balancing model............................. 49 C. The rules on network security and reliability..................... 49 D. Code of conduct.............................. 50 4.1.2.3. Network and LNG tariffs for connection and access.................... 51 A. Transmission system............................. 51 B. Distribution networks............................. 52 4.1.3. Cross-border issues........................................ 56 4.1.3.1. Analysing access to the cross-border infrastructure.................... 56 4.1.3.2. Cooperation................................. 57 4.1.4. Compliance............................................ 57 4.2. Competition.............................................. 57 4.2.1. Monitoring wholesale and retail prices................................57 4.2.2. Monitoring market transparency and openness.............................59 4.3. Consumer protection............................................59 4.4. Security of supply........................................... 59 4.4.1. Monitoring the balance between supply and demand..........................59 A. Natural gas demand............................. 59 B. Natural gas supplies............................. 61 4.4.2. Monitoring TSO investment plans...................................62 4.4.3. Expected future demand, available reserves and additional capacity...................63 5. THE CREG................................................................... 67 5.1. Management Board and staff....................................... 68 5.2. General Council..............................................72 5.3. Policy programme and comparative report on the objectives and achievements of the CREG............76 5.4. Cooperation with other bodies....................................... 76 5.4.1. CREG and the European Commission..................................76 5.4.2. CREG within ACER..........................................76 5.4.3. CREG within CEER and ERGEG.....................................78 5.4.4. Madrid Forum............................................81 5.4.5. Florence Forum...........................................81 5.4.6. London Forum............................................82 5.4.7. CREG and the regional regulators...................................84 5.4.8. CREG and the competition authorities.................................85 5.4.9. Handling questions and complaints..................................86 5.4.10. Participation of CREG members as speakers at seminars........................86 5.5. CREG finances.............................................. 88 5.5.1. Federal contribution........................................ 88 A. The federal contribution for gas............................ 88 B. The federal contribution for electricity.......................... 88 5.5.2. The funds..............................................89 A. CREG Fund................................... 89 B. Social Fund for Energy................................ 89 C. Denuclearisation Fund............................... 89 D. Greenhouse Gases Fund............................... 89 E. Protected Customers Fund.............................. 90 F. Fund for fl at-rate reductions for heating using natural gas and electricity................ 90 G. Fund to offset the loss of revenue suffered by the municipalities.................. 90 5.5.3. Accounts for 2011..........................................91 5.5.4. Auditor s report on the financial year closed on 31 December 2011.....................94 5.6. List of acts of the CREG during the year 2011.................................95
LIST OF TABLES 1. Net supplies to customers connected to the federal transmission grid for the years 2008 to 2011............11 2. (Unweighted) average price of imbalances during the period 2007-2011.......................16 3. Trend in the cost of Elia grid tariffs borne by MWh taken up............................18 4. Tariffs for the use of the distribution network for the years 2008 to 2011, excluding VAT................21 5. Average import and export capacity and average nomination per year.......................26 6. Annual revenues from capacities offered for auction...............................26 7. Congestion rents on coupled electricity exchanges, per type of player.......................27 8. Summary of the benefits granted to households via the free kwh system......................32 9. Wholesale market shares in electricity generation capacity............................34 10. Wholesale market shares in power generated..................................35 11. Energy exchanged and average price on the Intraday exchange..........................37 12. Breakdown of exchanges on the Day-Ahead hub.................................37 13. Breakdown of exchanges on the Intraday hub..................................37 14. Power demand and peak capacity demand in Belgium during the period 2007-2010..................40 15. Breakdown of the installed capacity per type of power plant connected to Elia s grid as at 31 December 2011......41 16. Breakdown of power generated per type of primary energy in 2011.........................41 17. Companies operating in the supply of natural gas on the Belgian market in 2011...................47 18. Tariffs for the use of the distribution network for the years 2008 to 2011, excluding VAT................54 19. Breakdown per sector of the Belgian demand for natural gas between 2001 and 2011................59 20. Directorates and staff of the CREG as at 31 December 2011............................71 21. Members of the General Council as at 31 December 2011.............................75 22. Overview of presentations given by the CREG in 2011...............................87 23. Shortfalls recorded in the funds in 2011.....................................88 24. Receipts and Payments Account as at 31 December 2011............................92 25. Balance sheet as at 31 December 2011.....................................93 LIST OF FIGURES 1. (Unweighted) average price of imbalances and Belpex DAM price during the period 2007-2011............16 2. Average composition of distribution network cost in Flanders in 2011 for a Dc customer...............24 3. Average composition of distribution network cost in Wallonia in 2011 for a Dc customer...............24 4. Average composition of distribution network cost in Brussels in 2011 for a Dc customer...............24 5. Availability and use of interconnection capacity from 2008 to 2011.........................26 6. Trend in electricity prices 2007-2011 per region for a Dc customer.........................30 7. Trend in household customer indexes.....................................31 8. Trend in electricity price 2007-2011 per region for an lc1 customer........................31 9. Average consumption on a monthly basis in the Elia control area from 2008 to 2010.................34 10. Average prices on the Belpex, APX, EPEX FR and EPEX GE exchanges between 2007 and 2011............36 11. Average monthly market resilience of Belpex from 2008 to 2011..........................36 12. Average composition of the distribution system costs in Flanders in 2011 for a T2 customer..............56 13. Average composition of the distribution system costs in Wallonia in 2011 for a T2 customer..............56 14. Average composition of the distribution system costs in Brussels in 2001 for a T2 customer..............56 15. Trend in natural gas price 2007-2011 per region for a T2 customer.........................58 16. Trend in natural gas price 2007-2011 per region for a T4 customer.........................58 17. Development of natural gas consumption per sector during the 1990-2011 period (1990 = 100), corrected for climate variations........................................60 18. Breakdown per sector of the Belgian demand for H-gas and L-gas in 2010 and 2011.................60 19. Breakdown of supply per entry zone in 2011...................................61 20. Composition of the aggregated supply portfolio of suppliers operating in Belgium in 2011................61 21. Composition of the aggregated supply portfolio for the Belgian market 2000-2011 (shares in %)............... 62 22. Market share of supply companies on the transmission grid in 2011........................62 23. Forecast demand for natural gas in Belgium until 2020..............................63
COMMISSION FOR ELECTRICITY AND GAS REGULATION ANNUAL REPORT 2011
1. Foreword The electricity and natural gas markets underwent a number of significant changes over the course of 2011 at both Belgian and European level. The new European legislation, laid down in the third Energy package, was transposed into Belgian law after a long and complex debate that began in the Federal Government in January and ended in the Parliament at the end of December. As it did in 2010, the CREG aimed to assist the Belgian authorities by offering them its view and putting forward texts that faithfully abide by and apply the provisions of the third package, while at the same time incorporating the comments made by the Council of State. The meticulous transposition of European law into our national legislation is vitally important. In May 2011, the Constitutional Court issued a ruling confirming that the CREG alone has the power to determine the methodology to be used to set the distribution tariffs. This provided confirmation from one of the highest courts in the land of the view upheld by the CREG for almost three years. The draft tariff decrees which should have been adopted as they were proposed by the CREG in 2008 have been amended in spite of European legislation and improperly adopted, incidentally resulting in tariff increases for electricity and gas consumers. This ruling highlights the risks linked to the imperfect transposition of the third package: in addition to the penalty which could again be imposed on Belgium by the European authorities in the event of the incorrect transposition of directives, further insecurity and instability would be created on the Belgian markets. A situation like this would be unfavourable for consumers, but also for electricity and gas companies. Last year was also marked by a major event: the Fukushima nuclear disaster. There is no doubt that the political authorities now view nuclear power differently. In Belgium, whereas in October 2009 some people were considering extending the lifespan of the nuclear power plants, it has been decided, in the agreement reached by the new government, to maintain the law on the withdrawal from the nuclear sector adopted in 2003 and to carry out stress tests that will determine over the next few months whether the nuclear reactors can continue to function and under what conditions. Leaving the nuclear sector raises the question, amongst others, of security of supply and future electricity prices. The CREG undertook a number of major studies on this subject and passed them on to the authorities in order to help them to attain the objectives set for the transition to other forms of energy as efficiently as possible. Fuel prices continued to rise in 2011, prompting an increase in the price of electricity and gas which are indexed on these fuels. The CREG carried out detailed analyses in this field which revealed that the indexation parameters used to set the price of the energy component in the bills sent to most household customers and SMEs are no longer representative and should be adapted by the electricity and gas suppliers, who are responsible for this. The CREG studies on the price components were used to determine the nature and importance of the elements that make up the final bill per category of consumer, per supplier and per distribution zone. Electricity and gas prices in Belgium were also compared with those in neighbouring countries. 3
1. Foreword Here again, the contributions made by the CREG helped clarify the situation for the authorities, enabling them to consider adopting measures relating to maximum prices. The CREG also made major contributions to the debate on the nuclear rent. Thanks to its studies, the existence of this rent was not only confirmed, but its amount was determined at a significant level. All this work resulted in the upward revision of the distribution contribution applied to this rent and the agreement of the Government, which is planning to place part of the power generated by depreciated nuclear power plants at the disposal of the electricity market. With its decisions approving the electricity and gas transmission tariffs proposed by Elia and Fluxys respectively for the period from 2012 to 2015, the CREG gives these two companies, the market and consumers visibility and stability with regard to tariffs for the next four years. A number of other studies, opinions and proposals were drawn up by the CREG over the course of 2011. It is worth mentioning in particular the publications on the cost of offshore wind power, the functioning of the Belgian wholesale electricity market, the calculation of the access capacity to the gas transmission system and the impact of photovoltaic solar panels on the price of electricity. Finally, the CREG responded in detail to requests for opinions from members of parliament concerning legislative proposals that they had filed with a view to extending the protection provided for domestic consumers and SMEs. Through these practical examples, the CREG demonstrates the crucial role that it plays within the liberalised electricity and gas markets, not only by acting as regulator, but also in the advice it is able to give to the public authorities. The European authorities have understood this and have included in the third package the reinforcement of the independence and the powers of the national regulators, proof of the essential role played by these bodies in improving the functioning of the electricity and gas markets. Readers of this report wishing to find out more about the measures taken and the results obtained by the CREG in 2011 in fulfilling each of its assignments are invited to consult the ad hoc report which is published on its website. In this way, the CREG intends to comply with the new legal provision concerning the publication, in total transparency, of the way in which it attained the objectives set out in its policy programme for the past year. François Possemiers Chairman of the Management Board April 2012 4
2. The main legislative developments 5
2. The main legislative developments In terms of legislation, 2011 was the year of the EU s third energy package. The regulations making up this package came into force on 3 March 2011 and the directives 1 were to be transposed in the different member states by the same date. In Belgium, this transposition process fell so far behind schedule that the CREG was in some cases forced to apply the provisions of the directives having a direct effect. This primarily involved establishing the methodology used to set tariffs, which is discussed in detail in paragraph 3.1.3.3. below. In 2010, the CREG carried out a series of studies proposing to modify the gas and electricity acts 2 in accordance with the new European regulations 3. However, the contents of these studies were only reflected to a very slight degree in the draft transposition bill which the government subsequently adopted and submitted to Parliament as a bill on 2 September 2011. Backed up by the critical opinion of the Council of State on this draft, the Management Board published an updated version of its previous studies in October 2011 4. Material for these updated studies, a copy of which was sent to the minister in charge and to the Commission on Economy of the Chamber, was supplied by regular exchanges of views with the regulators in other EU member states and the explanations provided by the representatives of the European Commission in various discussion forums. In these studies, proposed texts were put forward amongst other things to: - reinforce the independence and powers of the CREG, amongst other things with regard to the conditions governing connection and access to the networks (in terms of both tariffs and technical aspects); - establish a legal footing for the cooperation with the new European agency ACER 5 ; - continue the separation of activities linked to the production and supply of energy and network activities (unbundling) and work out a procedure for the certification of system operators by the regulator; - make use of the possibility provided for in the directives for member states to plan specific regulations for closed distribution networks in national legislation, in this case in the form of particular regulations for closed industrial networks. Having examined the bill, the Commission on Economy of the Chamber organised a series of hearings to which the CREG was also invited. The CREG took this opportunity to set out its objections to the bill and again draw attention to the risks inherent in transposing European directives incorrectly. In addition to a(nother) conviction by the EU Court of Justice, the Belgian legislator also risks creating an additional source of legal uncertainty and instability on the Belgian markets, whereas in fact its stated aim was precisely to overcome the existing instability. Finally, the bill was approved, without any major amendments, on 15 December 2011 in the Chamber of Representatives and on 22 December 2011 in the Senate, and was not published until 2012 6. The general date of entry into force is set for 21 January 2012. It should be pointed out that, generally speaking, the law does not settle the fate of the existing implementing decrees, even when these decrees do not derive a sufficient legal foundation from the amended law. Yet the CREG had underlined the importance of this issue in its studies. The legal basis of the existing implementing decrees can equally be threatened because the provision in question in the Gas Act or the Electricity Act is wrongly not brought into line with the third package (in other words, when a necessary amendment has not been made). This is the case in particular with the technical regulations 7 and the code of conduct 8. 1 Directive 2009/73/EC of the European Parliament and of the Council of 13 July 2009 on joint rules for the natural gas internal market, repealing Directive 2003/55/EC and Directive 200972/EC of the European Parliament and of the Council of 13 July 2009 on joint rules for the electricity internal market, repealing Directive 2003/54/EC. 2 Act of 29 April 1999 on the organisation of the electricity market and the act of 12 April 1965 on the transmission of gaseous and other substances by pipeline.. 3 2010 Annual Report, paragraph 2.7, p. 13. 4 Studies (F)111006-CDC-1111 and (F)111006-FCF-1112. 5 Agency for the Cooperation of Energy Regulators 6 Act of 8 January 2012 amending the act of 29 April 1999 on the organisation of the electricity market and the act of 12 April 1965 on the transmission of gaseous and other substances by pipeline (Belgian Official Journal of 11 January 2012). 7 Royal Decree of 19 December 2002 establishing the technical regulations for the management of the electricity transmission system and access to this system. 8 Royal Decree of 23 December 2010 on the code of conduct on access to the natural gas transmission system, the natural gas storage facility and the LNG facility and amending the Royal Decree of 12 June 2001 on the general terms and conditions for the supply of gas and the conditions for granting natural gas supply permits (Belgian Official Journal of 5 January 2011). 6
3. The electricity market
3. The electricity market 3.1. Regulation 3.1.1. Power generation 3.1.1.1. Permits for new generation facilities The regulatory framework The construction of new power generation facilities is subject to the prior granting of an individual permit issued by the Minister for Energy at the proposal of the CREG. The Royal Decree of 11 October 2000 on the granting of individual permits covering the establishment of power generation facilities was amended, following an opinion from the Management Board 9, by the Royal Decree of 5 August 2011 10 in order to transpose Article 33 of Directive 2009/31/EC 11. Applications submitted to the CREG In 2011 the Management Board published four proposals 12 relating to the granting of a generating permit. These involved applications from Greensky for the construction of a wind farm along the E40 near Hannut, Nest-Energie for the construction of two CCGT plants on the Evergem site, Eneco for the construction of two CCGT plants and one peak unit on the Beringen site and Electrabel for the conversion of an existing plant in Amercoeur into a CCGT plant. As at 31 December 2011, one application for an individual generating permit was still being processed by the CREG. In 2011, the Minister granted permits for the extension of a wind farm in Mettet/Fosses-la-Ville by Electricité du Bois du Prince 13 and for the construction of a cogeneration plant in Langerbrugge (Ghent) by Stora Enso Langerbrugge 14, for which the Management Board had issued proposals in 2010 15, as well as for the projects of Nest-Energie 16, Eneco 17, Greensky 18 and Electrabel 19, bringing the additional authorised generation capacity in 2011 to around 2,350 MW. In addition to the applications for new generating permits, the Management Board received three notifications of a change in control from Zandvliet Power, Dils Energie and T-Power. The Management Board has already sent a proposal 20 concerning the notification from Zandvliet Power to the Ministry for Energy. The notifications from Dils Energie and T-Power were still being processed as at 31 December 2011. 3.1.1.2. Offshore wind power generation A. Domain concessions for offshore wind power The regulatory framework The procedure relating to the granting of the domain concession for the most northerly zone, which is situated above the Blighbank zone and which was suspended following a communication published in the Belgian Official Journal of 26 February 2010, was reopened following the publication of the Royal Decree of 3 February modifying the coordinates of the zone intended for the installation of wind turbines in the North Sea 21. Further to the Council of State ruling of 3 February 2011 22 suspending the Ministerial Decree of 24 March 2010 granting the joint venture SEASTAR a domain concession for the construction and operation of a wind farm, the minister withdrew this decree (and therefore the domain concession granted to the joint venture SEASTAR) in a Ministerial Decree of 6 April 2011 23. In the decree announcing the withdrawal, the minister expressly asks the CREG to put forward a new opinion on the applications submitted by the joint venture SEASTAR, the joint venture Electrabel-Jan De Nul, Evelop Belgium and Electrastar, in accordance with Articles 9 and 10 of the Royal Decree of 20 December 2000, as they were in force at the time it was to render its original opinion. 8 9 The Management Board issued a positive opinion on this matter by letter. 10 Royal Decree of 5 August 2011 amending the Royal Decree of 11 October 2000 on the granting of individual permits covering the establishment of electricity generating facilities (Belgian Offi cial Journal of 22 August 2011). 11 Directive 2009/31/EC of the European Parliament and of the Council of 23 April 2009 on the geological storage of carbon dioxide, amending Directive 85/337/EEC of the Council, Directives 2000/60/EC, 2001/80/EC, 2004/35/EC, 2006/12/EC and Regulation (EC) No 1013/2006 of the European Parliament and of the Council. 12 Proposals (E)110421-CDC-1059, (E)110519-CDC-1067, (E)110526-CDC-1068 and (E)110616-CDC-1075. 13 Ministerial Decree of 14 February 2011 (Belgian Official Journal of 21 February 2011). 14 Ministerial Decree of 18 February 2011 (Belgian Official Journal of 28 February 2011). 15 Proposals (E)101202-CDC-1023 and (E)101125-CDC-1021. 16 Ministerial Decree of 1 August 2011 (Belgian Official Journal of 9 August 2011). 17 Ministerial Decree of 10 August 2011 (Belgian Official Journal of 23 August 2011). 18 Ministerial Decree of 30 August 2011 (Belgian Official Journal of 8 September 2011). 19 Ministerial Decree of 7 September 2011 (Belgian Official Journal of 16 September 2011). 20 Proposal (E)110908-CDC-1102. 21 Royal Decree of 3 February 2011 amending the Royal Decree of 20 December 2000 on the conditions and procedure for granting domain concessions for the construction and operation of electricity generation facilities using water, currents or wind, in marine areas over which Belgium can exercise its jurisdiction in accordance with the international law of the sea (Belgian Offi cial Journal of 17 February 2011). 22 Council of State, decree No 210.981 23 Ministerial Decree of 6 April 2011 withdrawing the Ministerial Decree of 24 March 2010 granting to the joint venture SEASTAR a domain concession for the construction and operation of electricity generation facilities using wind in marine areas located between the Bank zonder Naam and Blighbank (Belgian Official Journal of 22 April 2011).
3. The electricity market Applications submitted to the CREG On 18 October 2011, the CREG received a request from the Energy Authority to express an opinion on the application from Northwind (previously known as Eldepasco) to modify the domain concession granted by Ministerial Decree of 15 May 2006 and amended by Ministerial Decree of 24 March 2010. Northwind is planning to correct the longitudinal coordinate of a border point of the concession zone and to move the transformation platform. Having analysed the dossier, the Management Board notes that the correction of the longitudinal coordinate of the border point involves rectifying a material error and that moving the transformation platform constitutes a marginal modification which does not impact on the basic characteristics of the project and which is even beneficial for the quality of the project. Consequently, the Management Board issued a positive opinion 24 on the modifications proposed by Northwind. On 13 July 2011, the CREG received a request for an opinion from the Energy Administration on the applications from Electrastar, the joint venture Mermaid and Nortwester 2 with a view to obtaining a domain concession above the Blighbank. In its opinion 25, the Management Board covered the six criteria for granting concessions and commented on these. With regard to the quality of the projects from a technical point of view, the Management Board wonders whether the project proposed by one of the applicants fulfils this granting criterion in technical terms as the project could use the zone more efficiently. B. Green certificates and guarantees of origin In March 2009, the Management Board approved a proposal for a royal decree aimed at introducing a federal system of guarantees of origin for electricity generated by offshore wind farms 26. In May 2010, the Management Board approved a proposal for a royal decree clarifying the method used to measure and calculate net green electricity generation 27. In 2011, the Minister for Energy asked the CREG to provide another global proposal replacing the two previous proposals. The CREG issued a new proposal 28 on 17 February 2011. In addition to introducing a system of guarantees of origin and adapting the method used to calculate green electricity, this proposal also included the abolition of the obligation to purchase green certificates for electricity generated using onshore renewable energy sources and the possibility of reviewing the minimum prices on the basis of the terms and conditions of connection and profitability assessments. Finally, in 2011 the Management Board also took a decision 29 on the application from Belwind to grant green certificates for the offshore wind turbines installed on the Blighbank. This is the final principle decision for the first phase of the Belwind project setting, amongst other things, the date as of which the wind turbine satisfies the conditions for obtaining green certificates. The installed capacity in offshore wind turbines remained unchanged in 2011, amounting to a total of 195.9 MW or 30.9 MW for the six C-Power wind turbines that had already been constructed in 2009 and 165 MW for the 55 wind turbines constructed by Belwind in 2010. Finally, in 2011 the two offshore wind farms together generated a net quantity of 706,466 MWh, for which green certificates worth 75,591,860 were granted between February 2011 and January 2012. Finally, in December 2011 the Management Board drafted a proposal 30 on the calculation of the surcharge intended to offset the net real costs borne by the TSO and resulting from the obligation to buy and sell green certificates in 2012. On the basis of the limited gross quantity of energy included in the 2012-2015 tariffs proposal from the TSO, the Management Board proposed setting the surcharge at 1.080/MWh for 2012. This proposed amount was 38 % higher than the amount of the surcharge for 2011. The main reason for this increase may be attributed to the gradual rise over the course of 2012 in the installed capacity of the C- Power farm from 30.9 MW to 251.4 MW. This amount was laid down in the Ministerial Decree of 23 December 2011 31. 24 Opinion (A)111027-CDC-1119. 25 Opinion (A)111201-CDC-1128. 26 2009 Annual Report, paragraph 2.4.5.2., p. 18. 27 2010 Annual Report., paragraph 3.2.1. C, p. 34. 28 Proposal (C)110217-CDC-1042.. 29 Decision (B)110113-CDC-1033. 30 Proposal (C)111208-CDC-1130. 31 Ministerial Decree of 23 December 2011 setting the surcharge to be applied by the system operator to offset the real net cost resulting from the obligation to buy and sell green certificates in 2012 (Belgian Official Journal of 28 December 2011). 9
3. The electricity market C. Support measures in favour of green electricity Study on the cost analysis and the calculation of the nonprofitable portion for offshore wind farms in Belgium In this study 32, which was carried out further to the study 33 of the various support mechanisms for green electricity in Belgium, the Management Board examines the federal minimum price of offshore wind energy. In order to promote the generation of renewable energy at sea, a system of granting green certificates has been set up at federal level. The Royal Decree of 16 July 2002 34 set the following minimum purchase prices for offshore wind energy: 107/MWh for electricity generated by plants covered by a domain concession for generation resulting from the first 216 MW installed; 90/MWh for generation resulting from an installed capacity in excess of the first 216 MW. The average value of green certificates amounts to 102.24/MWh for facilities generating 300 MW. The assumptions and calculation method used for the minimum prices given above are as yet unknown to the Management Board. Neither the Minister for Energy nor the operators of offshore facilities can provide an answer to this. That is why the Management Board has attempted to reconstruct this average minimum purchase price. This was done on the basis of international studies and input on the costs and revenues of current Belgian offshore operators. On the basis of these assumptions, the non-profitable portion amounts to 102.11/MWh, which represents a return of 12 % on equity. The current offshore facilities are established using project financing. This form of financing entails that the same risks (i.e. cash flow generation) are covered by the banks, the shareholders and the insurers. This type of risk cover, but from three individual angles, gives rise to costs that may compensate the same risk several times. One solution is to opt in favour of a different form of financing (balancesheet financing or the use of a fund fed by the tax on nuclear power) or a reduction in the total investment amount so as to lessen the risk borne by shareholders and banks. This is possible by concentrating the electricity infrastructure (submarine cables and electrical installations) with a single regulated system operator for all offshore facilities. The Management Board also questions the current lifespan of offshore facilities. If the facilities remain operational for over 20 years thanks to regular maintenance, the operator will receive additional revenue leading to a lower minimum price or non-profitable portion. The Royal Decree of 20 December 2000 35 also stipulates a maximum lifespan of 30 years. Finally, the Management Board illustrates the possible impact of a number of scenarios on the non-profitable portion. If the seven concession holders together establish an optimal basic electrical infrastructure (which would be transferred to a regulated market participant after 20 years), the non-profitable portion would be 96.99/MWh. A 5 % fall in the CAPEX and a lower OPEX after 16 years brings the non-profitable portion down to 91.21/MWh. If the dismantling provision is abolished and the concession is extended to 30 years, the non-profitable portion would become 83.68/MWh. Study on the impact of photovoltaic solar panels on the electricity price in Belgium. In the discussion on the cost of subsidising solar panels, the argument that solar panels bring down price peaks on the electricity market is put forward. This study 36 assesses the average fall in the price of the Belpex DAM further to the installation of solar panels. The calculations are carried out with an installed capacity of 800 MW. In addition, the impact for Belgian consumers is estimated. A comparison is then made with the subsidising of another technology, i.e. a combined cycle gas turbine (CCGT). This study shows that 19-24 % of the cost of subsidising solar panels could be recovered by the consumer by means of a reduction in the electricity price. With a CCGT plant, 609 % of the subsidy costs could be recovered by the consumer, or a recovery rate 25 to 32 times higher than that for solar panels. It should be noted that the value of this study is mainly due to the relative impact of solar panels compared with a CCGT plant, and not so much to the absolute value of the cost recovery level. 10 32 Study (F)111027-CDC-1061. 33 Study (F)100520-CDC-966. 34 Royal Decree of 16 July 2002 establishing the mechanisms aimed at promoting electricity generated using renewable energy sources. 35 Royal Decree of 20 December 2000 on the conditions and procedure for granting domain concessions for the construction and operation of electricity generation facilities using water, currents or wind in marine areas over which Belgium has jurisdiction in accordance with the international law of the sea. 36 Study (F)110506-CDC-1062.
3. The electricity market 3.1.2. Electricity supply 3.1.2.1. Customers connected to the federal transmission system Table 1 shows the market shares of Electrabel and the other suppliers as regards net electricity supplies 37 to major industrial customers connected to the federal transmission system (grids with voltage levels higher than 70 kv). According to an initial estimate, Electrabel s market share amounted to approximately 90.2 % in 2011, up approximately 1.5 % compared with 2010. The total volume of energy offtake by end customers from the transmission system fell from 13,741 GWh in 2010 to 12,957.6 GWh in 2011. No access points on the transmission grid changed supplier in 2011. Over the course of the year 2011, the Minister issued permits to Essent Belgium, Enovos Luxembourg, E.ON Trading, EGL France & Benelux, GDF Suez Trading, Total Gas and Power Limited, Société Européene de Gestion de l Energie, ArcelorMittal Energy and Eneco België 39. As at 31 December 2011, twenty suppliers held a federal permit to supply electricity to customers connected to the transmission system: Anode, ArcelorMittal Energy, Duferco Energia, EGL France & Benelux, Electrabel, Eneco België, Enovos Luxembourg, E.ON Belgium, E.ON Energy Sales, E.ON Energy Trading, Essent Belgium, Essent Energy Trading, GDF Suez Trading, Nuon Belgium, Pfalzwerke, RWE Energy Belgium, RWE Supply & Trading, Société Européenne de Gestion de l Energie, SPE and Total Gas & Power. Table 1: Net supplies to customers connected to the federal transmission grid for the years 2008 to 2011 Suppliers Consumption sites 1 January 2011 Consumption sites 31 December 2011 Power offtake in 2008 (GWh) Power offtake in 2009 (GWh) Power offtake in 2010 (GWh) Power offtake in 2011 (GWh) Electrabel S.A. 70 69 11,470.3 (84.0 %) 2,183.3 (16.0 %) 10,806.5 (87.6 %) 1,526.3 (12.4 %) 12,162.7 (88.7 %) 1,551.2 (11.3 %) 11,693.1 (90.2 %) 1,264.5 (9.8 %) Other suppliers 15 16 Total 81* 81* 13,653.6 12,332.8 13,714.0 12,957.6 * Four consumption sites were supplied by two suppliers simultaneously Source : ELIA (provisional data, January 2012) The federal supply permits for electricity are granted by the Minister for Energy at the proposal of the CREG for a five-year period. In 2011, the Management Board received permit applications from EGL France & Benelux, Total Gas and Power Limited (which was rejected), GDF Suez Trading (formerly Gaselys), Total Gas and Power Limited (which was accepted), the Société Européenne de Gestion de l Energie, Eneco België, ArcelorMittal Energy and Energie I&V België. The Management Board therefore issued a total of seven proposals 38 over the course of the year 2011. One proposal concerns the application from E.ON Energy Trading, which was submitted at the end of 2010. As at 31 December 2011, one application for a federal supply permit was still being examined by the CREG. 3.1.2.2. Price caps A system of maximum prices has been implemented in Belgium for two categories of end customers: protected end customers and unprotected end customers whose contract has been terminated by their supplier. The DSOs ensure supplies to unprotected end customers whose supply contract has been terminated by their supplier at the maximum price set as follows: energy price + transmission tariff + distribution tariff + margin 40. The DSO uses the tariff data from those suppliers with a minimum share of 3 % operating in its distribution zone. All calculations include the suppliers who deliver to at least 90 % of household access points. 37 These figures do not take into account the energy supplied directly by local generation or customers located in the Grand Duchy of Luxembourg. 38 Proposals (E)110203-CDC-1038 (E.ON Energy Trading), (E)110407-CDC-1057 (EGL France & Benelux), (E)110714-CDC-1090 (GDF Suez Trading), (E)110811-CDC-1094 (Total Gas and Power Limited), (E)110811-CDC-1095 (Société Européenne de Gestion de l Energie), (E)111020-CDC-1115 (Eneco België) and (E)111020-CDC-1117 (ArcelorMittal Energy). 39 Ministerial Decrees of 1 February 2011 on Essent Belgium (Belgian Official Journal of 11 February 2011), 1 February 2011 on Enovos Luxembourg (Belgian Offi cial Journal of 11 February 2011), 18 March 2011 on E.ON Energy Trading, 8 June 2011 on EGL France & Benelux, 25 August 2011 on GDF Suez Trading, 15 September 2011 on Total Gas and Power Limited (Belgian Offi cial Journal of 23 January 2011), 15 September 2011 on the Société Européenne de Gestion de l Energie, 28 November 2011 on ArcelorMittal Energy (Belgian Offi cial Journal of 23 January 2012) and 1 December 2011 on Eneco België (Belgian Official Journal of 23 January 2012). 40 Ministerial Decrees of 1 June 2004 (electricity) and 15 February 2005 (natural gas). 11
3. The electricity market Each DSO with unprotected end customers whose contracts have been terminated sends the CREG the tariffs applicable to these customers for a six-monthly period by the end of June and the end of December at the latest. These tariffs are set using a standardised calculation method established by the CREG in 2010 on the basis of decisions taken by the Management Board 41 in application of the Ministerial Decrees of 1 June 2004 and 15 February 2005. This standardisation of the calculation method became necessary due to the huge disparity encountered until 2010 in the benchmark tariffs and calculation methods used by the DSOs. The DSO and/or the supplier are also charged with supplying protected end customers at a maximum price set by the CREG which is valid for a period of six months 42. The supplier is compensated for the obligation to supply at regular tariffs. The DSO s margin is an amount which is added to the sum of the energy, transmission and distribution components, if this sum is lower than the average of the price announced for a category of similar customers of suppliers in the distribution zone of the DSO. In this case, the margin is equal to the difference between this average and the sum of the first three parts of the price capping mechanism. In all other cases the margin is zero. Study on the draft legal text for the safety net against unjustified fluctuations in energy prices In this study 43, conducted in May 2011, the Management Board sets out its comments on the Draft legal text for the safety net against unjustified fluctuations in energy prices sent to it by the minister in a letter dated 8 April 2011. On 18 March 2011, the Council of Ministers decided to approve the introduction of the safety net regulation mechanism on the Belgian energy market. This means that in future energy suppliers will have to submit to monitoring by the CREG of adjustments to energy prices and modifications of price formulas for households and SMEs with a view to protecting end customers from unreasonable price rises. The aforementioned announcement by the Council of Ministers clearly refers to the safety net regulation mechanism used in the Netherlands. However, a first reading of the draft text reveals that there are fundamental differences between the Dutch interpretation and the interpretation proposed in the draft Belgian legislation. In the Netherlands, all the new tariffs are grouped together under the same denominator and no distinction is made between indexations and other price rises. Also in the Netherlands, an increase in a tariff is not examined, but each new tariff is dealt with individually as it is highly likely that certain contracts containing old tariffs continue to exist for a certain period of time. Only the national regulator is competent for all regulation of the safety net and an ex ante approach is adopted (rather than an ex post approach, as in the Belgian draft text). Finally, the Energiekamer in the Netherlands not only monitors the proper application of the formulas but also checks that the content and composition of the tariffs proposed are complete. These five points mean that should the draft legal text be approved, it would be very difficult to compare the Belgian mechanism with the Dutch system and reference to the latter would no longer be relevant. In conclusion, the Management Board asserts that the draft text offers suppliers a guarantee that no price rise will be refused, that the draft text pointlessly involves the National Bank of Belgium and the Institute of Registered Auditors in the regulation of the safety net, and that the draft text would do better to apply the ex ante principle and assess the amount of the tariffs rather than the increase in tariffs. Finally, the draft text merely creates the illusion that the CREG monitors tariffs and is more of a safety net for suppliers than for consumers. 3.1.2.3. Indexation parameters The Management Board calculates the electricity price indexation parameters (Nc and Ne) with a view to checking and comparing them with the other parameters used by electricity suppliers. It has stopped publishing these parameters since April 2011, as it felt that the elements needed to calculate these parameters no longer adequately reflected the real costs. Further to its study 44 on the quality of the Nc parameter, the Management Board decided to analyse the representative nature of the parameters used by Ebem. This study 45 comprises two parts: the first part describes the parameters used and the tariff formulas proposed by Ebem to its customers. The second part describes the analyses undertaken in order to assess the representative nature of the END parameter and the tariff formulas. These analyses led to the following conclusions. First of all, the analysis of Ebem s current supply portfolio shows that the END parameter applied by the supplier in its tariff formula is representative of the supply: it guarantees both an excellent correlation with the energy cost borne by Ebem and transparency with regard to the contractual terms and conditions of purchase. Moreover, the comparison made 12 41 Decisions (B)100429-CDC-964 (electricity) and (B)100429-CDC-965 (natural gas). 42 Ministerial Decrees of 30 March 2007. 43 Study (F)110506-CDC-1064. 44 Study (F)100909-CDC-948. 45 Study (F)110303-CDC-1047.
3. The electricity market between the costs (supply costs and general costs) and tariff receipts (determined in accordance with the Ebem tariff formulas based on the END and Ne parameters) made it possible to assess the margin produced and shows that the tariff method currently applied by Ebem does not generate an excessive profit and that the structure of the tariff formula is closely linked to the structure of the costs borne by the supplier. 3.1.3. Regulation of transmission and distribution 3.1.3.1. Unbundling and certification of the TSO and corporate governance A. Unbundling of the TSO The new rules on the unbundling of TSOs are one of the main pillars of the third European energy package. Given that the rules on unbundling contained in the previous European gas and electricity directives did not give rise to the effective unbundling of TSOs, new, more elaborate rules have been laid down in the third European energy package for the actual separation of grid activities on the one hand and generation and supply activities on the other (unbundling) with a view to preventing the risk of conflicts of interest and discriminatory behaviour in terms of grid operation, promoting the investments made in grid infrastructures in a non-discriminatory manner and ensuring fair access to the grid for newcomers and market transparency. To this end, a number of unbundling models have been provided for in the directives in the third package: firstly, the ownership unbundling model, as a starting point, and, as departures therefrom, the so-called ISO system (Independent System Operator) and the ITO system (Independent Transmission Operator), with the possibility of a specific exemption, the so-called ITO+ system. When transposing the provisions of this directive, the Belgian legislator chose, both for the management of the electricity transmission system and for that of natural gas, to adopt ownership unbundling as the only unbundling model in Belgian legislation. As far as Elia and Fluxys are concerned, there was de facto no other option than the ownership unbundling model at the time the law was transposed. In 2010, the CREG had already made an initial series of proposals for the transposition of the provisions in the directive on unbundling and certification by putting forward draft texts amending the current Electricity Act 46. In 2011, the CREG published an updated version of these studies 47 further, amongst other things, to the opinion from the Council of State on the draft bill. When participating in the hearings in Parliament organised by the Commission on Economy of the Chamber in the autumn of 2011, the CREG also made a series of comments and criticisms concerning the proposed articles of law on the subject of unbundling and the certification of TSOs included in the bill submitted for discussion. See section 2 of this report on this topic. B. TSO certification The new unbundling rules in the third European energy package also include the requirement for TSOs to be certified by the national regulator. These new rules stipulate, amongst other things, that the companies that own a transmission grid must be certified by the national regulatory authority as complying with the unbundling requirements before they can be appointed as TSOs by the member states. This new certification system also involves permanent monitoring by the national regulator to ensure that the unbundling requirements continue to be observed by the TSOs. This is a major new assignment for the CREG in its capacity as national regulatory authority, which is also covered by the aforementioned transposition legislation of 8 January 2012. With regard to this new certification system, in September 2011 the European Commission published a working paper containing the practical guidelines on the way in which it is to deal with notifications of draft decisions on certification which are submitted to it for an opinion by the national regulators 48. At European level, the CREG participated actively in various joint CEER-EC working groups in 2011 with a view to discussing questions and problems raised in terms of the interpretation and practical application of the criteria and the certification procedures contained in the articles of the directive. In the autumn of 2011, at the initiative of the CREG, informal discussions had already been started with the current TSO, Elia, in preparation for the formal certification which will have to take place once the Belgian transposition legislation comes into force in 2012. 46 2010 Annual Report, paragraph 2.7, p. 13. 47 Studies (F)111006-CDC-1111 and (F)111006-CDC-1112. 48 Commission staff working paper on certification of Transmission System Operators of networks for electricity and natural gas in the European Union, 21 September 2011. 13
3. The electricity market C. Corporate governance The CREG examined and commented on the activities report from the Elia corporate governance committee for 2010 (monitoring the application of Articles 9 and 9ter of the Electricity Act and assessing its effectiveness with regard to the requirements of independence and impartiality of the TSO). In 2011, the Management Board issued binding opinions 49 on the appointment of an independent administrator to Elia and the renewal of the appointments of seven independent administrators within Elia. Moreover, in 2011 it also issued binding opinions 50 on the renewal of the mandate of Elia s two auditors. The report from the Compliance Officer describing the measures taken by Elia in 2010 to ensure that all discriminatory practices are ruled out and to provide an appropriate monitoring of the programme of commitments as laid out by Article 8, 2 of the Electricity Act, was examined by the Management Board, which did not have any observations to make on this matter. 3.1.3.2. Technical operation A. Connection and access As regards the Access Responsible Parties contracts and access contracts, the Management Board refused to approve two proposed modifications to the general terms and conditions of these contracts as they concerned questions covered in the 2012-2015 tariffs proposal which was still being examined by the Management Board when the decision was taken 51. Announcing a decision on these two proposals to modify the general terms and conditions of Access Responsible Party contracts and access contracts within the deadline set by law would have been to prejudge the assessment authority of the Management Board in the context of this tariffs proposal. Once the 2012-1015 tariffs proposal had been approved, Elia again submitted proposals to modify the general terms and conditions of these contracts at the end of December and they were approved by the Management Board in early January 2012 52 so as to enter into force on 1 January 2012. B. Balancing and ancillary services Reserve capacity Elia has to assess and determine the primary, secondary and tertiary reserve capacity that contributes towards ensuring the security, reliability and efficiency of the transmission grid in the control area. It has an obligation to submit its assessment method and the results obtained by this method to the CREG for approval. In May 2011, the Management Board approved the proposal put forward by Elia concerning the method used to assess the primary, secondary and tertiary reserve capacity and the result of applying this method for 2012 53. However, the Management Board did add a number of considerations to this decision concerning, amongst other things, the improvement of the new assessment method proposed, the need to gather other information to make better use of this method, the need for Elia to have volumes in line with the decisions taken by the CREG throughout the year, the need for Elia to have data on all intermittent generation in Belgium, including that injected into the networks of the DSOs, the international extension of the activation of certain reserves, the participation of the nuclear plants and industrial customers in the reserves and the need to monitor the quality of the adjustment in the zone further to the implementation of the new method of assessing the volumes needed. Bids and volumes for ancillary services offered by service providers On 19 April 2011, the Management Board received the Elia report on the bids for ancillary services for 2012. The ancillary services concerned include the primary, secondary and tertiary adjustment capacity, voltage adjustment (partially) and active losses in Elia s grid with a voltage of less than or equal to 70 kv. The other ancillary services will still be covered by multi-annual contracts in 2012. 14 49 Opinions (A)110224-CDC-1044 and (A)110630-CDC-1080 to 1086. 50 Opinions (A)110512-CDC-1065 and (A)110512-CDC-1066. 51 Decisions (B)11110-CDC-1125 and (B)111110-CDC-1126. 52 Decisions (B)120112-CDC-1135 and (B)120112-CDC-1136. 53 Decision (B)110519-CDC-1056.
3. The electricity market On the basis of this report, in October 2011 the Management Board expressed an own-initiative opinion 54 and sent it to the Minister for Energy and to Elia. In this opinion, the Management Board points out that the volumes offered for the primary adjustment capacity of the frequency, the adjustment capacity of the balance in the zone and the tertiary reserve are inadequate compared with the volumes approved in the decision referred to above taken in May 2011 55. A development of the method used to value the reservation of primary and secondary reserves is also proposed and applied. The Management Board mentions that it is not possible to state on the basis of the analyses that it conducted for the purpose of the opinion that the prices offered for the primary, secondary and tertiary reserves are blatantly unreasonable. It adds, however, that it will organise annual ex post monitoring in order to check that the new method does not lead to a drift in reservation prices. Moreover, should a move be made, as in 2009, towards a ministerial decree to determine the distribution of volumes and prices, the opinion puts forward a number of guidelines for the distribution of volumes and makes some suggestions on price determination. Finally, the Management Board notes that other developments are needed to promote the emergence in Belgium of a sufficiently liquid reserves market and suggests a number of avenues that could be followed in this area. Balancing The TSO is responsible for monitoring, maintaining and, if need be, re-establishing the balance between supply and demand for electrical power in the control area, amongst other things further to any individual imbalances caused by the various Access Responsible Parties. Elia has to submit a proposal for market operating rules intended to offset any 15-minute imbalances to the CREG for approval. In December 2011, the Management Board approved the proposal from Elia for 2012 56. The proposed mechanism came into force on 1 January 2012. Activated volumes and concentration 57 In 2011, activations to offset imbalances in the control area rose by 23.0 % compared with 2010 to reach 1,110 GWh. The share of the secondary reserves in these activations amounted to 67.3 % in 2011, compared with 76.0 % in 2010 and 95.2 % in 2009. This fall is due in particular to the fact that most of the increase in activations in 2011 must be attributed to incremental and decremental bids, which increased by 76.3 % compared with 2010. In 2011, the activation of reserves located abroad by the TSOs accounted for 2.6 % of Elia s activations to offset imbalances in the control area, compared with 1.6 % in 2010. In terms of volume, this represents an increase of 100 % compared with 2010. The HHI index relating to secondary and tertiary reserves on generating units amounted to 4,510 in 2011, compared with 3,750 in 2010 and 5,800 in 2009. Activations relating to these resources accounted for 97.3 % of the total energy activated in 2011 to offset imbalances in the control area, whereas they accounted for 97.9 % in 2010 and 99.0 % in 2009. The increase in the HHI index can be explained by the rise in the relative participation of Electrabel and the relative fall in the participation of other players, despite the entry onto the production reserves market of two new players, RWE and T-Power. Price of energy to offset imbalances The imbalance tariff is based on a two-price system taking into account the direction of the imbalance of the Access Responsible Party and the direction of the imbalance in the control area. The table below provides an overview of the trend in the tariff (unweighted) for positive imbalances (injection > offtake) and the average tariff (unweighted) for negative imbalances (injection < offtake) for the period from 2007 to 2011. 54 Opinion (A)111020-CDC-1116. 55 Decision (B)110519-CDC-1056. 56 Decision (B)111222-CDC-1132. 57 Source: Elia data. 15
3. The electricity market Table 2: (Unweighted) average price of imbalances during the period 2007-2011 /MWh 2007 2008 2009 2010 2011 Injection > offtake 22.00 43.31 19.86 27.76 29.22 Injection < offtake 48.67 78.06 44.25 57.25 62.70 Source : Elia data Figure 1 : (Unweighted) average price of imbalances and Belpex DAM price during the period 2007-2011 (in /MWh) 90 80 70 60 50 40 30 20 10 0 2007 2008 2009 2010 2011 Injection > offtake Injection < offtake Belpex Source : Elia and Belpex data Figure 1 above can be used to compare these average prices with the trend in average prices on the Belpex Day- Ahead market over the same period. It may be observed that in 2011, compared with 2010, the average tariffs for negative imbalances rose more quickly than the average price of the Belpex DAM, unlike the average tariffs for positive imbalances. C. Rules on grid security and reliability Over the course of 2011, the CREG took various initiatives concerning the security and reliability of the grid. Amongst other things, this involved contacts with Elia on power supplies during a black-out of the Tihange nuclear power plant. The CREG also asked Elia and Fluxys to analyse the interdependence risks between the electricity and gas transmission systems. In fact, the planned introduction of electrical compressors on the gas transmission network is likely to create interdependence between the gas and electricity transmission systems. The CREG therefore asked the gas and electricity TSOs to examine and avert this risk in a blackout situation. The CREG asked Elia to draw up a plan for the management of electricity shortages together with the competent authorities. This plan must make it possible to cope with foreseeable disruption of the generation or transmission of electricity. Elia informed the CREG of the progress of its work. Elia sent a new version of the reconstruction plan to the CREG for consultation on 8 December 2010. In its opinion 58, the Management Board notes an improvement in the structuring and the form of the documents which is likely to optimise the procedures implemented to deal with a crisis. The Management Board mentions a number of approaches for improving the organisation of the reconstruction plan. 16 58 Opinion (A)110526-CDC1071.